Pengrowth Energy (PGH) 40-F 2008 FY Annual report (Canada)

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 40-F

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

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

For the fiscal year ended: December 31, 2008       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	None
(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

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

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

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

copies to:

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

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

Title of each class	Name of each exchange on which registered
Trust Units	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      þ Audited annual financial statements

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

     There were 256,075,997 Trust Units, of no par value, outstanding as of December 31, 2008.

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

DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT

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

Appendix	Documents
A	Pengrowth Energy Trust Annual Information Form for the year ended December 31, 2008.
B	Management’s Discussion and Analysis.
C	Consolidated Financial Statements of Pengrowth Energy Trust, including Management’s Report to Unitholders, the Auditors’ Reports and note 24 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles.
D	Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”.
E	Pengrowth Energy Trust Code of Business Conduct and Ethics dated February 17, 2009.

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

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

Disclosure Controls and Procedures. The required disclosure is included in the section entitled “Disclosure Controls and Procedures” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2008, filed as part of this Annual Report on Form 40-F.

Management’s Annual Report on Internal Control Over Financial Reporting. The required disclosure is included in the section entitled “Internal Control Over Financial Reporting” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2008, filed as part of this Annual Report on Form 40-F.

Attestation Report of the Registered Public Accounting Firm. The required disclosure is included in the “Auditors’ Report” that accompanies the Registrant’s Consolidated Financial Statements for the fiscal year ended December 31, 2008, filed as part of this Annual Report on Form 40-F.

Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2008, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

None.

IDENTIFICATION OF THE AUDIT COMMITTEE

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

AUDIT COMMITTEE FINANCIAL EXPERT

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

ADDITIONAL DISCLOSURE

Certain disclosure regarding the corporate governance practices of the Registrant, including disclosure of the Registrant’s principal accountant fees and services, pre-approval policies and procedures, code of ethics and off-balance sheet arrangements, is included on pages 100, 100, 103 and 103, respectively, of the Annual Information Form contained in Appendix A. Disclosures regarding the Registrant’s contractual obligations is included on page 29 of Management’s Discussion and Analysis contained in Appendix B.

UNDERTAKING

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

CONSENT TO SERVICE OF PROCESS

Form F-X signed by the Registrant and its agent for service of process has been filed with the Commission together with Form F-10 (333-146928) in connection with its securities registered on such form.

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

SIGNATURES

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

Date:  March 24, 2009	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 ANNUAL INFORMATION FORM FOR THE YEAR
ENDED DECEMBER 31, 2008

PENGROWTH ENERGY TRUST

ANNUAL INFORMATION FORM

For the year ended December 31, 2008

March 24, 2009

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
CONVERSION	5
PRESENTATION OF OUR FINANCIAL INFORMATION	6
PRESENTATION OF OUR RESERVE INFORMATION	6
FORWARD-LOOKING STATEMENTS	6
PENGROWTH ENERGY TRUST	8
Introduction	8
The Trust	8
The Corporation	8
The Trust’s Subsidiaries	8
The Manager	9
Intercorporate Relationships	9
Business Strategy and Strengths	10
SIFT Legislation Considerations	11
GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST	12
Recent Developments	12
Historical Developments	14
Trends	17
PENGROWTH MANAGEMENT LIMITED	18
Business	18
Management Agreement	19
Bonus Pool	20
Management Agreement Second Term	20
Expiry of the Management Agreement	21
PENGROWTH – OPERATIONAL INFORMATION	22
Principal Properties	22
Light Oil Properties	23
Heavy Oil Properties	26
Conventional Gas Properties	27
Shallow Gas Properties	31
Offshore Gas Properties	32
Oil Sands Properties	33
Statement of Oil and Gas Reserves and Reserves Data	34
Additional Information Relating to Reserves Data	44
Future Development Costs	46
Finding, Development and Acquisition Costs	46
Future Development Capital	47
Other Oil and Gas Information	48
Forward Contracts	51
Additional Information Concerning Abandonment & Reclamation Costs	51
Forward contracts	51
Costs Incurred	51
Exploration and Development Activities	52
Production Estimates	52
Production History (Netback)	53
Replacement of Properties	53
Before Tax Net Asset Value (NAV) at December 31, 2008	54
TRUST UNITS	55
The Trust Indenture	55
The Trustee	55
Stock Exchange Listings	56
Ownership Restrictions	56
Redemption Right	56
Conversion Rights	56
Voting at Meetings of Unitholders	56

Voting at Meetings of Corporation	57
Termination of the Trust	57
Unitholder Limited Liability	57
THE ROYALTY INDENTURE	58
Royalty Units	58
The Royalty	58
The Trustee	59
EXCHANGEABLE SHARES	59
DISTRIBUTIONS	60
General	60
Historical Distributions	60
Restrictions on Distributions	61
CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS	65
Taxation of the Trust	65
Taxation of Unitholders Resident in Canada	66
Taxation of Unitholders who are Non-Residents of Canada	67
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS	68
Classification of Pengrowth Energy Trust as a Partnership	69
Possible Classification as a Corporation; PFIC Rules	70
Consequences of Possible PFIC Classification	70
Tax Consequences of Trust Unit Ownership	71
Tax Treatment of Trust Operations	72
Disposition of Trust Units	74
Disposition of Trust Units by Redemption	75
Uniformity of Trust Units	76
Tax-Exempt Organizations	76
Administrative Matters	76
Reportable Transactions	76
Foreign Partnership Reporting	77
INDUSTRY CONDITIONS	77
Government Regulation	77
Pricing and Marketing — Oil	77
Pricing and Marketing — Natural Gas	77
Pricing and Marketing — Natural Gas Liquids	78
Royalties	78
Environmental Regulation	80
Climate Change	80
RISK FACTORS	82
MARKET FOR SECURITIES	95
DIRECTORS AND OFFICERS	96
Directors and Officers of the Manager	96
Principal Holders of Shares of the Manager	96
Directors and Officers of the Corporation	97
Corporate Cease Trade Orders or Bankruptcies	98
Personal Bankruptcies	99
Penalties or Sanctions	99
AUDIT COMMITTEE	99
Principal Accountant Fees and Services	100
Pre-approval Policies and Procedures	100

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CONFLICTS OF INTEREST	100
LEGAL PROCEEDINGS	102
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	102
INTERESTS OF EXPERTS	102
AUDITORS, TRANSFER AGENT AND REGISTRAR	102
MATERIAL CONTRACTS	102
CODE OF ETHICS	103
OFF-BALANCE SHEET ARRANGEMENTS	103
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE	103
ADDITIONAL INFORMATION	104
Appendix A – Report on Reserves Data by Independent Qualified Reserves Evaluator on Form 51-101F2
Appendix B – Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3
Appendix C – Audit Committee Terms of Reference

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2008.

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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;

“Computershare” refers to Computershare Trust Company of Canada;

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

“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;

“Royalty Indenture” refers to the amended and restated royalty indenture of the Corporation, dated July 27, 2006;

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

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

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

“Trust” refers to Pengrowth Energy Trust;

“Trust Indenture” refers to the amended and restated trust indenture of the Trust, dated June 18, 2008;

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

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

Engineering

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

“Contingent Resources” are those quantities of petroleum estimated, on a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies

may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Contingent Resources do not constitute, and should not be confused with, reserves;

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

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

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

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

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

“GLJ Report” refers to the report prepared by GLJ, dated February 6, 2009 with an effective date of December 31, 2008;

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

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

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

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

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

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

“Reserve Life Index” refers to the number of years determined by dividing the Company Interest Total Proved plus Probable Reserves of a property by the 2009 Company Interest estimated Total Proved plus Probable

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production from such property. The reserves and the 2009 estimated production for such property come from the GLJ Report;

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

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

“Total Proved Plus Probable Reserves” 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, possible) to which they are assigned; and

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

Abbreviations

“API” refers to the American Petroleum Institute;

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

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

“bblpd” refers to barrels per day;

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

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

“bwpd” refers to barrels of water per day;

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

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

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

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

“MMBtu” refers to million British thermal units;

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

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

“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;

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

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

“Tax Act” refers to 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.

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CONVERSION

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

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

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 24 to our audited annual consolidated financial statements for the year ended December 31, 2008, 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

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, Possible Reserves and Contingent Resources, and to disclose reserves and production on a gross basis before deducting royalties. Probable Reserves and Possible Reserves are of a higher risk and are less likely to be accurately estimated or recovered than Proved Reserves. Contingent Resources are higher risk than Probable Reserves and Possible Reserves and are less likely to be accurately estimated or recovered than Probable Reserves or Possible Reserves. Because we are permitted to prepare this Annual Information Form in accordance with Canadian disclosure requirements, we have disclosed in this Annual Information Form reserves designated as Probable Reserves, Possible Reserves and Contingent Resources and have disclosed reserves and production on a gross basis before deducting royalties.

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. If this Annual Information Form was required to be prepared in accordance with U.S. disclosure requirements, the SEC’s guidelines would prohibit Probable Reserves, Possible Reserves and Contingent Resources from being disclosed. Moreover, in accordance with Canadian practice, we have determined and disclosed reserves and estimated future net cash flow therefrom using both forecast and constant prices and costs; for the constant prices and costs case, prices and costs in effect as of December 31, 2008 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 forecast 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 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 2009 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

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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.

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 acquisition, development and exploration activities. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; 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; counterparty risk; 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, 2008, 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, a net profits interest and other securities issued by Esprit Exploration Ltd. as well as other investments and to issue Trust Units to members of the public. The Corporation and Esprit directly and indirectly acquire, own and manage working interests and royalty interests in oil and natural gas properties. The Trust and the Corporation are presently managed by the Manager pursuant to a management agreement that expires June 30, 2009, following which the Corporation will be managed pursuant to an ordinary corporate governance structure and the Unitholders will be asked to consider and approve the delegation of additional authority by the Trustee to the Corporation in its capacity as administrator of the Trust. See “Pengrowth Management Limited — Management Agreement”. The head office and registered office of the Trust is located at 2100, 222 — 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0B4.

The Trust

The Trust is governed by the Trust Indenture. Under the Trust Indenture, the Trust has issued Trust Units and class A trust units to Unitholders 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 receive monthly distributions as declared by the Board 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 common shares do not participate in any distributions from the Corporation.

The Corporation acquires, owns and operates Working Interests and Royalty Interests in oil and natural gas properties. The Corporation 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 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 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 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. Pursuant to a management agreement that expires June 30, 2009, the Manager currently provides advisory, management, and administrative services to the Trust and the Corporation. See “Pengrowth Management Limited - Management Agreement”. 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. These functions will be internalized and undertaken by the Corporation following expiry of the Management Agreement.

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 of January 1, 2009:

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Business Strategy and Strengths

Our goal over the longer term is to maximize returns to the Unitholders through cash distributions on a per Trust Unit basis and enhancing the value of the Trust Units. Our business model balances our distributions with our capital program while considering our level of indebtedness and our sources of equity and debt capital. 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 exploiting our properties, which includes the use of new technologies and achieving 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 through our participation in the Weyburn Unit and pilot projects at our Judy Creek field and South Swan Hills field. We are 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 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 help to extend the operating life of our mature gas properties. We use 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 a substantial amount of undeveloped acreage over which we control operations. This undeveloped land provides future drilling opportunities, which includes limited lower risk exploration. Our operations are presently focused substantially in the Western Canadian Sedimentary Basin. We also have experience in offshore operations through our 8.4 percent participation in the Sable Offshore Energy Project.

Our ability to pay out distributions over the longer term is dependent upon our ability to make acquisitions and to conduct effective operations and investments in our existing properties such that the operating cashflow, net of capital expenditures, is maintained or grows on a per unit basis. As we address ordinary declines in production from our existing assets through development capital projects, we also consider the acquisition of domestic and international oil and gas assets. We evaluate acquisition and development opportunities based upon the following criteria:

Acquisitions

• Acquisitions should yield economic returns above Pengrowth’s cost of capital and be accretive on a per Trust Unit basis based upon current forecast parameters. In determining economic value and whether an acquisition is accretive, we examine the profile of production, operating costs, capital costs, abandonment expenses, commodity price forecasts and other key variables and compare that with the profile of our existing asset base to understand the impact over time in terms of cash flow, production, reserves and distributions on a per Trust Unit basis.

• The 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 and, preferably, where operatorship may be assumed by Pengrowth;

o favourable production history;

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o upside potential through infill drilling, limited exploration 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.

• Generally each purchase of new properties must be based on an independent engineering report.

Development

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

o the net present value of future net revenue created by the capital invested;

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 has historically allowed Pengrowth to bid competitively for oil and natural gas properties. However, our cost of capital has been increased by the announcement of the SIFT Legislation, recent declines in commodity prices and the impact of the global recession.

SIFT Legislation Considerations

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

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

We believe our structure provides significant value for our Unitholders and there may not be any immediate incentive to make a material structural change. We will continue to carefully manage our tax pools to offset taxes payable by Pengrowth and mitigate the impact of the new tax on our Unitholders after 2010. Sufficient tax pool

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balances may exist in the Corporation and the Trust to mitigate the impact of the SIFT Legislation for several years beyond January 1, 2011.

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

GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST

Recent Developments

2009 Forecast Capital, Production and Operating Costs

On December 18, 2008, Pengrowth released the details of its 2009 capital expenditure program and provided guidance on production and operating costs for 2009. Pengrowth’s 2009 development capital expenditure program consists of up to $189 million, plus an additional $20 million for the Lindbergh Oil Sands project. Expenditures on information technology and leasehold improvements add an additional $6 million to the announced 2009 capital program. Pengrowth also announced that should the commodity price outlook improve, up to an additional $35 million in capital projects were in an advanced stage of preparation and could be funded.

Recent low commodity prices and the current commodity price outlook have caused Pengrowth to significantly reduce capital funding from recent levels. Pengrowth relies on undistributed cash from operations to partially fund the capital program. The Board of Directors considered a number of factors in establishing the budget for 2009, including anticipated cash flow from operations based upon forecast commodity prices, the level of distributions paid by the Trust, Pengrowth’s level of indebtedness, Pengrowth’s access to capital and cost of capital and anticipated year end 2009 production that will result from the capital program. In deciding which projects to fund, Pengrowth reviewed its extensive portfolio and identified those projects that are estimated to create the greatest value for each dollar invested. The remainder of the projects identified were deferred to 2010 or subsequent years. This deferral does not impact Pengrowth’s reserves but will impact production declines in 2009.

On January 1, 2009, the Government of Alberta implemented the new royalty framework (the “New Royalty Framework”) and the transitional royalties (the “Transitional Royalties”), which apply to wells drilled after November 18, 2008 and to production from those wells through December 31, 2013. In determining which programs to include in the 2009 capital program, Alberta’s two new royalty regimes were taken into consideration. These two royalty regimes, at commodity prices seen in the last two years, do adversely affect value creation for Pengrowth, and, as a result, will change how Pengrowth allocates capital in the future. However, at current price levels and forecasted production rates, the new royalty regimes are only slightly different than the previous royalty regimes. In addition, the difference between the newer Transitional Royalties and the New Royalty Framework at current prices is minimal. As an indication of this minimal difference, in evaluating reserves for year-end reporting, the difference between the two royalty regimes was less than 500 Mboe (less than 1%) in royalties, when using GLJ forecast prices and costs.

Pengrowth expects to fund its 2009 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 Trust Units under the Equity Distribution Program or by other means. 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 2009: This 2009 program anticipates drilling an estimated 656 gross wells (370 net wells).

Planned Capital Expenditures	($ millions)		(% of Total)
Drilling and Completions	$	126		67	%
Plant and Facilities		50		26	%
Land and Seismic		10		5	%

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Planned Capital Expenditures	($ millions)			(% of Total)
Other (e.g., CO2 Pilot)		3			2	%
Total Development Capital	$	189			100	%
Lindbergh Oil Sands Project		20
Total Development Capital and Lindbergh	$	209
Building, IT		6
Total Capital	$	215
Average Daily Production Volume (boepd)					76,000 - 78,000(1)
Operating Costs (per boe)	$	14.45	(2)
General and Administrative Costs (per boe)	$	2.37	(2)(3)

Notes:
(1)	The 2009 estimate excludes potential additions through acquisitions or reductions due to dispositions.
(2)	Assuming production targets for 2009 are achieved.
(3)	Includes management fees of approximately $0.21 per boe based on the remaining term of the contract.

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. resident 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 fifth protocol to the Canada-U.S. Convention dated September 21, 2007 (the “Protocol”) to the Canada-United States Tax Convention, 1980 (“Canada-U.S. Convention”), which will increase the amount of Canadian withholding tax from 15 to 25 percent on distributions of income. Under Article IV(7)(b) of the Protocol, U.S. resident Unitholders are denied certain of the benefits under the Canada-U.S. Convention which would otherwise reduce the withholding tax on distributions of Pengrowth’s income from 25 percent to 15 percent (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 increase in the Canadian withholding tax rates on distributions 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 on 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. The Protocol came into force on December 15, 2008 when the two countries formally notified each other that their procedures were complete. We have elected under applicable Treasury Regulations to be treated as a partnership for United States federal income tax purposes. 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 to Pengrowth and its Unitholders.

Accrete Acquisition

On September 30, 2008, Pengrowth closed the acquisition of Accrete Energy Inc. for total consideration of $120 million paid by the issuance of 4,973,325 Trust Units and the assumption of $22 million of Accrete’s net liabilities. Pengrowth acquired 1,900 boepd of production in the Harmattan gas field and 8.4 MMboe of P+P reserves (before royalties and based on forecast prices and costs). Non-Harmattan assets and certain indebtedness of Accrete were transferred to an exploration company created for the benefit of former shareholders of Accrete. For each Accrete share held, Accrete Shareholders received 0.276624 Trust Units.

Senior Unsecured Notes

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

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Under the note agreement relating to the 2008 Senior Notes (as well as the note agreements relating to the 2007 U.S. Senior Notes, 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 2008 Senior Notes (as well as the note agreements relating to the 2007 U.S. Senior Notes, 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 2008 Senior Notes, 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 repayment of our lenders, note holders and other creditors and only the remainder, if any, would be available for distribution to our Unitholders”.

Credit Facility

On June 13, 2008, the Corporation amended and renewed its $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 expiring June 15, 2011. 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. In addition, Pengrowth has a demand operating line of credit for working capital purposes the size of which was increased from $35 million to $50 million as part of the June 13, 2008 amendments.

As at December 31, 2008, availability under these facilities was reduced by drawings of $372 million and by outstanding letters of credit in the amount of approximately $11.6 million.

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 (the “Equity Distribution Program”). In order to issue Trust Units pursuant to the Equity Distribution Program, Pengrowth is required to have filed, and received a receipt for, a base shelf prospectus which is current at the date Trust Units are issued under the Equity Distribution Program. Pengrowth expects to file an updated base shelf prospectus in the first half of 2009. 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 during the period of distribution. Should Pengrowth access the Equity Distribution Program, the net proceeds of the distribution of Trust Units combined with debt would be used to fund distributions, 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, 2008.

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 58 acquisitions and has raised in excess of $3.7 billion through 21 public equity offerings. As at December 31, 2008, Pengrowth has distributed approximately $4.1 billion to Unitholders.

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

On July 26, 2007, 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.

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.

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. This 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. The acquisition added 64.7 MMboe of Total Proved Plus Probable Reserves and more than 375,000 acres of undeveloped lands. The acquired properties are high working interest and were a strategic fit to Pengrowth’s existing asset base.

On October 2, 2006, Pengrowth completed a 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”. 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.

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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.

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 two 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.

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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 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 at $20.70 per Trust Unit to raise gross proceeds of $225.5 million.

On November 10, 2000, the Trust issued 8,165,000 Trust Units at $19.00 per Trust Unit 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 future of our business.

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Commodity prices have transitioned from a period of increasing prices in 2007 and early 2008 to substantially reduced prices during the second half of 2008 and early 2009. The period of price increases was accompanied by increases in costs, increased taxes and increased royalties. The higher costs and higher taxes and royalties negatively affect profitability. With lower commodity prices, the level of royalties has declined and, with the economic slowdown, costs are beginning to abate.

Current prices are similar to those seen in early 2005; however, as measured by CERA’s upstream capital cost index, costs are approximately double those of 2005. Pengrowth has mitigated some of the lower prices by forward selling production for 2009, 2010 and 2011, as detailed in the Trust’s Annual Report for the year ended December 31, 2008. Pengrowth’s expectation is that through disciplined commodity price risk management, diligently focusing on reducing costs and through the quality of Pengrowth’s assets, Pengrowth will continue to generate positive operating cash flow.

Lower commodity prices may continue for some time as a result of lower demand due to the global economic downturn and, in the case of natural gas, increasing supply. This economic downturn has seen lower demand for energy including lower oil and gas consumption. In addition, the high prices in 2008 prompted investment in a number of oil and gas projects that will result in additional production at a time of falling demand.

Over the longer term, Pengrowth believes that oil and gas commodity prices will ultimately increase due to falling oil and gas supply and increasing demand. Supply is expected to fall due to a decrease in investment in new oil and gas projects. Historically, low commodity prices have helped promote economic growth as commodity prices are a significant cost for manufacturing and other industries. Partially as a result of the current low oil and gas price outlook, Pengrowth believes there will be an economic recovery which will, in turn, increase oil and gas demand. However, the timing of the recovery is uncertain.

Increases or decreases in the Canadian dollar relative to the U.S. dollar also result in decreases or increases, respectively, in revenue 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. As Pengrowth’s operating expenses and capital costs are primarily paid in Canadian dollars, the fluctuation in the Canadian dollar against the U.S. dollar acts to reduce or increase net revenue.

Lower commodity prices and higher costs impact the value and volume of Pengrowth’s reserves. As an example of this impact, the value of Pengrowth’s reserves using the lower constant December 31, 2008 commodity prices is approximately half the value of the reserves using the higher forecasted commodity prices. However, the volume of reserves is only reduced by six percent. Reserves volumes are determined to be the quantity of oil or gas produced as long as the revenue from the production is greater than the operating cost. When commodity prices decline, there is potential for halting production sooner than if the commodity prices were higher. The quality of Pengrowth’s properties are such that there is a minimal impact on the volume due to costs higher than revenue and this contributes to Pengrowth maintaining an outlook of generating positive operating cash flow.

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, 2008.

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 under a contract that expires on June 30, 2009. 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 Pengrowth through effective acquisitions and dispositions, financing arrangements and operations. The Manager has focused to date upon high quality, long life proven producing

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properties located in Canada. During the balance of the unexpired term of the contact, the Manager will continue to focus upon acquisitions which are strategic and which add value to the Corporation and the Trust on a per Trust Unit basis.

Management Agreement

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

Key elements of the Management Agreement are:

• two distinct 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;

• 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

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• 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.

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 ten 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 continued 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

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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.

Expiry of the Management Agreement

On October 10, 2007, a special committee of the Board of Directors, comprised of all independent members of the Board, was formed for the purpose of advising the Board in connection with all matters pertaining to the orderly transition to a traditional corporate governance structure at the end of the term.

Based upon the recommendation of the special committee, the Corporation and James S. Kinnear, as Chief Executive Officer, entered into an executive employment agreement that will be effective July 1, 2009 upon expiry of the Management Agreement and will have a three year term. The Corporation, James S. Kinnear and the Manager also entered into an arrangement to address transitional issues such as the terms upon which certain employees and consultants of the Manager might be offered employment with the Corporation, the expenses of the Manager that will be assumed by the Corporation and a reduction in the entitlement of the Manager to appoint members of the Board of Directors from two to one after the expiry of the executive employment agreement on June 30, 2012. As there will be non-related assets, liabilities and certain business activities remaining within the Manager and other entities controlled by Mr. Kinnear, upon the expiry of the Management Agreement, the executive employment agreement contains provisions addressing permitted activities by those entities during the term of the executive employment agreement. The special committee also expressed its present intention that James S. Kinnear would remain in the position of Chairman of the Board of Directors. On the recommendation of the special committee, the Board created the new position of Vice-Chairman and Lead Independent Director to ensure appropriate independent corporate governance practices for the Board and the Corporation.

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Historically, the Manager received $6.95 million in 2008, $6.81 million in 2007 and $9.94 million in 2006 from Pengrowth.

PENGROWTH — OPERATIONAL INFORMATION

As at December 31, 2008, the Corporation had 591 permanent employees. Pengrowth has invested more than $8 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.

Principal 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 6, 2009 in respect of the oil and gas properties of Pengrowth effective December 31, 2008. All reserves data presented under this sub-heading is from the GLJ Report and reflects forecast prices and costs. In addition, the following table contains Pengrowth’s average daily production of oil, natural gas and NGLs for the year ended December 31, 2008. Pengrowth’s producing properties as of December 31, 2008 are summarized in the following table:

Summary of Company Interest
at December 31, 2008⁽¹⁾
(Forecast Prices and Costs)⁽²⁾

							P+P
							Value
					Reserve		Before Tax
	P+P		Remaining		Life		at 10%		2008 Oil		2008 Gas		2008 NGL		2008 Total
	Reserves(4)		Reserve Life		Index		Discount		Production		Production		Production		Production
Field	(Mboe)		(years)		(years)		($MM)		(bblpd)		(MMcfpd)		(bblpd)		(boepd)(4)
Light Oil Properties
Judy Creek		39,073		50		11.0		881.8		6,801		4.3		2,247		9,759
Weyburn		22,205		50		23.6		392.0		2,589		0.0		0		2,589
Swan Hills		18,103		50		19.1		256.9		2,025		1.7		263		2,570
Carson Creek		15,649		39		13.4		264.7		2,069		3.4		271		2,910
Fenn Big Valley		6,413		35		9.0		107.1		863		7.3		66		2,152
Deer Mountain		6,066		47		21.0		96.8		606		0.1		66		691
Other(3)		32,813				9.5		659.1		7,788		6.5		445		9,321
Sub-Total		140,322				12.7		2,658.3		22,740		23.3		3,357		29,992
Heavy Oil Properties
Bodo		7,544		35		11.5		119.6		1,580		2.0		0		1,917
Jenner		7,112		20		6.5		179.4		3,049		0.4		6		3,121
Tangleflags		5,394		28		7.1		78.8		2,505		0.4		0		2,571
Other(3)		4,628				7.2		67.7		1,008		4.2		0		1,716
Sub-Total		24,678				7.8		445.4		8,142		7.1		6		9,325
Conventional Gas Properties
Olds		24,766		50		17.3		315.8		0		18.4		685		3,755
Harmattan		19,124		44		10.0		298.2		322		16.1		1,226		4,226
Dunvegan		6,139		36		10.1		89.6		40		7.7		407		1,727
Quirk Creek		5,878		42		10.7		78.6		0		3.6		223		822
Carson Creek		5,231		15		6.5		109.6		0		4.7		689		1,477
McLeod River		3,664		42		8.4		69.0		42		5.3		198		1,129
Kaybob		3,519		36		13.9		49.8		0		4.5		38		781
Blackstone		3,399		24		10.5		40.0		0		5.6		0		941
Other(3)		17,214				7.6		300.1		571		28.1		319		5,577
Sub-Total		88,934				10.4		1,350.8		975		94.0		3,786		20,434

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							P+P
							Value
					Reserve		Before Tax
	P+P		Remaining		Life		at 10%		2008 Oil		2008 Gas		2008 NGL		2008 Total
	Reserves(4)		Reserve Life		Index		Discount		Production		Production		Production		Production
Field	(Mboe)		(years)		(years)		($MM)		(bblpd)		(MMcfpd)		(bblpd)		(boepd)(4)
Shallow Gas Properties
Three Hills/Twining		12,364		50		9.9		238.6		405		11.3		359		2,648
Coal Bed Methane		8,300		37		10.6		135.0		0		11.0		3		1,839
Monogram		8,032		36		8.7		163.4		0		14.1		0		2,350
Jenner		7,893		43		11.5		122.6		21		12.1		3		2,039
Lethbridge		3,291		49		9.0		56.7		0		6.8		0		1,142
Other(3)		14,091				10.5		222.0		256		26.2		108		4,738
Sub-Total		53,971				10.1		938.3		683		81.6		473		14,755
Offshore Gas Properties
Sable Island		9,213		7		3.7		184.0		0		34.8		1,693		7,485
Sub-Total		9,213				3.7		184.0		0		34.8		1,693		7,485
Oil Sands Properties
Lindbergh		6,345		13		—		4.6		0		0.0		0		0
Sub-Total		6,345				—		4.6		0		0.0		0		0
Total		323,463				10.6		5,581.5		32,539		240.8		9,315		81,991

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)	Forecast prices are shown under the heading “ —Pricing Assumptions”.
(3)	“Other” includes Pengrowth’s Working Interests and Royalty Interests in approximately 100 other properties.
(4)	Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of natural gas being equal to one 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 referred to as “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 northwest of Edmonton, Alberta and covers an area of approximately 38,300 acres. Judy Creek was discovered in 1959, placed on waterflood in 1962 and hydrocarbon miscible flood in 1985. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 39.1 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 11.0 years. Pengrowth’s Company Interest production for Judy Creek averaged 9,759 boepd in 2008.

2008 Development Activity

The 2008 development included the initiation of one new miscible pattern and one new waterflood pattern in the Beaverhill Lake Unit as well as the drilling of two infill wells, five reactivations and seven acid fractures. Two artificial lift conversions were performed in the West Unit.

Carbon Dioxide (CO₂) Pilot

The intent of the Judy Creek CO₂ enhanced oil recovery pilot project is to evaluate the potential of CO₂ injection to increase oil recovery and to recover hydrocarbons left behind from the hydrocarbon miscible flood. The

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injected fluid consists of trucked-in CO₂ and acid gas. The acid gas comes from the Judy Creek Conservation Plant and consists mainly of CO₂ and hydrogen sulfide (H₂S). CO₂ injection commenced in February of 2007.

Favorable response has been evident in 2008 with both incremental oil and hydrocarbons from the hydrocarbon miscible flood being produced. To date, 1.1 bcf of CO2 has been injected into the 80-acre pilot pattern. This has resulted in an additional 27 Mbbl of oil (~1.3% of the original oil in place) and 150 MMcf of natural gas hydrocarbons from the hydrocarbon miscible flood. Given the encouraging results, Pengrowth intends to continue CO₂ injection until the second quarter of 2009 and will continue data collection until 2010.

2009 Development Activity

One new miscible pattern and the drilling of one new oil producer to follow-up the 2008 success in Section 04-064-11W5 is budgeted for 2009. Nine acid fractures and five reactivations are planned.

Weyburn Unit

Pengrowth holds a 9.76 percent non-operating Working Interest in the Weyburn Unit in southeast Saskatchewan. Medium (25-34° API) sour crude oil is produced from the Midale carbonate reservoir under waterflood and a CO₂ miscible flood enhanced oil recovery program. This is the largest enhanced oil recovery project in Canada and has also left approximately 10 million tonnes of CO₂ in the reservoir. The field consists of approximately 700 production wells and 300 injection wells. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 22.2 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 23.6 years. Pengrowth’s Company Interest production for Weyburn averaged 2,589 boepd in 2008.

2008 Development Activity

A total of 34 horizontal production infill wells were drilled in 2008, six in the waterflood area and 28 in the CO₂ enhanced recovery area. Approximately 200,000 bwpd is injected in the waterflood area. Current CO₂ injection is 125 MMcfpd of source CO₂ plus approximately 100 MMcfpd of recycled CO₂. Front end engineering and design work was conducted in 2008 to add additional CO₂ recycle compression capacity in 2009.

2009 Development Activity

Drilling activity will be reduced for 2009, with only two wells planned due to the current economic uncertainty and low oil prices. A second centrifugal CO₂ injection compressor is budgeted for 2009. The proposed capital budget for 2009 is $192.3 million gross ($18.9 million net) and the proposed operations budget is $148.5 million gross ($14.5 million net).

Swan Hills

Effective May 30, 2008, Pengrowth’s non-operated Working Interest in the Swan Hills Unit No. 1 increased, through acquisitions, from 22.34 to 24.01 percent. The Unit is located near the Judy Creek field in north central Alberta. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 18.1 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 19.1 years. Pengrowth’s Company Interest production for Swan Hills averaged 2,570 boepd in 2008.

2008 Development Activity

In 2008, 11 new oil wells were drilled in the northwest area of the Unit, eight of which were on production at year end. One new hydrocarbon miscible flood pattern was developed, which included the drilling of a new injector. Solvent injection is scheduled to commence in the second half of 2009.

The first two miscible patterns to target the platform of the reef began development late in 2008. Miscible injection is scheduled to start in mid 2009. A pilot project 40 acre hydrocarbon miscible flood pattern developed

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in 2007 was under water injection in 2008, and will commence miscible injection by mid 2009. In addition, three oil wells were recompleted.

2009 Development Activity

The 2009 development plans include drilling ten new 80 acre infill oil wells and initiating hydrocarbon miscible injection in the four patterns mentioned above. A variety of well recompletions, suspended well reactivations and artificial lift upgrades will also round out the 2009 development plan.

Carson Creek

Carson Creek is located 160 kilometres northwest of Edmonton, Alberta and is comprised of two Pengrowth-operated Units (one oil and one gas and condensate) which cover approximately 46,200 acres. The Carson Creek North Unit (oil) in which Pengrowth has an 88.6 percent Working Interest was discovered in 1958 and the current waterflood was initiated in 1964. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 15.6 MMboe. The Remaining Reserve Life is 39 years and the Reserve Life Index is 13.4 years. Pengrowth’s Company Interest production for the Carson Creek North Unit averaged 2,907 boepd in 2008.

2008 Development Activity

Pengrowth’s 2008 activities included drilling three new Beaverhill Lake oil producers. Other activities included ongoing geologic modeling and reservoir simulation, waterflood optimization and well workovers to improve production.

2009 Development Activity

Pengrowth anticipates taking advantage of regular well maintenance to enhance production from existing wells in the Carson Creek North Unit as well as ongoing waterflood optimization.

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, 2008 are estimated to be 6.4 MMboe. The Remaining Reserve Life is 35 years and the Reserve Life Index is 9 years. Pengrowth’s Company Interest production for Fenn Big Valley averaged 2,152 boepd in 2008.

2008 Development Activity

Pengrowth’s 2008 activity included shooting 3D seismic over the southern and northern regions to supplement the existing 3D seismic over the central region. One Belly River gas well and six Nisku ‘attic’ oil wells were drilled. In addition, two Nisku oil and seven Belly River/Edmonton gas recompletions were conducted.

2009 Development Activity

Pengrowth’s 2009 planned activities include drilling three Leduc pinnacle oil wells and two Edmonton sands gas wells. Three shallow gas recompletions are also planned.

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Deer Mountain Area

Deer Mountain is located 190 kilometres northwest of Edmonton, Alberta, and consists of both a Pengrowth-operated Unit, which covers approximately 6,400 acres, and four non-Unit wells. The 85.42 percent Working Interest in the Unit covers ten sections of land, and the non-Unit lands contribute an additional four sections of land with operated interests that range from 67 to 100 percent. A waterflood scheme has been operating in the Deer Mountain Unit since September 1968. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 6.1 MMboe. The Remaining Reserve Life is 47 years and the Reserve Life Index is 21 years. Pengrowth’s Company Interest production for Deer Mountain averaged 691 boepd in 2008.

2008 Development Activity

Development activity in 2008 included the drilling of two successful oil wells, the reactivation of three inactive oil wells and workovers on three producing oil and one water injection well. Pengrowth also completed surface modifications to utilize non-potable water as the make-up water for the waterflood.

2009 Development Activity

On January 7, 2009 Pengrowth was successful in increasing its 100 percent Working Interest land holding in the Deer Mountain area by an additional 9.25 sections. The 2009 planned activities for the waterflood include optimization of waterflood performance, drilling one additional water well for the waterflood and optimization of existing injectors. In addition, three workovers will be conducted on existing producers.

Heavy Oil Properties

Bodo

The Bodo heavy oil property straddles the Alberta-Saskatchewan border near Township 35 and produces mainly 12° API oil from the McLaren formation and 15° API oil from the Lloydminster formation. 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, 2008 are estimated to be 7.5 MMboe. The Remaining Reserve Life is 35 years and the Reserve Life Index is 11.5 years. Pengrowth’s Company Interest production for Bodo averaged 1,917 boepd in 2008.

2008 Development Activity

Pengrowth drilled a total of 13 horizontal wells in the greater Cosine area. An additional area was identified for polymer flood and has been on injection since March of 2008. Pengrowth continues to review operating cost reduction initiatives and has focused on waterflood management improvements.

2009 Development Activity

Two horizontal wells and one vertical well are planned to be drilled in the greater Bodo area in 2009. Ongoing surveillance of both the waterflood and polymer flood will continue, with the intention of expanding the polymer flood to other portions of the pool. 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. A large inventory of recompletion prospects have been identified with a number of the top prospects scheduled for 2009.

Jenner

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 89.1 percent in the

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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, 2008 are estimated to be 7.1 MMboe. The Remaining Reserve Life is 20 years and the Reserve Life Index is 6.5 years. Pengrowth’s Company Interest production for Jenner averaged 3,121 boepd in 2008.

     2008 Development Activity

Pengrowth’s 2008 development activities included the drilling of five vertical wells and four horizontal wells. In addition, water handling improvements were made and numerous production optimization projects were completed.

     2009 Development Activity

The 2009 development activities will include the drilling of several horizontal re-entry wells, in addition to production optimization projects and further produced water handling improvements.

Tangleflags

Tangleflags is located in west central Saskatchewan, approximately 40 kilometers northeast of Lloydminster. It produces 12° API oil mainly from the Lloydminster sands under thermal recovery process, with some cold production from other Mannville sands. Pengrowth holds a 50 percent non-operating working interest.

The thermal Tangleflags North enhanced oil recovery project commenced operation in the late 1980’s and a variety of well configurations have been tried, including vertical and horizontal steam injection and producing wells. These include vertical injection with vertical production, vertical injection with horizontal production, horizontal injection with horizontal production (i.e., SAGD).

Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 5.4 MMboe. The Remaining Reserve Life is 28 years and the Reserve Life Index is 7.1 years. Pengrowth’s Company Interest production for Tangleflags averaged 2,571 boepd in 2008.

     2008 Development Activity

In 2008, activity focused on optimizing the performance of thirteen recent infill wells that targeted bypassed oil identified from 4D seismic. Several vertical producers were converted to steam injectors to optimize this infill program, which is expected to increase reserves by 20 percent and partially offset decline year over year.

     2009 Development Activity

In the current low oil price climate, the property will be operated to take advantage of the significant residual heat in this mature field. There are no significant capital projects planned pending an improvement in oil price; however, 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, 2008 are estimated to be

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24.8 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 17.3 years. Pengrowth’s Company Interest production for Olds averaged 3,755 boepd in 2008.

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.

     2008 Development Activity

The 2008 activities in Olds focused on pipeline and compression improvements that allowed existing wells to produce at higher rates resulting in minimal production decline. A major plant turnaround was successfully conducted in the second quarter. Sulphur solvent washes or squeezes on several of the Wabamun wells were also performed, resulting in the reactivation of three previously shut-in wells. In December, one Pekisko horizontal well was recompleted using multi-stage fracturing.

     2009 Development Activity

Development plans for 2009 include two new drills, improving efficiency in the south end gathering system with the installation of a new pipeline, and continued compression improvements. In addition, recompletion of two wells using multi-stage fracturing technology is also underway.

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 Wabumun, as well as two partner-operated Elkton Units. The production is predominantly sweet natural gas with Working Interests averaging 55 percent in the non-Unit lands and 25 percent in the Units. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 19.1 MMboe. The Remaining Reserve Life is 44 years and the Reserve Life Index is 10 years. Pengrowth’s Company Interest production for Harmattan averaged 4,226 boepd in 2008.

     2008 Development Activity

The Elkton well drilled in 2008 was tied-in and is currently producing 1.2 MMcfpd with a low decline rate. A five section downspacing application for the Elkton zone was submitted as well as a four section downspacing application for the Ellerslie. Two other successful wells were drilled, an Ellerslie oil well and a Wabamun oil well.

     2009 Development Activity

The activity for 2009 includes one new drill on the former Accrete lands. Optimization work identified from the analysis conducted on the Accrete property will also be performed.

Dunvegan

The partner operated Dunvegan gas field is located 430 kilometres northwest of Edmonton, Alberta in the Peace River area. Pengrowth has a 10.37 percent Working Interest in the Dunvegan Gas Unit No. 1 and various interests in non-unit producing wells. The property contains over 200 producing wells and covers an area of approximately 52,600 acres. Approximately 95 percent of the Unit’s identified natural gas reserves are contained in the Mississippian Debolt formation. A new play in the Upper Debolt formation has emerged over the last year. This zone is not part of the main Unit. Gas potential is still being evaluated, but initial results are promising. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 6.1 MMboe. The Remaining Reserve Life is 36 years and the Reserve Life Index is 10.1 years. Pengrowth’s Company Interest production for Dunvegan averaged 1,727 boepd in 2008.

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     2008 Development Activity

There were nine successful wells drilled in 2008, and one recompletion. Compression and other optimization activities were also performed.

     2009 Development Activity

Activity in 2009 will include five new drilling locations in the Unit. The Upper Debolt will be developed further with four horizontal drills, with the possibility of follow-up locations. There will also be additional optimization, recompletion projects and compression work.

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 other zones 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, 2008 are estimated to be 5.9 MMboe. The Remaining Reserve Life is 42 years and the Reserve Life Index is 10.7 years. Pengrowth’s Company Interest production for Quirk Creek averaged 822 boepd in 2008.

     2008 Development Activity

The main activity in 2008 focused on plant operations. In September, the plant was shutdown for a scheduled turnaround. Several unscheduled shutdowns have adversely affected production through the second half of 2008 by approximately 750 boepd when averaged over the full year.

     2009 Development Activity

The plant was brought back on stream on February 5, 2009. No other activity is planned for 2009.

Carson Creek

Carson Creek is located 160 kilometres northwest of Edmonton, Alberta and is comprised of two Pengrowth-operated Units (one oil and one gas and condensate) which cover approximately 46,200 acres. The Carson Creek Beaverhill Lake Unit No. 1 (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, 2008 are estimated to be 5.2 MMboe. The Remaining Reserve Life is 15 years and the Reserve Life Index is 6.5 years. Pengrowth’s Company Interest production for Carson Creek gas averaged 1,472 boepd in 2008.

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

     2008 Development Activity

Pengrowth’s 2008 activities included drilling three new Beaverhill Lake gas producers. Results of the drilling are encouraging with production commencing in late 2008 and early 2009. Other activities included ongoing geologic modeling and reservoir simulation and well workovers to improve production.

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     2009 Development Activity

The activity anticipated for 2009 consists of drilling one horizontal Swan Hills gas well to assess the feasibility of staged fracturing technology in the area. Based on results of this horizontal well, additional drilling is planned to further develop the play.

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, 2008 are estimated to be 3.7 MMboe. The Remaining Reserve Life is 42 years and the Reserve Life Index is 8.4 years. Pengrowth’s Company Interest production for McLeod River averaged 1,129 boepd in 2008.

     2008 Development Activity

Pengrowth’s 2008 development activity included the reactivation of one Gething gas well.

     2009 Development Activity

The activities for 2009 include three Mannville recompletions.

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, 2008 are estimated to be 3.5 MMboe. The Remaining Reserve Life is 36 years and the Reserve Life Index is 13.9 years. Pengrowth’s Company Interest production for Kaybob averaged 781 boepd in 2008.

     2008 Development Activity

Pengrowth drilled two Kaybob Notikewin Unit wells in 2008, with one well tied in and the other deferred due to increased tie-in costs.

     2009 Development Activity

No activity is anticipated for the Kaybob property in 2009.

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, 2008 are estimated to be 3.4 MMboe. The Remaining Reserve Life is 24 years and the Reserve Life Index is 10.5 years. Pengrowth’s Company Interest production for Blackstone averaged 941 boepd in 2008.

     2008 Development Activity

There was no development activity on the Blackstone property in 2008.

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     2009 Development Activity

No activity is anticipated on the Blackstone property in 2009.

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, 2008 are estimated to be 12.4 MMboe. The Remaining Reserve Life is 50 years and the Reserve Life Index is 9.9 years. Pengrowth’s Company Interest production for Twining/Three Hills Creek averaged 2,648 boepd in 2008.

     2008 Development Activity

Development activity in 2008 included the drilling of five oil wells and five natural gas wells.

     2009 Development Activity

Pengrowth’s 2009 development activities include drilling six oil wells and two gas wells.

Coal Bed Methane (CBM)

Pengrowth’s CBM activity is focused in the Ghost Pine, Fenn Big Valley and Twining areas which are 100 to 160 kilometres northeast of Calgary, Alberta. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 8.3 MMboe. The Remaining Reserve Life is 37 years and the Reserve Life Index is 10.6 years. Pengrowth’s Company Interest CBM production averaged 1,839 boepd in 2008.

     2008 Development Activity

A total of 27 wells were drilled or recompleted in the Horseshoe Canyon Formation and Pengrowth drilled its second and third horizontal Mannville CBM wells in the Fenn Big Valley area. Pengrowth also participated in 35 partner operated wells.

     2009 Development Activity

Plans for 2009 include drilling 21 Horseshoe Canyon/Belly River wells and one Mannville horizontal well. The Pengrowth compressor station in Twining will also undergo expansions that will double the capacity to accommodate further drilling in the area.

Monogram Gas Unit

The Monogram Gas Unit is located approximately 225 kilometres 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 seven wells drilled in 1971. By the end of 1989, 294 wells had been drilled. By the end of 2008, 839 wells had been drilled. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 8.0 MMboe. The Remaining Reserve Life is 36 years and the Reserve Life Index is 8.7 years. Pengrowth’s Company Interest production for Monogram averaged 2,350 boepd in 2008.

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     2008 Development Activity

There were 60 infill wells drilled in the first quarter of 2008 and an additional 91 wells were drilled in the fourth quarter.

     2009 Development Activity

The 2009 development plan is to drill 125 infill wells.

Jenner

The Jenner shallow gas property is located 250 kilometres east of Calgary, Alberta. Production from this property is primarily from the Milk River, Medicine Hat and Second White Specks formations within the Jenner, Atlee Buffalo and Atlee fields. Pengrowth has an average Working Interest of 67.2 percent and operates the majority of the production. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 7.9 MMboe. The Remaining Reserve Life is 43 years and the Reserve Life Index is 11.5 years. Pengrowth’s Company Interest production for Jenner Shallow Gas averaged 2,039 boepd in 2008.

     2008 Development Activity

Pengrowth’s 2008 development activities were focused around improving efficiencies in gas well de-watering and reducing operating costs. Construction of a Pengrowth owned and operated water disposal facility was completed. Two wells were successfully recompleted in the Belly River zone.

     2009 Development Activity

The 2009 development activities will focus on optimization of compression and gas gathering systems. Numerous drilling opportunities exist within the property.

Lethbridge

Pengrowth’s operations in the Lethbridge, Alberta area cover a large area and include operating over 250 wells, most of which are 100 percent Working Interest. All wells produce sweet gas from the Milk River, BFS (Barons) and Bow Island formations. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 3.3 MMboe. The Remaining Reserve Life is 49 years and the Reserve Life Index is 9 years. Pengrowth’s Company Interest production for Lethbridge averaged 1,142 boepd in 2008.

     2008 Development Activity

During 2008, Pengrowth performed 16 coil cleanouts. Coiled tubing was installed in three wells to maximize production and three compressors were reconfigured to reduce fuel usage.

     2009 Development Activity

The planned activities for 2009 are a continued well cleanout program and installing smaller production tubing to improve well de-watering.

Offshore Gas Properties

Sable Offshore Energy Project

The Sable Offshore Energy Project (“SOEP”) is located 225 kilometres off the east coast of Nova Scotia and consists of several natural gas fields and five producing platforms. 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

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sent to the Point Tupper fractionation plant for processing. Sales gas is transported to market via the Maritimes and Northeast Pipeline. Propane and butane are shipped by both truck and rail and condensate is transported by tanker ship from the platform. SOEP has been producing since late 1999.

Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2008 are estimated to be 9.2 MMboe. The Remaining Reserve Life is 7 years and the Reserve Life Index is 3.7 years. Pengrowth’s Company Interest production for SOEP averaged 7,485 boepd in 2008.

     2008 Development Activity

The 2008 activities at SOEP included the continued computer modeling of the fields to identify the best methods to maximize gas recovery, completion of the compressor installation and a series of well workovers. A deep cut facility was installed and resulted in additional liquid recovery. The produced water system was re-commissioned at North Triumph which will be required to accommodate future water production from the North Triumph wells. A six day facilities turnaround was completed in August. The shutdown was required for regular maintenance and regulatory requirements. It was also required by Maritimes and Northeast Pipeline to permit the tie in of additional compression.

     2009 Development Activity

The major capital project for 2009 will be the drilling of a fourth well in the Alma field in June of 2009. Several workovers are also planned, and computer modeling will continue in order to maximize gas recovery. Opportunities to optimize the liquid loading facilities will be further investigated. There will also be a 20 day shutdown in 2009 to complete pressure vessel inspections and make facility repairs.

Oil Sands Properties

Lindbergh

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

Company Interest Total Proved plus Probable Reserves at December 31, 2008 are estimated to be 6.3 MMboe. See also “–Lindbergh Oil Sands Contingent Resources”.

     2008 Development Activity

A pilot project scheme application was submitted to the applicable regulators in April 2008 and supplemental information requests were received in the third quarter of 2008 in respect to the application. Responses to the supplemental information requests have been developed for resubmission in the first quarter of 2009. Capital spending on the pilot project was $20 million, which resulted in the completion of a significant portion of the detailed design and engineering for the pilot facilities and wells.

     2009 Development Activity

A prudent capital plan has been put into place for the Lindbergh asset that will allow further delineation drilling to firm up resource estimates as well as progress the detailed engineering to near completion by year end in preparation for execution in future years.

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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, prepared in accordance with NI 51-101, with an effective date of December 31, 2008 contained in the GLJ Report dated February 6, 2009, 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, 2008 and the preparation date is January 15, 2009 when the final information was provided. 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 independent evaluation of Proved Reserves and Total Proved Plus Probable Reserves and no attempt was made to evaluate Possible Reserves in the conventional properties. It is Pengrowth’s practice to obtain an engineering report evaluating all of its Proved Reserves and Probable Reserves as at December 31 of each year. Only in respect of the Lindbergh oil sands property did GLJ evaluate Possible Reserves and Contingent Resources. All of 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 net present value of the estimated future net revenue associated with such reserves as at December 31, 2008 contained in the GLJ Report dated February 6, 2009. These tables summarize the data contained in the GLJ Report, and, as a result, may contain slightly different numbers than the GLJ Report due to rounding. Columns may not add due to rounding.

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

Pengrowth’s future net revenues associated with the reserves contained in this Annual Information Form reflect the New Royalty Framework and the Transitional Royalties implemented by the Government of Alberta on January 1, 2009. The Transitional Royalties may be applied to wells drilled after November 18, 2008 and to production from those wells through December 31, 2013.The Transitional Royalties were applied to qualifying wells in Alberta when the Transitional Royalties resulted in lower royalties than the royalties using the New Royalty Framework. The overall impact of the Transitional Royalties as compared to the New Royalty Framework is minimal.

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

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

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• SIFT tax starting January 2011 at 27.11 percent (and 25.61 percent in 2012 and thereafter). The SIFT tax is based on the provincial allocation from the Corporation’s December 31, 2007 tax return;

• Annual general and administration expenses at the current level;

• Interest expense at the current level;

• Inclusion of tax pools and deductions at the trust level as well as at the operating entity level (total tax pools of $3.1 billion);

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

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

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

The net revenues estimated in the GLJ Report represent estimates of the revenues from oil and gas sales from 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 revenues are not the same as cash flows from operating activities reported by the Trust in its statement of cash flows. The GLJ Report does not estimate general and administrative expenses, 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 to this Annual Information Form as Appendices A and B, respectively.

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Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves
as of December 31, 2008
(Forecast Prices and Costs)⁽¹⁾

	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	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)
Proved Reserves
Proved Developed Producing		72,564		72,411		57,262		14,453		14,443		13,073		22,009		21,902		15,806
Proved Developed Non- Producing		821		821		611		148		148		136		415		414		304
Proved Undeveloped		17,030		17,029		12,541		1,676		1,676		1,370		1,120		1,120		766
Total Proved Reserves		90,415		90,261		70,414		16,277		16,268		14,579		23,543		23,436		16,876
Probable Reserves		30,874		30,846		23,545		11,451		11,448		10,110		8,898		8,873		6,353
Total Proved Plus Probable Reserves		121,289		121,107		93,959		27,728		27,716		24,689		32,442		32,309		23,228

	Natural Gas						Coal Bed Methane						Total Oil Equivalent Basis(2)
	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		527,799		523,765		428,531		21,524		20,490		20,080		200,580		199,466		160,910
Proved Developed Non- Producing		19,544		19,337		14,528		2,177		2,157		2,025		5,004		4,965		3,810
Proved Undeveloped		48,440		48,310		39,368		10,447		10,372		9,397		29,640		29,605		22,804
Total Proved Reserves		595,783		591,412		482,427		34,148		33,019		31,503		235,224		234,036		187,524
Probable Reserves		206,815		205,163		163,393		15,279		14,960		13,768		88,239		87,854		69,534
Total Proved Plus Probable Reserves		802,598		796,576		645,821		49,427		47,979		45,270		323,463		321,891		257,058

Notes:
(1)	Forecast prices are shown under the heading “ –Pricing Assumptions”.
(2)	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, 2008
Before and After Income Taxes
(Forecast Prices and Costs)⁽¹⁾

											Unit Value
	Before Income Taxes										Before Income Tax
	Discounted at (%/Year)										Discounted at 10%/Year(2)
	0%		5%		10%		15%		20%
Reserves Category	($MM)		($MM)		($MM)		($MM)		($MM)		$/boe		$/Mcfe
Proved Reserves
Proved Developed Producing		6,947		5,046		3,982		3,308		2,843		24.75		4.12
Proved Developed Non-Producing		162		103		75		57		46		19.56		3.26
Proved Undeveloped		1,097		611		368		229		142		16.14		2.69
Total Proved Reserves		8,206		5,761		4,425		3,594		3,030		23.60		3.93
Probable Reserves		3,703		1,899		1,157		779		558		16.64		2.77
Total Proved Plus Probable Reserves		11,909		7,660		5,582		4,373		3,589		21.71		3.62

	After Income Taxes
	Discounted at (%/Year)
	0%		5%		10%		15%		20%
Reserves Category	($MM)		($MM)		($MM)		($MM)		($MM)
Proved Reserves
Proved Developed Producing		5,894		4,225		3,462		2,938		2,561
Proved Developed Non-Producing		99		66		49		38		31
Proved Undeveloped		430		398		221		125		66
Total Proved Reserves		6,423		4,689		3,732		3,101		2,658
Probable Reserves		2,214		1,098		692		479		351
Total Proved Plus Probable Reserves		8,637		5,787		4,424		3,580		3,009

Notes:
(1)	Forecast prices are shown under the heading “ –Pricing Assumptions”.
(2)	Net present value of future net revenue per reserve unit values are based on Pengrowth’s net reserves.

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Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2008
(Forecast Prices and Costs)⁽¹⁾

Future Net

Capital

Future Net

Revenue

Operating

Development

Abandonment

Revenue Before

After Income

Revenue

Royalties(2)

Costs

Costs

Costs(3)

Income Taxes

Income Tax

Taxes

Reserves Category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Proved Reserves

17,515

3,630

4,901

579

200

8,206

(1,783

)

6,423

Total Proved Plus Probable Reserves

25,082

5,269

6,670

1,009

225

11,909

(3,272

)

8,637

Notes:
(1)	Forecast prices are shown under the heading “ —Pricing Assumptions”.
(2)	Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. This includes the impact of the New Royalty Framework implemented by the Government of Alberta on January 1, 2009, and the optional Transitional Royalty until December 31, 2013 for qualifying wells drilled in Alberta after November 18, 2008.
(3)	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, 2008
(Forecast Prices and Costs)⁽¹⁾

		Future Net Revenue
		Before Income Taxes
		(discounted at 10%/yr)		Unit Value(4)
Reserves Category	Production Group	($MM)		($/boe)		($/Mcfe)
Total Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)(2)		2,181		25.90		4.32
	Heavy Oil (including solution gas and other by-products)((1)		358		21.96		3.66
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)		1,777		21.74		3.62
	Non-conventional Oil & Gas Activities		108		20.57		3.43
	Total		4,425		23.60		3.93
Total Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)(2)		2,708		24.36		4.06
	Heavy Oil (including solution gas and other by-products)(1)		443		20.83		3.47
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)		2,289		20.63		3.44
	Non-conventional Oil & Gas Activities		141		10.59		1.76
	Total		5,582		21.71		3.62

Notes:
(1)	Forecast prices are shown under the heading “ —Pricing Assumptions”.
(2)	NGL’s associated with the production of solution gas are included as a by-product.
(3)	NGL’s associated with the production of natural gas are included as a by-product.
(4)	Net present value of future net revenue per reserve 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, 2008
(Constant Prices and Costs)⁽¹⁾

	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	(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)
Proved Reserves
Proved Developed Producing		64,697		64,569		59,544		12,386		12,380		11,668		21,414		21,311		15,539
Proved Developed Non-Producing		882		882		740		111		111		108		416		416		306
Proved Undeveloped		18,269		18,268		16,541		1,522		1,522		1,395		1,200		1,200		810
Total Proved Reserves		83,847		83,719		76,825		14,019		14,013		13,171		23,030		22,927		16,655
Probable Reserves		30,427		30,405		27,763		4,373		4,372		4,032		8,841		8,817		6,364
Total Proved Plus Probable Reserves		114,274		114,124		104,588		18,392		18,385		17,203		31,871		31,743		23,019

	Natural Gas						Coal Bed Methane						Total Oil Equivalent Basis(2)
	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		517,028		512,917		437,243		21,526		20,492		20,175		188,256		187,162		162,987
Proved Developed Non-Producing		19,291		19,072		14,922		2,177		2,157		2,034		4,987		4,946		3,980
Proved Undeveloped		48,614		48,485		41,044		10,445		10,371		9,511		30,834		30,799		27,172
Total Proved Reserves		584,933		580,473		493,210		34,149		33,020		31,721		224,077		222,908		194,139
Probable Reserves		203,168		201,735		169,631		15,274		14,954		13,999		80,048		79,708		68,764
Total Proved Plus Probable Reserves		788,101		782,208		662,841		49,423		47,974		45,720		304,125		302,616		262,902

Notes:
(1)	Constant prices are shown under the heading “ —Pricing Assumptions”.
(2)	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.

- 39 -

Summary of Net Present Value
of Future Net Revenue
as of December 31, 2008
Before and After Income Tax
(Constant Prices and Costs)⁽¹⁾

	Before Income Taxes											Unit Value
	Discounted At (%/Year)											Before Income Tax
	0%		5%		10%		15%		20%			Discounted At 10%/Year(2)
Reserves Category	($MM)		($MM)		($MM)		($MM)		($MM)			$/boe		$/Mcfe
Proved Reserves
Proved Developed Producing		3,001		2,362		1,967		1,697		1,502			12.07		2.01
Proved Developed Non-Producing		77		51		37		29		23			9.30		1.55
Proved Undeveloped		356		163		62		4		(32	)		2.28		0.38
Total Proved Reserves		3,434		2,576		2,066		1,730		1,492			10.64		1.77
Probable Reserves		1,386		787		509		356		263			7.40		1.23
Total Proved Plus Probable Reserves		4,820		3,363		2,575		2,086		1,755			9.79		1.63

	After Income Taxes
	Discounted At (%/Year)
	0%		5%		10%		15%			20%
Reserves Category	($MM)		($MM)		($MM)		($MM)			($MM)
Proved Reserves
Proved Developed Producing		2,951		2,344		1,951		1,688			1,489
Proved Developed Non-Producing		49		33		24		19			14
Proved Undeveloped		280		141		41		(17	)		(50	)
Total Proved Reserves		3,280		2,518		2,016		1,685			1,453
Probable Reserves		1,109		729		461		318			231
Total Proved Plus Probable Reserves		4,389		3,247		2,477		2,003			1,684

Notes:
(1)	Constant prices are shown under the heading “ —Pricing Assumptions”.
(2)	Net present value of future net revenue per reserve unit values are based on Pengrowth’s net reserves

- 40 -

Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2008
(Constant Prices and Costs)⁽¹⁾

Future Net

Revenue

Future net

Capital

Before

Revenue

Operating

Development

Abandonment

Income

Income

After Income

Revenue

Royalties(2)

Costs

Costs

Costs(3)

Taxes

Tax

Taxes

Reserves Category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Proved Reserves

8,839

1,111

3,616

524

153

3,434

(154

)

3,280

Total Proved Plus Probable Reserves

11,998

1,530

4,676

813

160

4,820

(431

)

4,389

Notes:
(1)	Constant prices are shown under the heading “ —Pricing Assumptions”.
(2)	Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. This includes the impact of the New Royalty Framework implemented by the Government of Alberta on January 1, 2009, and the optional Transitional Royalty until December 31, 2013 for qualifying wells drilled in Alberta after November 18, 2008.
(3)	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, 2008
(Constant Prices and Costs)⁽¹⁾

		Future Net
		Revenue Before
		Income Taxes
		(discounted at 10%/yr)		Unit Value(4)
Reserves Category	Production Group	($MM)		($/Boe)		($/Mcfe)
Total Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)(2)		779		8.59		1.43
	Heavy Oil (including solution gas and other by-products)(1)		81		5.44		0.91
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)		1,136		13.75		2.29
	Non-conventional Oil & Gas Activities		70		11.56		1.93
	Total		2,066		10.64		1.77
Total Proved Plus      Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)(2)		960		7.87		1.31
	Heavy Oil (including solution gas and other by-products)(1)		97		5.01		0.84
	Natural Gas (including by-products but excluding solution gas from oil wells)(3)		1,432		12.74		2.12
	Non-conventional Oil & Gas Activities		85		9.78		1.63
	Total		2,575		9.79		1.63

Notes:
(1)	Constant prices are shown under the heading “ —Pricing Assumptions”.
(2)	NGL’s associated with the production of solution gas are included as a by-product.
(3)	NGL’s associated with the production of natural gas are included as a by-product.
(4)	Net present value of future net revenue per reserve unit values are based on Pengrowth’s net reserves.

- 41 -

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 January 1, 2009 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		29.30 API		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)
2008(4)		99.48		103.44		93.74		75.54		8.16		57.82		76.91		104.46		—		—
2009		57.50		68.61		59.00		43.10		7.58		43.22		52.14		69.98		2.0		0.83
2010		68.00		78.94		68.68		49.76		7.94		49.73		61.57		80.52		2.0		0.85
2011		74.00		83.54		73.52		54.35		8.34		52.63		65.16		85.21		2.0		0.88
2012		85.00		90.92		80.01		59.23		8.70		57.28		70.92		92.74		2.0		0.93
2013		92.01		95.91		84.40		62.54		8.95		60.42		74.81		97.82		2.0		0.95
2014		93.85		97.84		86.10		63.82		9.14		61.64		76.32		99.80		2.0		0.95
2015		95.73		99.82		87.84		65.13		9.34		62.89		77.86		101.81		2.0		0.95
2016		97.64		101.83		89.61		66.46		9.54		64.15		79.43		103.87		2.0		0.95
2017		99.59		103.89		91.42		67.83		9.75		65.45		81.03		105.97		2.0		0.95
2018		101.59		105.99		93.27		69.22		9.95		66.77		82.67		108.10		2.0		0.95
Thereafter	+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr		+2%/yr			2.0		0.95

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 weighted average historical prices for 2008.

     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, 2008. 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

Hardisty

Cushing

Par Price

Medium

Heavy 12°

AECO Gas

Pentanes

Inflation

Exchange

Oklahoma

400 API

29.30 API

API

Price

Propane

Butane

Plus

Rate

Rate(2)

Year

($US/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/MMBtu)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

(%/Year)

($US/Cdn)

December 31, 2008

44.60

44.27

37.98

30.24

6.22

27.89

33.65

55.93

0.0

%

0.817

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, 2008, presented using forecast prices and costs. All reserves are located in Canada.

Reserves Reconciliation
By Principal 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
	(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)			(Mbbl)
December 31, 2007		92,817			31,180			123,997			16,898			4,883			21,781			21,677			7,185			28,862
Extensions		619			595			1,214			199			49			247			796			793			1,589
Infill Drilling		1,263			330			1,592			260			306			566			103			182			285
Improved Recovery		1,314			695			2,009			0			6,389			6,389			93			8			101
Technical Revisions		1,965			(2,349	)		(384	)		1,884			(179	)		1,705			1,885			(541	)		1,344
Discoveries		17			3			20			0			0			0			0			0			0
Acquisitions		1,182			394			1,576			0			0			0			2,282			1,251			3,533
Dispositions		(11	)		(3	)		(14	)		0			0			0			(10	)		(5	)		(15	)
Economic Factors		0			0			0			0			0			0			0			0			0
Production		(8,905	)		0			(8,905	)		(2,973	)		0			(2,973	)		(3,390	)		0			(3,390	)
December 31, 2008		90,261			30,846			121,107			16,268			11,448			27,716			23,436			8,873			32,309

	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, 2007		614,363			193,874			808,237			37,002			17,115			54,117			239,953			78,413			318,366
Extensions		11,009			13,457			24,466			1,298			2,284			3,582			3,665			4,061			7,726
Infill Drilling		8,885			1,187			10,072			0			0			0			3,106			1,015			4,122
Improved Recovery		339			(104	)		236			0			0			0			1,464			7,075			8,539
Technical Revisions		21,415			(13,230	)		8,185			(1,603	)		(4,440	)		(6,042	)		9,036			(6,014	)		3,022
Discoveries		622			295			917			0			0			0			120			52			173
Acquisitions		19,181			10,082			29,263			0			0			0			6,661			3,326			9,987
Dispositions		(1,185	)		(398	)		(1,583	)		0			0			0			(219	)		(74	)		(292	)
Economic Factors		0			0			0			0			0			0			0			0			0
Production		(83,216	)		0			(83,216	)		(3,678	)		0			(3,678	)		(29,751	)		0			(29,751	)
December 31, 2008		591,413			205,163			796,576			33,019			14,960			47,979			234,036			87,854			321,891

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.

- 43 -

At December 31 2008, Company Interest Total Proved Plus Probable Reserves at forecast prices and costs were 323.5 MMboe as compared to 319.9 MMboe reported at year end 2007 and 297.8 MMboe reported at year end 2006. The following additional GLJ reserves reconciliation is presented for year end December 31, 2008.

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, 2007		202,898			241,169			319,921
Extensions		3,805			3,689			7,762
Infill Drilling		3,766			3,109			4,125
Improved Recovery		873			1,464			8,539
Technical Revisions		13,346			9,244			3,264
Discoveries		0			120			173
Acquisitions		6,016			6,661			9,987
Dispositions		(114	)		(224	)		(299	)
Economic Factors		0			0			0
Production		(30,009	)		(30,009	)		(30,009	)
December 31, 2008		200,580			235,224			323,463

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 2008 production by 59 percent and 80 percent for Total Proved and Proved Plus Probable Reserves, respectively. Based on all changes, including acquisitions and dispositions, reserve replacement was 80 percent and 112 percent for Total Proved and Proved Plus Probable Reserves, respectively.

• New reserves of 20.6 MMboe added for development activity accounted for approximately 61 percent of the Total Proved Plus Probable Reserves additions in 2008. Most significant were the improved recovery addition for the proposed thermal project at Lindbergh, drilling extensions at Carson Creek and infill drilling and improved recover adds at Weyburn and Deer Mountain. Reserve increases in the Proved Producing category also resulted from reclassification of Proved and Probable Undeveloped Reserves primarily for infill drilling and drilling extensions at Monogram, Fenn Big Valley (CBM), Weyburn and Swan Hills.

• The net increase of 9.7 MMboe to Proved Plus Probable Reserves from acquisitions and dispositions was almost entirely from the acquisition of additional interests in Harmattan, a focus area for Pengrowth. Only some minor sales were made in 2008, disposing of small, isolated properties when opportunities arose.

• Various performance related revisions were made to previous estimates resulting in a net positive change. The largest revisions to Proved Plus Probable Reserves occurred at Judy Creek (+1,483 Mboe), Quirk Creek (+1,137 Mboe), Carson Creek (+892 Mboe) and Kidney (-641 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

- 44 -

next two to three years. Much of the remaining capital scheduled beyond this period is related to the Weyburn, Judy Creek and Swan Hills enhanced oil recovery projects, which have staged development plans.

Company Gross Reserves First Attributed by Year⁽¹⁾

Proved Undeveloped Reserves

	Light & Medium Oil				Heavy Oil				Natural Gas				Coal Bed Methane				Natural Gas Liquids				Total Oil Equivalent
	(Mbbl)				(Mbbl)				(MMcf)				(MMcf)				(Mbbl)				(Mboe)(2)
	First		Total at		First		Total at		First		Total at		First		Total at		First		Total at		First		Total at
	Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end
Prior		18,755		18,755		1,699		1,699		29,005		29,005		0		0		1,088		1,088		26,376		26,376
2006		1,766		17,352		295		1,891		16,088		44,198		3,955		3,955		421		1,439		5,822		28,708
2007		1,932		18,985		342		2,194		20,905		50,224		11,356		13,911		398		1,361		8,049		33,229
2008		1,000		17,029		382		1,676		3,513		48,311		1,858		10,372		125		1,120		2,402		29,606
Probable Undeveloped Reserves
	Light & Medium Oil				Heavy Oil				Natural Gas				Coal Bed Methane				Natural Gas Liquids				Total Oil Equivalent
	(Mbbl)				(Mbbl)				(MMcf)				(MMcf)				(Mbbl)				(Mboe)(2)
	First		Total at		First		Total at		First		Total at		First		Total at		First		Total at		First		Total at
	Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end
Prior		8,104		8,104		1,506		1,506		16,805		16,805		0		0		1,062		1,062		13,473		13,473
2006		2,577		11,350		507		1,586		19,510		56,662		4,306		4,306		531		2,151		7,585		25,248
2007		3,065		13,497		726		2,269		25,386		64,986		8,170		10,155		670		2,716		10,054		31,006
2008		1,850		12,372		6,997		7,857		17,686		68,822		4,514		7,948		782		3,478		13,329		36,502

Notes:
(1)	“First Attributed” refers to reserves first attributed at year-end of the corresponding fiscal year.
(2)	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.

ProvedUndeveloped Reserves

Pengrowth’s Proved Undeveloped Reserves comprise roughly 13 percent of the Total Proved Reserves on a barrel of oil equivalency basis. Pengrowth Interest Proved Undeveloped Reserves of 29.6 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.

Swan Hills miscible flood expansion, as well as some infill drilling, comprises roughly 17 percent of Pengrowth’s Proved Undeveloped Reserves. 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 2027. Similarly at Judy Creek, miscible flood development is forecast to continue until 2012 and accounts for another 16 percent of the Proved Undeveloped Reserves. In the Weyburn Unit, an additional 15 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 in Weyburn, from the existing 52 patterns to full development with 65 patterns in the proved case, is forecast to occur by 2011. Development of all 90 patterns in the probable case continues until 2015. Given that CO₂ injection is still in the early planning and pilot stages, no full scale CO₂ flooding is being forecasted at Judy Creek.

The Olds Gas Unit contains about eight percent of the total Proved Undeveloped Reserves assigned by GLJ relating to further infill drilling that is forecasted to occur until 2012 in the proved reserve case and 2013 in the Proved Plus Probable reserve case. Multi-well shallow gas infill drilling programs are scheduled for 2009 and beyond at Jenner and Monogram, which together contain seven percent of the Total Proved Undeveloped Reserves. At Deer Mountain, waterflood optimization and infill drilling scheduled over the next three years accounts for about six percent of the Proved Undeveloped Reserves. Pengrowth’s ongoing CBM development requires further drilling extensions at Twining and Fenn Big Valley. Because of the extensive land holdings, this

- 45 -

is forecast to occur over the next three years and represents approximately five percent of the Total Proved Undeveloped Reserves. The east coast offshore Sable Island area contains roughly four percent of the Total Proved Undeveloped Reserves and is attributed to one remaining well to be drilled at Alma in 2009 and completion of new sands at Venture. Ongoing development is scheduled in heavy oil properties where approximately four 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.

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 36.5 MMboe and represent about 11 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: Lindbergh (17 percent), Olds Gas Unit (14 percent), Weyburn Unit (14 percent), Swan Hills Unit (seven percent), Judy Creek Units (four percent), Carson Creek (five percent), Deer Mountain (three percent), Fenn Big Valley and Twining CBM (three percent) and Harmattan (three percent). At Lindbergh, Probable Undeveloped Reserves are assigned to a proposed oil sands SAGD pilot project. Facility design and procurement, delineation drilling and other development work is underway with completion planned for 2011.

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 ten percent per annum for the years indicated. All of such development costs are estimated to be incurred in Canada.

													Total
															Discounted
	2009		2010		2011		2012		2013		Remainder		Undiscounted		at 10%
Reserve Category	($MM)		($MM)		($MM)		($MM)		($MM)		($MM)		($MM)		($MM)
Proved Reserves		157		146		61		30		19		111		524		402
(Constant Prices and Costs)
Proved Reserves		157		149		63		32		21		157		579		422
(Forecast Prices and Costs)
Proved & Probable Reserves		220		283		204		46		36		220		1,009		748
(Forecast Prices and Costs)

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 $209 million development capital expenditure program for 2009 to fund its land acquisition, development and exploration activities, including expenditures at its proposed Lindbergh oil sands SAGD pilot project.

Finding, Development and Acquisition Costs

Finding and Development Costs

During 2008, Pengrowth spent $388 million on development and optimization activities, which added 17.6 MMboe of Proved Reserves and 23.9 MMboe of Total Proved Plus Probable Reserves including revisions. The largest additions were for the proposed Lindbergh SAGD pilot project (6.3 MMboe), drilling extensions at Carson Creek, Fenn Big Valley and Harmattan, infill drilling and improved recovery at Weyburn and Deer Mountain and infill drilling at Monogram.

In total, Pengrowth participated in drilling 507 gross wells (217 net wells) with a 96 percent success rate.

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At Judy Creek, infill drilling and ongoing development and optimization of the waterflood and 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.

Further development occurred in the Carson Creek BHL Units during 2008. After shooting a 3D seismic program over the oil Unit in 2007, three new producers were drilled and optimization of the waterflood continues. In the gas Unit, three new gas wells were drilled in a region of the pool not currently being drained by existing wells.

Further development and optimization occurred in the Weyburn field in southeast Saskatchewan. A large infill drilling program was carried out in 2008 along with new pattern development in the CO₂ miscible flood project area. In all, 34 horizontal infill producers and eight injectors were drilled in the waterflood and miscible flood areas.

In 2008, Pengrowth participated in a total of 60 Horseshoe Canyon CBM wells in the Twining, Lone Pine Creek, Three Hills Creek and Fenn Big Valley areas of southern Alberta. In addition, Pengrowth drilled and completed its second and third horizontal Mannville CBM wells in Fenn Big Valley during 2008. With the success of these first three wells, more Mannville CBM drilling is planned at Fenn Big Valley.

Additional delineation of the Lindbergh oil sands pool was conducted with the drilling of four core holes in the vicinity of the proposed SAGD pilot project area. A significant portion of the engineering design was also completed for the pilot facilities and well pairs.

Various other multi-well infill drilling programs were conducted during 2008 to increase production and maximize recoveries. In the heavy oil areas, nine wells, both vertical and horizontals, were drilled in Jenner and a total of 13 horizontal wells were drilled in the Cosine, Cactus Lake and Tramping Lake areas. Ongoing shallow gas development occurred with multi-well infill programs at Three Hills/Twining and Monogram (151 wells). In the Dunvegan Gas Unit, another nine infill wells were drilled. Development drilling and facility optimization occurred in the Olds/Harmattan gas area. Other light oil development occurred with infill drilling programs at Fenn Big Valley (six Nisku wells) and Deer Mountain (two BHL wells).

Acquisitions and Divestitures

Pengrowth made strategic acquisitions during 2008 aimed at increasing ownership in existing core areas. Pengrowth spent $148.2 million on acquisitions adding 6.7 MMboe of Proved and 10.0 MMboe of Proved Plus Probable Reserves. Total proceeds from minor dispositions of small, isolated properties and undeveloped acreage during 2008 was $17.4 million, resulting in a decrease of 0.2 MMboe Proved and 0.3 MMboe Proved Plus Probable Reserves.

In September 2008, Pengrowth closed the acquisition of Accrete Energy Inc. Along with another small asset acquisition, this expanded Pengrowth’s operations in the southern Alberta Harmattan area. Pengrowth also increased its interests in the core Judy Creek area by acquiring additional ownership in existing assets at Carson Creek and Swan Hills.

Future Development Capital

NI 51-101 requires that the calculation of finding and development costs include changes in forecasted future development costs (“FDC”) relating to the reserves. FDC reflects 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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2008 Finding, Development and Acquisition Costs
Company Interest Reserves
(Forecast Prices and Costs)

			Proved plus
	Proved		Probable
FD&A Costs Excluding Changes in Future Development Capital
Exploration and Development Capital Expenditures ($M)	$	388,300	$	388,300
Exploration and Development Reserve Additions including Revisions (Mboe)		17,627		23,863
Finding and Development Cost ($/boe)	$	22.03	$	16.27
Net Acquisition Capital ($M)	$	130,795	$	130,795
Net Acquisition Reserve Additions (Mboe)		6,437		9,688
Net Acquisition Cost ($/boe)	$	20.32	$	13.50
Total Capital Expenditures including Net Acquisitions ($M)	$	519,095	$	519,095
Reserve Additions including Net Acquisitions (Mboe)		24,064		33,551
Finding Development and Acquisition Cost ($/boe)	$	21.57	$	15.47
FD&A Costs Including Changes in Future Development Capital
Exploration and Development Capital Expenditures ($M)	$	388,300	$	388,300
Exploration and Development Change in FDC ($M)	$	12,000	$	180,000
Exploration and Development Capital including Change in FDC ($M)	$	400,300	$	568,300
Exploration and Development Reserve Additions including Revisions (Mboe)		17,627		23,863
Finding and Development Cost ($/boe)	$	22.71	$	23.82
Net Acquisition Capital ($M)	$	130,795	$	130,795
Net Acquisition FDC ($M)	$	1,000	$	10,000
Net Acquisition Capital including FDC ($M)	$	131,795	$	140,795
Net Acquisition Reserve Additions (Mboe)		6,437		9,688
Net Acquisition Cost ($/boe)	$	20.47	$	14.53
Total Capital Expenditures including Net Acquisitions ($M)	$	519,095	$	519,095
Total Change in FDC ($M)	$	13,000	$	190,000
Total Capital including Change in FDC ($M)	$	532,095	$	709,095
Reserve Additions including Net Acquisitions (Mboe)		24,064		33,551
Finding Development and Acquisition Cost including change in FDC ($/boe)	$	22.11	$	21.14

Notes:
(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.
(2)	The Proved plus Probable values for “Exploration and Development Reserve Additions including Revisions” and for “Reserve Additions including Net Acquisitions” includes 6,345 Mboe for the proposed Lindbergh oil sands SAGD pilot project. The 2008 costs associated with the Lindbergh project were $20 million and the change in future development costs, in addition to the 2008 costs, is $123 million. If the Lindbergh SAGD pilot project reserves and the associated 2008 and future development costs were excluded, Pengrowth’s 2008 finding, development and acquisition costs, including the change in FDC, would be $20.81 per boe on a Proved plus Probable basis. These Reserves and costs are only associated with the pilot area; please see “ —Lindbergh Oil Sands Reserves and Contingent Resources” for additional information.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Other Oil and Gas Information

Oil and Gas Wells

As at December 31, 2008 Pengrowth had an interest in 10,128 gross (5,286 net) producing oil and natural gas wells and 1,552 gross (926 net) non-producing oil and natural gas wells.

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	Producing				Non-Producing
	Gross		Net		Gross		Net
Crude Oil Wells
Alberta		2,449		1,559		468		282
British Columbia		154		108		46		43
Saskatchewan		1,181		295		176		81
Nova Scotia		0		0		0		0
Natural Gas Wells
Alberta		5,881		2,963		527		287
British Columbia		118		76		22		15
Saskatchewan		52		49		87		47
Nova Scotia		19		1		0		0
Other(1)
Alberta		252		222		158		109
British Columbia		0		0		46		43
Saskatchewan		22		11		22		19
Total		10,128		5,286		1,552		926

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, 2008 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, 2008

					Maximum Net Acres Expected to
Location	Gross Acres		Net Acres		Expire During 2009
Alberta		974,083		656,192		92,591
British Columbia		279,222		153,748		15,948
Ontario		4,776		—		—
Saskatchewan		64,145		53,522		1,920
Nova Scotia		200,650		15,957		—
Total		1,522,876		879,419		110,459

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.

Lindbergh Oil Sands Reserves and Contingent Resources

The Lindbergh oil sands property is located approximately 420 kilometers northeast of Calgary and 65 kilometers southwest of Cold Lake. Pengrowth holds a 100 percent Working Interest in this oil sands asset where oil quality averages 11°API. The Upper Lloydminster and Lower Rex are the targeted formations. These formations contain bitumen-saturated sands up to 23 meters thick at approximately 500 meters depth.

Pengrowth is planning to start a pilot that is the basis for the Probable and Probable plus Possible Reserves. In addition, there are Contingent Resources for the area surrounding the pilot. An evaluation of the Contingent Resources for Lindbergh has been completed by GLJ as at December 31, 2008. The evaluation was limited to reservoir amenable to steam assisted gravity drainage (SAGD). The project’s profitability is sensitive to oil prices. Using GLJ’s price forecast, the project is forecast to be profitable. However, using the constant price forecast, the project is uneconomic and would not be developed.

The tables below summarize the estimated volumes of reserves and Contingent Resources attributable to the Lindbergh property based upon GLJ’s forecast prices and costs, before royalties. The estimates are in accordance with the definitions and guidelines in the COGE Handbook and NI 51-101. Please note that reserves and Contingent Resources involve different risks associated with achieving commerciality. Under the fiscal

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conditions, including commodity price and cost assumptions, applied in the estimation of reserves, the likelihood that a project will achieve commerciality is effectively 100 percent, whereas the likelihood of a Contingent Resource achieving commerciality may be less than 100 percent.

The Probable Reserves have been assigned within the region of the proposed pilot well development using forecast prices and costs. Probable and Possible Reserves have been assigned to this same pilot area as well as a previously delineated region offsetting the pilot. No reserves or Contingent Resources have been assigned using constant prices and costs.

Pilot Project Probable and Probable
plus Possible Reserves and Net Present Value of Future Net Revenue
as of December 31, 2008
(Forecast Prices and Costs)

				Probable plus
	Probable Reserves			Possible Reserves(1)
Reserves (Mbbl)		6,345			35,695
Before tax net present value of future net revenue
0 % discount rate ($MM)	$	85.7		$	1,071.2
5% discount rate ($MM)	$	35.5		$	298.6
10% discount rate ($MM)	$	4.6		$	96.6
15% discount rate ($MM)	$	(14.7	)	$	24.6
20% discount rate ($MM)	$	(26.6	)	$	(7.5	)

Note:
(1)	GLJ has estimated our undiscounted capital to be $327 million and the 10 percent discounted capital amount to be $129 million to develop the Proved plus Probable Reserves.

Contingent Resources have been assigned to the remaining areas of the reservoir within the property that meet certain minimum criteria. In order to be classified as a Contingent Resource, a technically feasible recovery project must be defined. These Contingent Resources are expected to be economic to develop. The reclassification of these Contingent Resources as reserves is contingent upon further reservoir studies, delineation drilling, facility design, preparation of firm development plans, regulatory applications and company approvals. However, there is no certainty that it will be commercially viable to produce any portion of the Contingent Resource.

	December 31, 2008
	Contingent Resources(1)
	(MMbbl)
Low estimate(2)		144.2
Best estimate(3)		194.2
High Estimate(4)		264.1

Notes:
(1)	Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. The contingencies may include factors such as economics, legal, environmental, political, regulatory or lack of markets. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates.
(2)	A low estimate is a conservative estimate of the quantity of oil that will be recovered from the accumulation, which under probabilistic methodology reflects a 90 percent confidence level.
(3)	A best estimate is a best estimate of the quantity of oil that will be recovered from the accumulation, which under probabilistic methodology reflects a 50 percent confidence level.
(4)	A high estimate is an optimistic estimate of the quantity of oil that will be recovered from the accumulation, which under probabilistic methodology reflects a 10 percent confidence level.

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The accuracy of resource estimates is in part a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. These resource volumes are classified as a resource rather than a reserve contingent upon further reservoir studies, delineation drilling and facility design, preparation of firm development plans, regulatory applications and company approvals. The size of the resource estimate could be positively impacted, potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the interpretation of seismic and well control. The size of the resource estimate could be negatively impacted, potentially in a material amount, if additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic and well control.

Forward Contracts

Pengrowth may use financial derivatives or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. A description of such instruments is provided in Pengrowth’s annual financial statements and related management’s discussion and analysis for the year ended December 31, 2008, which may be found on SEDAR at www.sedar.com.

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 GLJ’s estimate of future net revenue.

Pengrowth has estimated the net present value (discounted at ten percent per annum) of its total asset retirement obligations to be approximately $257 million as at December 31, 2008, based on a total future liability (inflated at two percent per annum) of approximately $2,283 million. These costs are anticipated to be paid over 50 years with the majority of the costs incurred between 2039 and 2054.

The following tables summarize Pengrowth’s total asset retirement obligations as at December 31, 2008:

Asset Retirement Obligations

	2009		2010		2011		Remainder		Total
	($M)		($M)		($M)		($M)		($M)
Total Abandonment, Reclamation, Remediation & Dismantling		14,176		14,828		17,168		2,236,964		2,283,136
Discounted at ten percent		13,516		12,853		13,528		215,725		256,622

GLJ’s Proved Producing reserve evaluation includes $182 million ($67 million when discounted at ten percent) of the asset retirement obligations in the above table. The number of net wells to which this asset retirement obligation applies is found under the heading “- Other Oil and Gas Information — Oil and Gas Wells”.

Costs Incurred

The following table outlines property acquisition, exploration and development costs incurred during the financial year ended December 31, 2008. These costs include only those costs which are cash or cash equivalent.

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	Amount
Nature of Cost	($M)
Acquisition Costs(1)
Proved		126,022
Unproved		—
Exploration Costs		22,012
Development Costs		366,300
Total		514,334

Note:
(1)	Based on the values assigned to property, plant and equipment in the purchase price allocations for the Accrete acquisition and for several minor property acquisitions

Exploration and Development Activities

The following table summarizes the number of wells completed or determined to be dry during the financial year ended December 31, 2008.

	Development				Exploration				Total
Wells	Gross		Net		Gross		Net		Gross		Net
Gas		371		142.4		8		4.8		379		147.2
Oil		90		47.3		3		1.3		93		48.6
Service		16		6.2		—		—		16		6.2
Dry		14		12.1		5		3.1		19		15.2
Total		491		208.0		16		9.2		507		217.2

Production Estimates

The following tables summarize the 2009 average daily volume of gross production estimated by GLJ for all properties held on December 31, 2008 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 2009 production to be between 76,000 and 78,000 boepd.

	2009 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)		23,615		24,500		23,615		24,502
Heavy Oil (bblpd)		6,971		7,274		6,971		7,279
Natural Gas (Mcfpd)		233,518		245,958		233,547		246,008
Natural Gas Liquids (bblpd)		10,052		10,609		10,051		10,609
Total (boepd)		79,558		83,376		79,562		83,391

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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:

													Year
	Quarter Ended												Ended
	March 31,			June 30,			September			December			December
	2008			2008			30, 2008			31, 2008			31, 2008
Light Crude Oil
Average Daily Oil Production(1) (bblpd)		25,103			25,052			23,286			24,236			24,416
Sales Price (after realized commodity price risk management) ($/bbl)		79.38			83.88			82.00			65.87			77.78
Processing and other income ($/bbl)		0.67			1.10			1.46			0.04			0.81
Royalties ($/bbl)		(15.44	)		(17.52	)		(20.10	)		(14.02	)		(16.73	)
Amortization of injectants ($/bbl)		(3.40	)		(2.50	)		(3.05	)		(2.64	)		(2.90	)
Production Costs(2) ($/bbl)		(16.03	)		(16.89	)		(15.05	)		(15.05	)		(15.77	)
Operating Netback ($/bbl)		45.18			48.07			45.26			34.20			43.19
Heavy Oil
Average Daily Oil Production(1) (bblpd)		7,740			8,242			8,287			8,217			8,122
Sales Price ($/bbl)		62.74			100.34			96.93			42.20			75.77
Processing and other income ($/bbl)		0.27			0.70			0.02			0.29			0.32
Royalties ($/bbl)		(9.18	)		(15.07	)		(15.87	)		(1.95	)		(10.54	)
Production Costs(2) ($/bbl)		(12.34	)		(11.60	)		(13.17	)		(12.77	)		(12.47	)
Operating Netback ($/bbl)		41.49			74.37			67.91			27.77			53.08
NGLs
Average Daily NGL Production(1) (bblpd)		9,666			8,596			8,361			10,634			9,315
Sales Price ($/bbl)		66.96			92.25			87.06			43.87			70.67
Royalties ($/bbl)		(23.45	)		(38.77	)		(32.22	)		(12.27	)		(25.74	)
Production Costs(2) ($/bbl)		(12.28	)		(16.36	)		(14.62	)		(12.93	)		(13.93	)
Operating Netback ($/bbl)		31.23			37.12			40.22			18.67			31.00
Natural Gas
Average Daily Gas Production(1) (Mcfpd)		241,208			234,028			246,287			241,709			240,825
Sales Price after realized commodity price risk management) ($/Mcf)		7.72			9.40			8.29			7.40			8.19
Processing and other income ($/Mcf)		0.28			0.59			0.72			0.36			0.49
Royalties ($/Mcf)		(1.64	)		(2.06	)		(2.19	)		(1.62	)		(1.88	)
Production Costs(2) ($/Mcf)		(2.13	)		(2.49	)		(2.42	)		(2.29	)		(2.33	)
Operating Netback ($/Mcf)		4.23			5.44			4.40			3.85			4.47
Barrels of Oil Equivalent Basis(3)
Average Daily Production(1) (boepd)		82,711			80,895			80,981			83,373			81,991
Sales Price after realized commodity price risk management) ($/boe)		60.30			73.21			67.71			50.34			62.76
Processing and other income ($/boe)		1.06			2.10			2.61			1.09			1.71
Royalties ($/boe)		(13.05	)		(17.05	)		(17.39	)		(10.51	)		(14.46	)
Amortization of injectants ($/boe)		(1.03	)		(0.77	)		(0.88	)		(0.77	)		(0.86	)
Production Costs(2)($/boe)		(13.66	)		(15.34	)		(14.57	)		(13.92	)		(14.37	)
Operating Netback ($/boe)		33.62			42.15			37.48			26.23			34.78

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.

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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.

Before Tax Net Asset Value (NAV) at December 31, 2008

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 the forecast prices and costs shown under the heading “ -Pricing Assumptions”.

	Undiscounted			5% Discount			10% Discount			15% Discount			20% Discount
	Amount			Rate			Rate			Rate			Rate
(amounts in $MM except for NAV per Trust Unit)
Undeveloped Lands(1)		210
Working Capital Deficit(2)		(68	)
Reclamation Funds		27
Long Term Debt		(1,697	)
Fair Value of Risk Management Contracts(3)		146
Other Liabilities(4)		(85	)
Asset Retirement Obligations(5)		(196	)
Total Other Assets and Liabilities		(1,663	)		(1,663	)		(1,663	)		(1,663	)		(1,663	)
Value of Total Proved Plus Probable Reserves(6)		11,909			7,660			5,582			4,373			3,589
Total Net Asset Value		10,246			5,997			3,919			2,710			1,926
NAV per Trust Unit	$	40.01		$	23.42		$	15.30		$	10.58		$	7.52
(256.1 million Trust Units outstanding as at December 31, 2008)

Notes:
(1)	Pengrowth’s internal estimate, calculated using the average land sale prices paid in 2008 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, 2008.
(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.
(6)	Future net revenue prior to provisions for income tax, interest costs or general and administrative costs.

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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. An unlimited number of Trust Units, class A trust units and special units may be created and issued pursuant to the Trust Indenture, of which 256,075,997 Trust Units and 1,888 class A trust units are issued and outstanding as at December 31, 2008. There are presently no special units outstanding. Each Trust Unit, class A trust unit and special 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, class A trust units and special 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, class A trust units and special 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, class A trust units and special units and issuing Trust Units, class A trust units and special 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. Special units are not listed or posted for trading on the facilities of any stock exchange.

Ownership Restrictions

There are no restrictions on the ownership of the Trust Units or the special 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 and 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 and 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 and 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. The special units are redeemable by the holder thereof, when properly endorsed for transfer and when accompanied by a duly completed and properly executed notice, at a redemption price determined by the Board of Directors.

Conversion Rights

There are no conversion rights attached to the Trust Units or the special 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 five percent of the aggregate number of Trust Units, class A trust units and special 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, class A trust unit and special 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 five percent of the aggregate number of Trust Units, class A trust units and special 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;

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(iv) the approval of subdivisions or consolidations of Trust Units, class A trust units and special 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.

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, class A trust units and special units, in the aggregate; or (ii) if the Trust Units, the class A trust units and the special 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 five percent of the issued and outstanding Trust Units, class A trust units and special 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 132,305,583 Royalty Units were issued and outstanding as at December 31, 2008. 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. 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 percent of gross revenue, determined by the Corporation 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 or periods. Any amounts remaining in the reserve when there are no longer any properties that are subject to the royalty, and all of

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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 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

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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

On December 18, 2008, the monthly distributions were reduced from $0.225 per Trust Units to $0.17 per Trust Unit and the Board of Directors approved a reduced capital program of $215 million in direct response to substantial declines in commodity prices in late 2008. A further reduction in distributions to $0.10 was announced on February 19, 2009 commencing with the March 16, 2009 distribution. The Board of Directors’ stated objective in making the further reduction in distributions was exercising financial prudence in uncertain times. Based upon forward strip pricing at the time of the announcement, Pengrowth anticipates funding substantially all of its 2009 capital program and distributions from cash flow from operations, leaving flexibility to pursue more acquisition and consolidation opportunities. 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 commodity prices, production rates, proposed capital expenditures, Pengrowth’s level of indebtedness and our ability to access equity and debt capital. 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 provide assurance that cash flow will be available for distribution to Unitholders in the amounts anticipated or at all. See“Risk Factors”.

Distributions declared in 2008 and for the preceding five fiscal years were as follows:

	2008		2007		2006		2005		2004		2003
First Quarter	$	0.675	$	0.75	$	0.75	$	0.69	$	0.63	$	0.75
Second Quarter		0.675		0.75		0.75		0.69		0.64		0.67
Third Quarter		0.675		0.75		0.75		0.69		0.67		0.63

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	2008		2007		2006		2005		2004		2003
Fourth Quarter		0.565		0.675		0.75		0.75		0.69		0.63
Total	$	2.59	$	2.93	$	3.00	$	2.82	$	2.63	$	2.68

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:

	2008			2007			2006			2005			2004			2003
Taxable Income(1) (per Trust Unit)	$	2.70		$	2.78		$	2.40		$	2.22		$	1.43		$	1.47
(percent of distributions classified as taxable income)		(100	%)		(95	%)		(80	%)		(80	%)		(55	%)		(55	%)

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 the Trust intends to make distributions of a portion of its available cash, these cash distributions may be reduced or suspended.Cash distributions are not guaranteed.The ability to make cash distributions and the actual amount distributed will depend on numerous factors including, among other things: its 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 its inability to meet Pengrowth’s 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 Pengrowth operates, and therefore the stability of the distributions they would receive. See “Risk Factors”. This section also describes Pengrowth 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, which are also incorporated by reference in the agreement relating to the $50 million demand operating line of credit; (ii) the note purchase agreements relating to the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes, the 2008 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;

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	•   depreciation, depletion and amortization expense; and
	•   other non-cash amounts.
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, the 2008 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, the 2008 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, the 2008 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 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, the 2008 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 and the 2008 Senior Notes, 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.

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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.
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, 2008, 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 “Certain Canadian Federal Income Tax Considerations — Taxation of Unitholders who are Non-Residents of Canada” 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;

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• 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 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, 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 rate applicable to the Trust is expected to be 26.5 percent in 2011 and 25 percent in 2012, assuming a provincial tax rate of 10 percent being the applicable tax rate in the Province of Alberta where we anticipate 79 percent of our revenue will be generated in 2009. 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.

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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.

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, 2008.

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 $672 million. Accordingly, Pengrowth may currently issue additional equity without offending the Normal Growth Guidelines of approximately $2.208 billion, and may issue approximately $960 million of additional equity for each of 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. On November 28, 2008, Finance introduced further technical amendments to the SIFT Legislation in the form of a notice of ways and means motion. Under these technical amendments, the Normal Growth Guidelines are being revised to accelerate a Grandfathered SIFT’s “safe harbour” amount for each of 2009 and 2010 so that it is available on November 28, 2008. Although this change does not increase the maximum available growth of a Grandfathered SIFT under the Normal Growth Guidelines, the change allows a Grandfathered SIFT to use the remaining growth in a single year rather than staging it over 2009 and 2010.

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

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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, deferred profit sharing plans and tax-free savings accounts as defined in the Tax Act (referred to herein as “Exempt Plans”) will generally continue not to be liable for tax in 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 came into force on December 15, 2008, when the two countries formally notified each other that their procedures were 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 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 will apply to distributions commencing on January 1, 2010. 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

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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.

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 has and will continue 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,

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(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 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. 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 to Pengrowth and its Unitholders. As circumstances, including, without limitation, applicable tax laws and tax treaties, change, we will continue to evaluate if such an election would be beneficial, including, without limitation, as a result of any potential tax efficiency in the payment of distributions to United States holders.

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 “— 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 2009 and thereafter. However, no assurance can be given that the qualifying income exception will in fact be met.

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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) or we elect under applicable Treasury Regulations to be treated as a corporation for United States federal income tax purposes, 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 or on the effective date of an election to be treated as a corporation for United States federal income tax purposes) 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.

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 (regardless of whether we continue to be a PFIC), the United States holder would generally be subject to special adverse rules including taxation at maximum ordinary income rates plus an interest charge on both gains on sale and certain dividends, unless the United States holder makes an election to be taxed under an alternative regime. In addition, any dividends will not be qualifying dividends, and will not be eligible for the reduced rate that currently applies to certain dividends received by United States holders that are not corporations.

While the Trust is treated as a partnership for United States federal income tax purposes, a United States holder would 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 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.

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

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 “— 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 “— 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 “— 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 “— 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.

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

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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.

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.

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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.

Royalties

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. 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, geographic 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.

Alberta

Royalties payable pursuant to petroleum and natural gas leases with the Government of Alberta are ad valorem royalties, calculated using the oil or natural gas price and the amount of monthly production.

The Government of Alberta changed the royalty rates effective January 1, 2009. The Province has two different royalty programs: the New Royalty Framework and Transitional Royalties.

The New Royalty Framework establishes new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the new royalty framework, the formula for conventional oil and natural gas royalties uses a sliding rate formula, dependant on the market price and production volumes. Royalty rates for conventional oil range from zero percent to 50 percent. Natural gas royalty rates range from 5 percent to 50 percent. Propane and butanes will have fixed royalty rates of 30 percent, whereas pentanes plus will have a fixed royalty rate of 40 percent. The sulfur royalty rate remains unchanged at 16²/₃ percent.

In November 2008, the Alberta Government announced that companies drilling new natural gas and conventional oil wells at depths between 1,000 and 3,500 metres, which are spudded between November 19, 2008 and December 31, 2013, will have a one-time option of selecting new Transitional Royalty rates or the New Royalty Framework rates. The transition option provides lower royalties in the initial years of a well’s life. For example, under the transition option, royalty rates for natural gas wells will range from 5 percent to 30 percent. The election must be made prior to the end of the first calendar month in which the leased substance is produced. All wells using the Transitional Royalty rates must shift to the New Royalty Framework rates on January 1, 2014.

The Deep Oil Exploration Program (“DOEP”) and the Natural Gas Deep Drilling Program (“NGDDP”) are new programs that began January 1, 2009. These programs provide upfront royalty adjustments to new wells. To qualify for such royalty adjustments under the DOEP, exploration wells must have a vertical depth greater than

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2,000 meters with a Crown interest and must be spudded after January 1, 2009. These oil wells qualify for a royalty exemption on either the first $1,000,000 of royalty or the first 12 months of production. The NGDDP applies to wells producing at a true vertical depth greater than 2,500 meters. The NGDDP will have an escalating royalty credit in line with progressively deeper wells from $625 per meter to a maximum of $3,750 per meter. There are additional benefits for the deepest wells. Both the DOEP and the NGDDP are five year programs. Any wells spud after December 31, 2013, or any wells that choose the transition option, will not qualify under either program. No royalty adjustments will be granted under either the DOEP or the NGDDP after December 31, 2018.

Approximately 79 percent of Pengrowth’s Company Interest production forecast for 2009 is in the Province of Alberta.

British Columbia

The British Columbia natural gas royalty regime is price sensitive, using a “select price” as a parameter in the royalty rate formula. When the reference price, being the greater of the producer price or the Crown set posted minimum price (“PMP”), is below the select price, the royalty rate is fixed. The rate increases as prices increase above the select price. The Government of British Columbia determines the producer prices by averaging the actual selling prices for gas sales with shared characteristics for each company minus applicable costs. If this price is below the PMP, the PMP will be the price of the gas for royalty purposes.

Natural gas is classified as either “conservation gas” or “non-conservation gas”. There are three royalty categories applicable to non-conservation gas, which are dependent on the date on which title was acquired from the Crown and on the date on which the well was drilled. The base royalty rate for non-conservation gas ranges from 9 percent to 15 percent. A lower base royalty rate of 8 percent is applied to conservation gas. However, the royalty rate may be reduced for low productivity wells.

The royalty regime for oil is dependent on age and production. Oil is classified as “old”, “new” or “third tier” and a separate formula is used to determine the royalty rate depending on the classification. The rates are further varied depending on production. Lower royalty rates apply to low productivity wells and third tier oil to reflect the increased cost of exploration and extraction. There is no minimum royalty rate for oil.

Approximately six percent of Pengrowth’s Company Interest production forecast for 2009 is in the Province of British Columbia.

Saskatchewan

Crown royalty rates are sensitive to the individual productivity of each well. The rates are applied to the respective portions of each classification of gas (“fourth tier gas”, “third tier gas”, “new gas” and “old gas”) produced from a well.

Each month, the royalty rates are adjusted based on the level of the Provincial Average Gas Price (“PGP”) established by the Province monthly. The PGP represents the weighted average fieldgate price (expressed in $/10³m³) received by producers during the month for the sale of all gas subject to royalty. Crown royalty of the production volume is calculated on each individual well using the applicable royalty rate to the volume of gas produced by each well on a monthly basis.

The operator must elect to use either the PGP or the Operator Average Gas Price (“OGP”) for purposes of valuing the Crown’s royalty share of the production volume from each well. The OGP is determined each month by the operator and represents the weighted average fieldgate price ($/10³m³) received by the operator for sales of gas during the month. The Crown royalty share is calculated by multiplying the Crown royalty volume determined for each well by the wellhead value of the gas for the month.

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Crown royalty rates are sensitive to the individual productivity of each well and the type of oil produced from the well. Each month, royalty rates are adjusted based on the level of the reference price established by the Province for each type of oil.

For Crown royalty purposes, crude oil is classified as “heavy oil”, “southwest designed oil” or “non-heavy oil other than southwest designated oil”. There are separate reference prices established for each type of oil which represent the average wellhead price (in $/m³) received by producers during the month for sales of that oil type in Saskatchewan.

The Crown royalty share of production volume is calculated on each individual well using the applicable royalty rate to the volume of oil produced from the well each month. The Crown royalty share is calculated by multiplying the Crown royalty volume determined for each well by the wellhead value of the oil for the month.

A separate cost sensitive royalty structure applies to incremental production from enhanced oil recovery projects, which incorporates lower royalty and freehold production tax rates before the project reaches payout of investment and operating expenditures.

Approximately seven percent of Pengrowth’s Company Interest production forecast for 2009 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 based on revenues and profits. 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 and offers lower royalties for a first project in a new area, being a “high risk project”. 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 eight percent of Pengrowth’s Company Interest production forecast for 2009 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.

Climate Change

Federal

Canada is a signatory to the United Nations Framework Convention on Climate Change. The Canadian federal government has indicated an intention to regulate emissions of industrial greenhouse gas (“GHG”) emissions from a broad range of industrial sectors in theRegulatory Framework for Air Emissionsreleased April 26, 2007 (the “Framework”) and updated in a March 10, 2008 document entitledTurning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions (collectively, the “Federal Plan”). The Federal Plan outlines proposed policies to reduce GHG emissions intensity of regulated facilities starting January 2, 2010. New facilities will face intensity reduction requirements, beginning in their fourth year of commercial production, of 2 percent per year from their ‘baseline’ emissions intensity (e.g. the emissions intensity of their third year of commercial production)

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until at least 2020. Targets will be based on a “cleaner fuel standard” (i.e. the use of natural gas as a fuel) for new facilities commencing production before 2012, although new facilities commencing production in 2012 or later that are built “carbon-capture ready” will not need to meet the cleaner fuel standard until 2018. Compliance options under the Federal Plan include: making emissions intensity improvements, making investments in certified carbon capture and storage projects (until 2018), buying offsets or emissions performance credits, and, for a portion of each entity’s emissions reduction obligations (the portion would start at 70 percent and decline to zero percent in 2018), making payments of $15/ton until 2012, then $20 or more/ton, to the federal technology fund.

The Canadian federal government currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs and industrial air pollutants, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. Further, since the 2008 U.S. presidential elections, announcements from the Canadian federal government indicate an interest in creating a North American cap and trade system with “hard caps” on emissions from facilities rather than emissions intensity limits. No assurance can be given that either a modified Federal Plan or a North American cap and trade system will or will not be implemented, or what obligations might be imposed under any such system.

The Framework also outlines proposed requirements by the Canadian federal government governing the emission of industrial air pollutants starting in 2010. Proposed compliance mechanisms include fixed emission caps and an emissions credit trading system for certain industrial air pollutants, as well as several options from which companies may choose to meet GHG emission reduction targets. The current status of these proposals is unclear. The Canadian federal government currently imposes reporting obligations under theCanadian Environmental Protection Act, 1999for facilities that create GHG emissions over 100,000 tons in any year.

As the details of the implementation of any federal legislation for GHGs or industrial pollutants have not been announced, the effect on Pengrowth’s operations cannot be determined at this time.

Alberta

Alberta regulates GHG emissions under theClimate Change and Emissions Management Act, theSpecified Gas Reporting Regulation(the “SGRR”), which imposes GHG emissions reporting requirements, and theSpecified Gas Emitters Regulation(the “SGER”) which imposes GHG emissions limits. Under the SGRR, Pengrowth must report if it has GHG emissions of 100,000 tonnes or more from a facility in any year. Currently, only two facilities exceed this criteria: the Judy Creek Gas Conservation Plant and the Olds Gas Plant. Under the SGER, GHG emission limits apply once a facility has direct GHG emissions in a year of 100,000 tonnes or more. Under the SGER, any facility coming into commercial production after 2000 will be considered a new facility and will be required to reduce its emission intensity (e.g. tonnes of GHGs emitted per unit of production) by 2 percent per year beginning in its fourth year of commercial operation, up to an aggregate 12 percent reduction from the emissions intensity level of its third year of commercial operation. The SGER permits Pengrowth to meet the applicable emission limits by making emissions intensity improvements at facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring ‘fund credits’ by making payments of $15/per tonne to the Alberta Climate Change and Management Fund. The Alberta government recently announced its intention to raise the price of fund credits and increase the required reductions in GHG emissions intensity to unspecified levels. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations imposed in permits and under environmental regulations. Under the Alberta regulations, if the emissions remain at current levels, Pengrowth would be required to purchase “off-setting” credits of up to $500,000 from Alberta Environment. In 2008, Pengrowth spent $111,855 on purchasing “off-setting” credits for the Olds Gas Plant. The Judy Creek Gas Conservation Plant did not need to purchase “off-setting” credits as it had a surplus of carbon credits.

British Columbia

The Province of British Columbia intends to reduce its GHG emissions to 33 percent below 2007 levels by 2020 and has set interim targets of 6 percent below 2007 levels by 2012 and 18 percent below 2007 levels by 2016 and, accordingly, has implemented theGreenhouse Gas Reduction Targets Act. The Crown is obliged to report every

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second year on the amount of reductions achieved in the province, although there is no mechanism in place to measure compliance nor is there any consequence for failing to reach the target. A carbon tax was implemented on the purchase or use of fossil fuels within the Province of British Columbia, starting at $10/ton on July 1, 2008 and rising by $5 per year to $30/ton in 2012. This carbon tax is mostly collected at the whole sale level, but is collected at the retail level for marketable natural gas and propane. Carbon capture and storage is required for all coal-fired electricity generation facilities and a 0.4 percent levy tax has been implemented at the consumer level on electricity, natural gas, grid propane and heating oil that goes towards establishing a Clean Energy Fund.

Saskatchewan

The Province of Saskatchewan has not implemented GHG emission reduction legislation at this time.

The direct and indirect costs of the various GHG regulations, existing and proposed, may adversely affect Pengrowth’s business, operations and financial results. Equipment that meets future emission standards may not be available on an economic basis and other compliance methods to reduce Pengrowth’s emissions or emissions intensity to future required levels may significantly increase operating costs or reduce the output of the projects. Offset, performance or fund credits may not be available for acquisition or may not be available on an economic basis. Any failure to meet emission reduction compliance obligations requirements may materially adversely affect Pengrowth’s business and result in fines, penalties and the suspension of operations. There is also a risk that one or more levels of government could impose additional emissions or emissions intensity reduction requirements or taxes on emissions created by Pengrowth or by consumers of Pengrowth’s products. The imposition of such measures might negatively affect Pengrowth’s costs and prices for Pengrowth’s products and have an adverse effect on earnings and results of operations.

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 our Management’s Discussion and Analysis for the year ended December 31, 2008.

The SIFT Legislation has and will continue to materially and adversely affect Pengrowth, 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 Canadian federal income tax rates and the expected provincial tax rates, we estimate 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 is expected to be 26.5 percent in 2011 and 25 percent in 2012, assuming a provincial tax rate of 10 percent being the applicable tax rate in the Province of Alberta where we anticipate 79 percent of our revenue will be generated in 2009. 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. 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 Pengrowth to compete effectively for acquisition opportunities in the future. There can be no assurance that Pengrowth will be able to reorganize its legal and tax structure to reduce the expected impact of the SIFT Legislation.

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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.

Low 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;

• geo-political conditions;

• worldwide economic conditions;

• 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 of lower operating cash flow due to low commodity prices, and in which Pengrowth 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, Pengrowth’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 Pengrowth is required to use cash flow to finance capital expenditures or property acquisitions, the cash the Trust receives 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.

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The value of the Trust Units will depend upon, among other things, Pengrowth’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 herein 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;

• 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. Should the lack of financing and uncertainty in the capital markets adversely impact Pengrowth’s ability to refinance debt, additional equity may be issued resulting in a dilutive effect on current and future Unitholders.

In the normal course of our business, we have entered into contractual arrangements with third parties which subject Pengrowth to the risk that such parties may default on their obligations.

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Pengrowth is exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to Pengrowth, such failures could have a material adverse effect on Pengrowth and its cash flow from operations. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner’s willingness to participate in Pengrowth’s ongoing capital program, potentially delaying the program and the results of such program until Pengrowth finds a suitable alternative partner.

If Pengrowth 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, 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 potential environmental claims and liability which will be funded out of our cash flow and will 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 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 industry participants, 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, some 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 are 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.

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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, the 2008 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 Pengrowth. 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 Pengrowth. In addition, increased activity within the oil and gas 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 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.

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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 Pengrowth or the Unitholders. Pengrowth, 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 Pengrowth or its 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 Pengrowth, 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 significant 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. 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.

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 and Esprit. If the oil and natural gas reserves associated with the resource properties of the Corporation and Esprit are not supplemented through additional development or the acquisition of oil and natural gas properties, the ability of Pengrowth 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 and Esprit. Pengrowth’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, Pengrowth’s involvement in the exploration for oil and natural gas is minimal. As a result, if the oil and natural gas reserves associated with Pengrowth’s resource properties are not supplemented through additional development or the acquisition of oil and natural gas properties, the ability of Pengrowth 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.

Under an agreement that expires on June 30, 2009, the Manager provides the advisory, management and administrative needs of Pengrowth in consideration for a management fee which is currently based in part on the earnings of Pengrowth. This arrangement may create an incentive for the Manager to maximize the earnings of Pengrowth, rather than maximize its cash flow from operations, which is the primary basis for calculating distributions available to Unitholders. The Manager may acquire, hold, operate, develop, manage and sell Canadian resource

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properties, or similar investments, 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 Pengrowth 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 Pengrowth are required to be paid by Pengrowth. 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.

Under the executive employment agreement which will become effective on July 1, 2009 between the Corporation and James S. Kinnear, the Chief Executive Officer of the Corporation, Mr. Kinnear is permitted to undertake certain oil and gas activities outside of North America provided that the activities are conducted by an entity led by an individual other than Mr. Kinnear, such activities do not derogate from Mr. Kinnear’s full time commitment to Pengrowth and have been first introduced to Pengrowth, such that they are not in conflict with any of Pengrowth’s business or operations.

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 GHGs 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 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 tax treatment of the Trust has a significant effect on the value of our Trust Units. 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:

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• 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, the Corporation and Esprit are all 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 the assets of such persons and of Pengrowth are located outside of the United States. Consequently, it may be difficult for United States investors to affect service of process within the United States upon Pengrowth 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 Pengrowth 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 Pengrowth 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, indebtedness and common shares of, the Corporation, Esprit 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 trading price of our Trust Units is a function of, among

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other things, anticipated cash flow, the oil and natural gas properties acquired by Pengrowth and the ability to effect long-term growth in the value of Pengrowth. 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 Pengrowth to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of our Trust Units.

Our Trust Units will have no value when reserves from the properties can no longer be economically produced or marketed; 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 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 herein estimates of Proved, Proved Plus Probable and Possible Reserves, as well as Contingent Resources. 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 result 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

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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.

• We have the right to elect under applicable United States Treasury Regulations to be treated as a corporation for United States federal income tax purposes, if such election were determined to be beneficial. As circumstances, including, without limitation, applicable tax laws and tax treaties, change, we will continue to evaluate if such an election would be beneficial to Pengrowth and its Unitholders including, without limitation, as a result of any potential tax efficiency in the payment of distributions to United States holders. If we elect to be treated as a corporation for United States federal income tax purposes, we would be treated as if we transferred all of our assets (subject to liabilities) to a newly formed corporation in return for stock in that corporation, and then distributed that stock to our owners in liquidation of their interests in us. Such deemed transfer and liquidation would likely be taxable to United States holders.

• 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 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.

• 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.

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• 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. The Protocol entered into force on December 15, 2008. 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 U.S. for the purposes of the Canada-U.S. Convention. Article IV(7)(b) of the Protocol will not come into force until January 1, 2010. 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.

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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.

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.

Terrorist attacks and the threat of terrorist attacks may have an adverse impact on the Corporation.

Energy sector participants, including Pengrowth, are a potential target for terrorists. The possibility that infrastructure facilities may be direct targets of, or indirect casualties of, an act of terror and the implementation of security measures as a precaution against possible terrorist attacks will result in increased cost to Pengrowth’s business.

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;

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

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

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 Pengrowth in respect of contracts or undertakings which Pengrowth 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 its 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 Pengrowth to the same extent that a shareholder is protected from the liabilities of a corporation. Further, although Pengrowth 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 Pengrowth 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. Pengrowth’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

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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.

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)								(U.S. $ per Trust Unit)
2008
January		18.15		14.16		17.67		11,122,230		18.22		13.67		17.48		5,637,800
February		18.85		17.10		18.35		8,055,594		19.22		16.93		18.66		3,611,700
March		19.82		18.07		19.67		11,576,037		19.47		17.61		19.10		5,043,500
April		21.02		19.17		19.75		9,122,242		20.79		18.86		19.71		6,104,400
May		21.56		19.47		20.34		9,432,421		21.90		19.04		20.53		7,693,300
June		21.16		19.90		20.50		9,449,203		20.89		19.60		20.11		5,626,900
July		20.55		17.40		17.70		11,964,173		20.20		17.04		17.31		10,624,448
August		18.89		17.10		18.85		9,860,089		18.09		16.20		17.75		7,137,570
September		18.50		14.73		15.99		9,961,463		17.32		14.16		14.94		9,052,581
October		15.98		8.55		13.01		18,451,866		15.00		7.50		11.21		22,021,164
November		13.53		9.75		11.24		7,901,229		11.65		7.56		8.97		9,406,631
December		10.95		8.82		9.35		8,681,986		8.62		6.84		7.62		10,348,796

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)
2008
January		100.50		98.50		100.00		841,000
February		102.25		99.51		100.00		677,000
March		102.00		100.00		100.50		671,000
April		102.00		100.01		102.00		485,000
May		101.25		101.25		101.25		349,000
June		102.00		100.55		100.55		358,000
July		101.50		100.55		100.56		524,000
August		102.00		100.01		101.00		451,000
September		101.50		99.00		101.00		814,000
October		100.01		91.60		91.60		1,277,000
November		98.70		90.50		91.00		621,000
December		97.23		85.00		91.00		372,000

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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 (since 2004)	Vice President, Engineering Pengrowth Management Limited
Robert M. Nicolay Alberta, Canada	Vice President, Business Development (since 2007)	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, 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		7,495,095
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		4,273
Alberta, Canada		Petro Andina Resources Inc.
		(energy company)
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)	Corporate Director		13,370
Alberta, Canada
Nicholas C.H. Villiers	Director (since 2007)	Business Consultant		—
London, England
John B. Zaozirny(3)(4)	Vice Chairman and Lead Independent	Vice Chair		35,100
Alberta, Canada	Director (Director since 1988)	Canaccord Capital Corporation
Gordon M. Anderson	Vice President (since 2001)	Vice President, Financial Services		29,167
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		20,483
Alberta, Canada	(since March 1, 2006)	Controller Pengrowth
	Controller (since 2005)	Corporation
James E.A. Causgrove	Vice President, Production and	Vice President, Production		41,789
Alberta, Canada	Operations (since 2005)	and Operations
		Pengrowth Corporation
William G. Christensen	Vice President, Strategic Planning and	Vice President, Strategic		26,927
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		12,510
Alberta, Canada	(since 2007)	Staff
		Pengrowth Corporation
Charles V. Selby	Vice President and Corporate Secretary	President		161,071
Alberta, Canada	(since 2005)	Selby Professional
	Corporate Secretary (since 1993)	Corporation (corporate
		finance and legal advising
		company)
Larry B. Strong	Vice President, Geosciences (since 2005)	Vice President, Geosciences		23,763
Alberta, Canada		Pengrowth Corporation

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			Trust Units
			Controlled or
Name and Jurisdiction	Position with		Beneficially
of Residence	Pengrowth Corporation	Principal Occupation	Owned(1)
Christopher G. Webster	Chief Financial Officer (since 2005)	Chief Financial Officer		66,144
Alberta, Canada	Treasurer (2000 - 2005)	Pengrowth Corporation

Notes:

(1)	As at December 31, 2008 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, 2008, the foregoing directors and officers, as a group, beneficially owned, directly or indirectly, 7,972,370 Trust Units or approximately three percent of the issued and outstanding Trust Units and held options, rights and deferred entitlement units to acquire a further 1,251,002 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; 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; Doug Bowles who was Financial Reporting Manager from 2003 to 2005 of ExxonMobil Canada; and James Donihee who was Chief Operating Officer of the National Energy Board (Canada) from 2003 to 2007.

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
(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.

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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:

Name	Independent	Financially 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, and until October 31, 2008 was a member of the board of Fording Inc. and served 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.
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. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Accountant designation.

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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 2008 and 2007:

	2008		2007
Audit Fees		1,037		1,393
Audit Related Fees		—		—
Tax Fees		98		163
All Other Fees		—		—
Total		1,135		1,556

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 2008 and 2007 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. 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

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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 Multilatral Instrument 61-101Protection of Minority Security Holders in Special 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 are not determinable at this time, however they are not expected to have a materially adverse effect on Pengrowth as a whole. Pengrowth is not, and has not been at any time within the most recently completed financial year, a party to any legal proceedings, known or contemplated, where the damages involved, excluding interest and costs, exceed ten percent of Pengrowth’s assets.

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 Vice-Chairman and Lead Independent Director of the Corporation, is the Vice Chair 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 Note Purchase Agreement dated August 21, 2008 concerning the 2008 Senior Notes;

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7.	the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes;
8.	the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes;
9.	the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes;
10.	the Debenture Indenture;
11.	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 website www.pengrowth.com, and is available in print to any Unitholder who requests it.

The Board of Directors approved changes to the Code of Ethics on February 17, 2009 in order to clarify that any retaliation against directors, officers, employees, consultants and contractors of Pengrowth who report possible violations of law or the Code of Ethics is prohibited and to make other clerical amendments. All employees are required to accept the Code annually.

During the year ended December 31, 2008, Pengrowth has not granted any waivers (including implicit waivers) from the Code of Ethics in respect of its Chief Executive Officer, Chief Financial Officer or its principal accounting officer.

OFF-BALANCE SHEET ARRANGEMENTS

Pengrowth has no off-balance sheet arrangements.

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 securities 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 of 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 Awards Plan which has been used as an employee retention and hiring mechanism when required by the tight employment market in the Canadian oil and gas industry.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration, the Manager’s remuneration, the principal holders of Trust Units and securities authorized for issuance under equity compensation plans, is contained in Pengrowth’s Management Information Circular dated May 9, 2008, which relates to the Annual and Special Meeting of Unitholders held on June 18, 2008. Pengrowth’s next meeting of Unitholders is scheduled to take place in the second quarter of 2009. 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 and associated management’s discussion and analysis for the years ended December 31, 2008 and 2007, which are included in the Trust’s Annual Report for the year ended December 31, 2008.

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, 2008. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, 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 presented 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, 2008, 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		Net Present Value of Future Net Revenue
	Preparation Date	Location of Reserves	(before income taxes, 10 percent discount rate -
Independent Qualified	of Evaluation	(Country or Foreign	$MM)
Reserves Evaluator	Report	Geographic Area)	Audited		Evaluated		Reviewed		Total
GLJ Petroleum Consultants	January 15, 2009	Canada		—	$	5,582		—	$	5,582

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. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
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, February 6, 2009.

(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
RESERVES DATA AND OTHER INFORMATION

     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, 2008, 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)“Wayne Foo”

Wayne Foo

Director

Pengrowth Corporation

(signed)“D. Michael G. Stewart”

D. Michael G. Stewart

Director

Pengrowth Corporation

March 24, 2009

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APPENDIX C

Audit Committee Terms of Reference

C-1

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 18, 2008 (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 National Instrument 52-110Audit Committees(“NI 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 any member of the Audit Committee or the Chairman and Chief Executive Officer (“CEO”) of the Corporation. 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 notice of a meeting is 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 chair 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 Chairman and CEO and the President and COO 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, may 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 NI 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 annually in the Trust’s annual information circular and 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 be incorporated by reference into a prospectus, including without limitation, the annual information circular. Approve, on behalf of the Board, Pengrowth’s interim financial statements and related management’s discussion and analysis and interim earnings

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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 52-110F1Audit Committee Information Required in an AIF, attached to NI 52-110. If proxies are solicited for the election of 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

1. 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.

2. 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 Vice Chairman and Lead Independent Director, the Chairman and CEO and the President and COO.

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 legal 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 information circular.

3. Ensure due compliance with each obligation to certify, on an annual and interim basis, internal control over financial reporting and disclosure controls and procedures in accordance with applicable securities laws and regulations.

4. Review all exceptions to established policies, procedures and internal controls of Pengrowth, which have been approved by any two officers of the Corporation.

5. 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.

6. 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.

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 legal 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, in its capacity as administrator of the Trust, on March 2, 2009.

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

A-3

comparable to 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

B-2

requirement 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 $120,000 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 is a current partner or employee of a firm that is the company’s internal or external auditor; (B) the director has an immediate family member who is a current partner of such a firm; (C) the director has an immediate family member who is a current employee of such a firm and personally works on the listed company’s audit; or (D) the director or an immediate family member was within the last three years 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 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.

C-2

For the 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.

APPENDIX B

MANAGEMENT’S DISCUSSION AND ANALYSIS

PENGROWTH 2008 | MD&A 5

MANAGEMENT’S DISCUSSION AND ANALYSIS

SUMMARY OF FINANCIAL RESULTS

	Three Months ended December 31									Twelve Months ended December 31
(thousands,
except per unit amounts)	2008			2007			% Change			2008			2007			% Change
INCOME STATEMENT
Oil and gas sales	$	392,158		$	425,249			(8	)	$	1,919,049		$	1,722,038			11
Net income (loss)	$	148,688		$	(3,665	)		—		$	395,850		$	359,652			10
Net income (loss) per trust unit	$	0.58		$	(0.01	)		—		$	1.58		$	1.47			7
CASH FLOWS
Cash flows from operating activities	$	154,807		$	196,325			(21	)	$	912,516		$	800,344			14
Cash flows from operating activities per trust unit	$	0.61		$	0.80			(24	)	$	3.65		$	3.26			12
Distributions declared	$	144,663		$	166,631			(13	)	$	651,015		$	706,601			(8	)
Distributions declared per trust unit	$	0.565		$	0.675			(16	)	$	2.590		$	2.875			(10	)
Ratio of distributions declared over cash flows from operating activities		93	%		85	%					71	%		88	%
Capital expenditures	$	125,876		$	95,743			31		$	401,928		$	309,708			30
Capital expenditures per trust unit	$	0.49		$	0.39			26		$	1.61		$	1.26			28
Weighted average number of trust units outstanding		255,473			246,513			4			250,182			245,470			2
BALANCE SHEET
Working capital										$	(70,159	)	$	(189,603	)		(63	)
Property, plant and equipment										$	4,251,381		$	4,306,682			(1	)
Long term debt										$	1,524,503		$	1,203,236			27
Trust unitholders’ equity										$	2,663,805		$	2,756,220			(3	)
Trust unitholders’ equity per trust unit										$	10.40		$	11.17			(7	)
Currency (U.S.$/Cdn$) (closing rate at period end)											0.8210			1.0088
Number of trust units outstanding at period end											256,076			246,846			4

Note regarding currency: all figures contained within this report are quoted in Canadian dollars unless otherwise indicated.

6 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

SUMMARY OF OPERATING RESULTS

	Three Months ended December 31									Twelve Months ended December 31
	2008			2007			% Change			2008			2007			% Change
AVERAGE DAILY PRODUCTION
Crude oil (barrels)		24,236			25,892			(6	)		24,416			26,327			(7	)
Heavy oil (barrels)		8,217			7,434			11			8,122			7,168			13
Natural gas (mcf)		241,709			250,117			(3	)		240,825			266,980			(10	)
Natural gas liquids (barrels)		10,634			9,319			14			9,315			9,409			(1	)
Total production (boe)		83,373			84,331			(1	)		81,991			87,401			(6	)
TOTAL PRODUCTION (mboe)		7,670			7,758			(1	)		30,009			31,901			(6	)
PRODUCTION PROFILE
Crude oil		29	%		31	%					30	%		30	%
Heavy oil		10	%		9	%					10	%		8	%
Natural gas		48	%		49	%					49	%		51	%
Natural gas liquids		13	%		11	%					11	%		11	%
AVERAGE REALIZED PRICES
(after commodity risk management)
Crude oil (per barrel)	$	65.87		$	73.69			(11	)	$	77.78		$	71.88			8
Heavy oil (per barrel)	$	42.20		$	45.47			(7	)	$	75.77		$	44.53			70
Natural gas (per mcf)	$	7.40		$	6.90			7		$	8.19		$	7.29			12
Natural gas liquids (per barrel)	$	43.87		$	67.64			(35	)	$	70.67		$	58.86			20
Average realized price per boe	$	50.34		$	54.58			(8	)	$	62.76		$	53.90			16
PROVED PLUS PROBABLE RESERVES
Crude oil (mbbls)											121,289			124,188			(2	)
Heavy oil (mbbls)											27,728			21,792			27
Natural gas (bcf)											852			870			(2	)
Natural gas liquids (mbbls)											32,442			28,994			12
Total oil equivalent (mboe)											323,463			319,921			1
SUMMARY OF TRUST UNIT TRADING
NYSE — PGH ($U.S.)
High	$	15.00		$	19.21					$	21.90		$	19.85
Low	$	6.84		$	17.30					$	6.84		$	15.82
Close	$	7.62		$	17.77					$	7.62		$	17.77
TSX — PGF.UN ($Cdn)
High	$	15.98		$	18.68					$	21.56		$	21.04
Low	$	8.55		$	17.00					$	8.55		$	16.92
Close	$	9.35		$	17.62					$	9.35		$	17.62

PENGROWTH 2008 | MD&A 7

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following Management’s Discussion and Analysis (MD&A) of financial results should be read in conjunction with the audited consolidated Financial Statements for the year ended December 31, 2008 of Pengrowth Energy Trust and is based on information available to March 2, 2009.

FREQUENTLY RECURRING TERMS

For the purposes of this MD&A, we use certain frequently recurring terms as follows: the “Trust” refers to Pengrowth Energy Trust, the “Corporation” refers to Pengrowth Corporation, “Pengrowth” refers to the Trust and its subsidiaries and the Corporation on a consolidated basis and the “Manager” refers to Pengrowth Management Limited.

Pengrowth uses the following frequently recurring industry terms in this MD&A: “bbls” refers to barrels, “boe” refers to barrels of oil equivalent, “mboe” refers to a thousand barrels of oil equivalent, “mcf” refers to thousand cubic feet, “gj” refers to gigajoule and “mmbtu” refers to million British thermal units.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS

This MD&A contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of Canadian securities legislation and the United States Private Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “guidance” “may”, “will”, “should”, “could”, “estimate”, “predict” or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to: reserves, 2009 production, production additions from Pengrowth’s 2009 development program, royalty obligations, 2009 operating expenses, future income taxes, goodwill, asset retirement obligations, taxability of distributions, remediation and abandonment expenses, capital expenditures, general and administration expenses, and proceeds from the disposal of properties. Statements relating to “reserves” are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on 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 natural 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 exploitation 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 “Business Risks” herein and under “Risk Factors” in Pengrowth’s most recent Annual Information Form (AIF), and in Pengrowth’s most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases. Copies of the Trust’s Canadian public filings are available on SEDAR at www.sedar.com. The Trust’s U.S. public filings, including the Trust’s most recent annual report form 40-F as supplemented by its filings on form 6-K, are available at www.sec.gov.

Pengrowth cautions that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to Pengrowth, investors and others should carefully consider the foregoing factors and other uncertainties and potential events. Furthermore, the forward-looking statements contained in this

8 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

MD&A are made as of the date of this MD&A and Pengrowth does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by law. The forward-looking statements in this document are provided for the limited purpose of enabling current and potential investors to evaluate an investment in Pengrowth. Readers are cautioned that such statements may not be appropriate, and should not be used for other purposes.

The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

CRITICAL ACCOUNTING ESTIMATES

As discussed in Note 2 to the financial statements, the financial statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period ended.

The amounts recorded for depletion, depreciation and amortization of injectants, the provision for asset retirement obligations, unit based compensation, goodwill and future taxes are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. The amounts recorded for the fair value of risk management contracts and the unrealized gains or losses on the change in fair value are based on estimates. These estimates can change significantly from period to period. As required by National Instrument 51-101 (NI 51-101) Standards of Disclosure for Oil and Gas Activities, Pengrowth uses independent qualified reserve evaluators in the preparation of reserve evaluations. By their nature, these estimates are subject to measurement uncertainty and changes in these estimates may impact the consolidated financial statements of future periods.

The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended. Certain of these estimates may change from period to period resulting in a material impact on Pengrowth’s results of operations, financial position, and change in financial position.

The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions as determined by Pengrowth’s independent reserves evaluators. A material change in the future costs and oil and gas prices may have a material affect on the results of the ceiling test calculation. Any impairment indicated by the ceiling test would be written off through net income in the period. The prices used in the ceiling test are disclosed in Note 6 to the annual consolidated financial statements. While the reserves and estimated future prices have changed over the past two years, the results of the ceiling tests have indicated a significant surplus over net book value. Please refer to the oil and gas disclosures in the AIF filed each year for detailed disclosure of reserves and future net revenue.

The impairment assessment of goodwill is based on the estimated fair value of Pengrowth’s reporting units which is referenced to Pengrowth’s trust unit price and the premium an arm’s length party would pay to acquire all of the outstanding trust units. Under Canadian GAAP, goodwill is assessed for impairment in a two step process. In the first step, the total net assets are compared to Pengrowth’s total market capitalization and any control premium that may be considered reasonable. If the total market capitalization is greater than the total net assets, goodwill is determined not to be impaired and no further assessment is required. A significant change in the market price of Pengrowth’s trust units or the necessary control premium may have a material impact on the assessment of goodwill which may require quantification under Step 2. Pengrowth has never been required to quantify any impairment under Step 2. Continued decline in the trust unit price could cause Pengrowth to quantify any impairment under Step 2, which may result in a material write-down.

In the second step of the impairment assessment of goodwill, the total market capitalization plus any control premium is compared to the fair value of Pengrowth’s net assets. The fair values of assets except property, plant and equipment would be determined in accordance with the policies disclosed in Note 20 to the financial statements. The fair value of property, plant and equipment would be determined based on estimates of proved plus probable reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions as determined by Pengrowth’s independent reserves evaluators. A material change in the future costs and oil and gas prices may have a material affect on the results of the quantification of any potential impairment.

NON-GAAP FINANCIAL MEASURES

This MD&A refers to certain financial measures that are not determined in accordance with GAAP in Canada or the United States. These measures do not have standardized meanings and may not be comparable to similar measures presented by other trusts or corporations. Measures such as operating netbacks do not have standardized meanings prescribed by GAAP.

PENGROWTH 2008 | MD&A 9

MANAGEMENT’S DISCUSSION AND ANALYSIS

Distributions can be compared to cash flow from operating activities in order to determine the amount, if any, of distributions financed through debt or short term borrowing. The current level of capital expenditures funded through retained cash, as compared to debt or equity, can also be determined when it is compared to the difference in cash flow from operating activities and distributions paid in the financing section of the Statement of Cash Flows.

Management monitors Pengrowth’s capital structure using non-GAAP financial metrics. The two metrics are Total Debt to the trailing twelve months Earnings Before Interest, Taxes, Depletion, Depreciation, Amortization, Accretion, and other non-cash items (EBITDA) and Total Debt to Total Capitalization. Total Debt is the sum of working capital, long term debt and convertible debentures as shown on balance sheet, and Total Capitalization is the sum of Total Debt and Unitholder’s equity. Management believes that targeting prudent ratios of these measures is reasonable given the size of Pengrowth, its capital management objectives, growth strategy, uncertainty of oil and gas commodity prices and additional margin required from the debt covenants.

If the ratio of Total Debt to trailing EBITDA reaches or exceeds certain levels, management would consider steps to reduce the ratio of Total Debt to trailing EBITDA. If the ratio of Total Debt to Total Capitalization reaches or exceeds certain levels, except upon completion of a material acquisition, Pengrowth management would consider steps to improve the ratio while considering our debt financial covenant limits. Those steps could include, but are not limited to, raising equity, selling assets, reducing capital expenditures or reducing distributions. Details of these measures are included in Note 19 to the consolidated financial statements.

NON-GAAP OPERATIONAL MEASURES

The reserves and production in this MD&A refer to Company Interest reserves or production that is Pengrowth’s working interest share of production or reserves prior to the deduction of royalties plus the interest in production or reserves at the wellhead. Company interest is more fully described in Pengrowth’s AIF.

When converting natural gas to equivalent barrels of oil within this MD&A, Pengrowth uses the industry standard of six thousand cubic feet to one barrel of oil equivalent. Barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of six mcf of natural gas to one boe is based on an energy equivalency conversion primarily and does not represent a value equivalency at the wellhead. Production volumes, revenues and reserves are reported on a company interest gross basis (before royalties) in accordance with Canadian practice.

CURRENCY

All amounts are stated in Canadian dollars unless otherwise specified.

OVERVIEW

Pengrowth generated record cash flow from operating activities for the full year of 2008 of $912.5 million, a 14 percent increase over the full year of 2007. The increase in cash flow from operating activities in 2008 is the result of higher realized commodity prices for oil, gas and natural gas liquids (NGLs) through the first three quarters of the year, which more than offset the impact of lower volumes and higher royalty and operating expenses.

	Three months ended									Twelve months ended
	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Production (boe/d)		83,373			80,981			84,331			81,991			87,401
Netback ($/boe)		26.23			37.48			29.56			34.78			30.40
Cash flows from operating activities ($000’s)		154,807			273,597			196,325			912,516			800,344
Net income (loss) ($000’s)		148,688			422,395			(3,665	)		395,850			359,652
Included in net income:
Unrealized gain (loss) on commodity risk management ($000’s)		292,249			476,005			(136,606	)		249,899			(122,307	)
Unrealized foreign exchange gain (loss) on foreign denominated debt ($000’s)		(127,207	)		(24,999	)		5,665			(172,626	)		73,940

(1) Restated to conform to presentation adapted in current period.

10 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

On a year-over-year basis, net income increased by ten percent in 2008 to $395.8 million compared to $359.7 million in 2007. Included in the net income are unrealized gains on mark-to-market commodity risk management contracts of $249.9 million before taxes ($174.9 million after tax) compared to a $122.3 million before tax ($91.3 million after tax) unrealized loss in 2007. While the weakening of the Canadian dollar relative to the U.S. dollar had a positive impact on cash flow, the weakness also resulted in pre-tax unrealized foreign exchange losses on foreign denominated debt of $127.2 million in the fourth quarter 2008 and $172.6 million for the full year of 2008 compared to pre-tax unrealized gains of $5.7 million and $73.9 million in the comparative periods in the prior year, respectively.

The commodity risk management activities, which are utilized to partially secure returns from significant acquisitions and provide a level of stability to the Trust’s cash flow from operating activities, has from time to time limited the Trust’s ability to fully realize higher commodity prices. With lower commodity prices at the end of the fourth quarter, the commodity risk management activity did offset a portion of the Trust’s exposure to the reduced prices.

HIGHLIGHTS

• Oil and gas sales increased 11 percent, to $1.9 billion in 2008 reflective of higher average realized prices reached through the first three quarters of 2008. In the fourth quarter, oil and gas sales were $392.2 million, a decrease of 24 percent from the third quarter and an eight percent decrease from the fourth quarter of 2007.

• Cash flow from operating activities increased 14 percent to $912.5 million in 2008 reflective of higher realized prices compared to 2007. Fourth quarter cash flow from operating activities was $154.8 million representing a 43 percent decrease from the third quarter and a 21 percent decrease from the fourth quarter of 2007.

• Daily production for 2008 averaged 81,991 boe per day, consistent with 2008 guidance. The six percent decrease in the current year compared to 2007 full year average production of 87,401 boe per day, is primarily due to lower volumes as a result of divested properties and operational shutdowns offset by successful development activity and additional volumes from the acquired properties from Accrete Energy Inc. (“Accrete”) completed at the end of the third quarter. Fourth quarter production averaged 83,373 boe per day, relatively unchanged from the same quarter in 2007; additional volumes from the Accrete properties were partially offset by an unscheduled maintenance shutdown.

• Pengrowth’s 2008 development capital spending, excluding acquisitions totaled $388.3 million ($283.1 million in 2007), including the Lindbergh project, resulting in reserve replacement of 80 percent for Total Proved plus Probable Reserves excluding acquisitions, and 112 percent including acquisitions.

• Distributions declared to unitholders in 2008 were $651.0 million, or $2.59 per trust unit. Distributions declared to unitholders totalled 71 percent of cash flow from operating activities and 93 percent for the fourth quarter of 2008. Due to higher capital spending in 2008, and the desire to curtail debt, an increased percentage of cash flow from operations was withheld to fund the capital program.

• Net income increased ten percent to $395.8 million in 2008 compared to $359.7 million in 2007. The increase was due to higher realized prices through the first three quarters of 2008, partly offset by higher royalties, operating expenses and general and administrative costs. In addition to these items, net income was effected by certain non-cash items including a $249.9 million unrealized gain on commodity risk management contracts, and a $71.9 million future tax reduction, partly offset by a $172.6 million unrealized foreign exchange loss on foreign denominated debt.

• During 2008, Pengrowth’s average realized price was $62.76 per boe (after commodity risk management) compared to an average price of $53.90 per boe in 2007. Prices for liquids and natural gas were higher year over year reflective of the unprecedented benchmark prices through the third quarter of 2008.

• During the fourth quarter of 2008, Pengrowth’s average realized price was $50.34 per boe (after commodity risk management) compared to an average realization of $67.71 per boe in the third quarter of 2008 and $54.58 in the fourth quarter of 2007. Compared to the other periods, prices for liquids were lower in the fourth quarter of 2008 while natural gas enjoyed a modest increase.

• During 2008, Pengrowth closed a U.S. $265 million and a Cdn $15 million private placement of senior unsecured notes with interest rates of 6.98 percent and 6.61 percent respectively, due in 2018.

• Operating netbacks (after commodity risk management) increased 14 percent in 2008 to $34.78 from 2007, driven by higher realized prices partially offset by higher royalties and operating costs. Fourth quarter 2008 operating netbacks were $26.23 per boe, a decrease of 30 percent from the third quarter and a 11 percent decrease from the fourth quarter of 2007.

PENGROWTH 2008 | MD&A 11

MANAGEMENT’S DISCUSSION AND ANALYSIS

• Pengrowth’s finding and development costs for 2008 equaled $16.27 per boe on a proved plus probable basis. Including acquisitions, finding and development costs were $15.47 per boe on a proved plus probable basis. During the year, Pengrowth participated in 507 gross (217 net) wells with a 96 percent success rate.

• During the fourth quarter of 2008, Pengrowth completed the divestiture of certain non-core, non-producing lands in the Dawson area in British Columbia. Proceeds of the disposition were approximately $27 million, with $21 million received in 2008.

• On September 30, 2008, Pengrowth acquired properties in the Harmattan area from Accrete Energy Inc. (“Accrete”). All of Accrete’s oil and gas properties except those in the Harmattan area were transferred to Argosy Energy Inc., an unrelated company.

• During the third quarter of 2008, Pengrowth completed the acquisition of additional working interest in the Harmattan area from Fairmount Energy Inc. for $12.0 million. Also in the third quarter of 2008, Pengrowth purchased additional working interests in both the Carson Creek and Garrington areas.

• During the second quarter of 2008, Pengrowth completed property acquisitions of approximately $16.9 million, which included exercising a right of first refusal in Three Hills and purchasing additional working interest at Swan Hills.

RESULTS OF OPERATIONS

This MD&A contains the results of Pengrowth Energy Trust and its subsidiaries.

PRODUCTION

Average daily production increased approximately three percent in the fourth quarter of 2008 compared to the third quarter of 2008. Increased volumes are primarily attributable to development additions, the acquisition of Accrete on September 30, 2008, and an additional condensate lift at Sable Offshore Energy Project (“SOEP”), offset by a lengthy unscheduled plant outage at Quirk Creek and operational issues in the Olds area. Average daily production decreased in the fourth quarter and full year 2008 compared to the same periods of 2007 as a result of lower volumes due to divested properties and maintenance shutdowns offset by successful development activity and additional volumes acquired through the previously mentioned Accrete acquisition.

At this time, Pengrowth anticipates 2009 full year production to average between 76,000 to 78,000 boe per day. This estimate excludes the impact from any potential future acquisitions and dispositions. Given the current market conditions, Pengrowth has reduced the development capital program including Lindbergh to $209 million, compared to $388 million in 2008, which has a direct impact on the outlook for production for the full year of 2009.

DAILY PRODUCTION

	Three months ended						Twelve months ended
	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Light crude oil (bbls)		24,236		23,286		25,892		24,416		26,327
Heavy oil (bbls)		8,217		8,287		7,434		8,122		7,168
Natural gas (mcfs)		241,709		246,287		250,117		240,825		266,980
Natural gas liquids (bbls)		10,634		8,361		9,319		9,315		9,409
Total boe per day		83,373		80,981		84,331		81,991		87,401

Light crude oil production volumes increased four percent in the fourth quarter of 2008 compared to the third quarter of 2008 primarily due to successful results from recompletion work at Fenn Big Valley and additional volumes coming back on line in Judy Creek after third quarter maintenance work. Production volumes decreased approximately seven percent for the full year of 2008 compared to the full year of 2007 and six percent in the fourth quarter of 2008 from the fourth quarter of 2007. The decrease is mainly attributable to the absence of volumes from divested properties (approximately 850 bbls per day for the full year of 2008), and natural declines.

12 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

Heavy oil production increased 11 percent compared to the fourth quarter of 2007 and decreased slightly in the fourth quarter of 2008 compared to the third quarter of 2008. The additional volumes are the result of successful development activity primarily at Tangleflags and increased productivity of existing wells in East Bodo from success with the polymer flood. These additional volumes were partially offset by natural declines.

Natural gas production decreased ten percent for the full year of 2008 and three percent in the fourth quarter of 2008 compared to the same periods of 2007. The decreases are mainly attributable to maintenance shutdowns (Olds and Quirk Creek) and the absence of volumes from properties divested in 2007 of approximately 14,000 mcf per day for the full year 2008. Offsetting the decreases were additional volumes from the Accrete acquisition, which contributed volumes in the fourth quarter and successful development activities of new wells and increased productivity of existing wells. Production volumes decreased approximately two percent in the fourth quarter of 2008 compared to the third quarter of 2008 as a result of maintenance shutdowns at Quirk Creek, operational issues at Olds and natural declines, partially offset by additional volumes from the previously mentioned Accrete acquisition.

NGL production decreased slightly for full year 2008 compared to full year 2007 primarily due to divested properties offset by an additional condensate lift at SOEP in the current year, higher sales at Judy Creek as a result of lower NGL volumes required for miscible flood requirements and additional volumes from the Accrete acquisition. Fourth quarter 2008 production increased 27 percent compared to third quarter 2008 as a result of an additional condensate lift at SOEP, added volumes from the previously mentioned Accrete acquisition, partly offset by a maintenance shutdown at Quirk Creek. Fourth quarter production increased 14 percent when compared to the same period of 2007 as a result of an additional condensate lift at SOEP in the current period.

PRICING AND COMMODITY RISK MANAGEMENT

Although in 2008 the oil and gas industry realized record benchmark prices through the third quarter, Pengrowth did not fully benefit from these higher benchmark prices due to the effects of the risk management strategy. Pengrowth’s realizations in the fourth quarter were influenced by the dramatic benchmark price declines, however gains from commodity risk management activities partially offset some of the decreases in benchmark prices.

As part of its risk management strategy, Pengrowth uses forward price swaps to manage its exposure to commodity price fluctuations to provide a measure of stability to monthly cash distributions and to partially secure returns on significant new acquisitions. As of December 31, 2008, Pengrowth has crude oil contracts for 2009, 2010 and 2011 for approximately 13,000 bbls per day, 6,500 bbls per day and 500 bbls per day respectively. Also as of December 31, 2008, Pengrowth has natural gas contracts for 2009 and 2010 for 75,000 mcf per day and 16,600 mcf per day, respectively. Each Cdn $1 per barrel change in future oil prices would result in approximately Cdn $7.3 million pre-tax change in the value of the crude contracts. Similarly, each Cdn $0.50 per mcf change in future natural gas prices would result in approximately Cdn $16.7 million pretax change in the value of the natural gas contracts. The changes in the fair value of the forward contracts directly affects net income through the unrealized amounts booked to the statement of income during the period. The effect on cash flows will be recognized separately only upon realization of the contracts, which could vary significantly from the unrealized amount recorded due to timing and prices when each contract is settled. However, if each contract were to settle at the contract price in effect at December 31, 2008, future revenue would be increased by the $164.7 million unrealized commodity risk management gains that have been recorded. Pengrowth has fixed the Canadian dollar exchange rate at the same time that it swaps any U.S. dollar denominated commodity in order to protect against changes in the foreign exchange rate.

Pengrowth has not designated any outstanding commodity contracts as hedges for accounting purposes and therefore records these contracts on the balance sheet at their fair value and recognize changes in fair value on the statement of income as unrealized commodity risk management gains or losses. There will continue to be volatility in earnings to the extent that the fair value of commodity contracts fluctuate however, these non-cash amounts do not impact Pengrowth’s operating cash flows. Realized commodity risk management gains or losses are recorded in oil and gas sales on the statement of income and impacts cash flows at that time.

PENGROWTH 2008 | MD&A 13

MANAGEMENT’S DISCUSSION AND ANALYSIS

AVERAGE REALIZED PRICES

	Three months ended						Twelve months ended
(Cdn$)	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Light crude oil (per bbl)		60.76		118.81		82.31		98.20		72.93
after realized commodity risk management		65.87		82.00		73.69		77.78		71.88
Heavy oil (per bbl)		42.20		96.93		45.47		75.77		44.53
Natural gas (per mcf)		6.97		8.82		6.20		8.32		6.71
after realized commodity risk management		7.40		8.29		6.90		8.19		7.29
Natural gas liquids (per bbl)		43.87		87.06		67.64		70.67		58.86
Total per boe		47.60		79.91		55.16		69.24		52.46
after realized commodity risk management		50.34		67.71		54.58		62.76		53.90
BENCHMARK PRICES
WTI oil (U.S.$  per bbl)		58.73		117.98		90.71		99.65		72.12
AECO spot gas (Cdn$  per gj)		6.43		8.76		5.69		7.70		6.27
NYMEX gas (U.S.$  per mmbtu)		6.94		10.24		6.97		9.04		6.86
Currency (U.S.$/Cdn$)		0.83		0.96		1.02		0.94		0.93

REALIZED COMMODITY RISK MANAGEMENT GAINS (LOSSES)

	Three months ended								Twelve months ended
	Dec 31, 2008		Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Light crude oil ($ millions)		11.4		(78.8	)		(20.5	)		(182.5	)		(10.1	)
Light crude oil ($  per bbl)		5.11		(36.81	)		(8.62	)		(20.42	)		(1.05	)
Natural gas ($ millions)		9.6		(12.1	)		16.0			(11.8	)		56.1
Natural gas ($  per mcf)		0.43		(0.53	)		0.70			(0.13	)		0.58
Combined ($ millions)		21.0		(90.9	)		(4.5	)		(194.3	)		46.0
Combined ($  per boe)		2.74		(12.20	)		(0.58	)		(6.48	)		1.44

Commodity price contracts in place at December 31, 2008 are detailed in Note 20 to the consolidated financial statements. Additionally, the fair value of the outstanding contracts has been recorded on the balance sheet as an asset of $165 million at year end of which the majority is a current asset of $123 million. In the year ended December 31, 2007 the total net liability was $85 million, of which $63 million was current. An unrealized gain of $250 million resulting from the change in fair value from January 1 to December 31, 2008 has been recognized in the statement of income compared to an unrealized loss of $122 million for the same time period in 2007.

OIL AND GAS SALES — CONTRIBUTION ANALYSIS

The following table includes the impact of realized commodity risk management activity.

($ millions)	Three months ended												Twelve months ended
	Dec 31,		% of		Sept 30,		% of		Dec 31,		% of		Dec 31,		% of		Dec 31,		% of
Sales Revenue	2008		total		2008		total		2007		total		2008		total		2007		total
Light crude oil		146.9		37		175.6		34		175.6		41		695.1		36		690.8		40
Natural gas		164.5		42		187.9		36		158.8		37		722.1		38		710.1		41
Natural gas liquids		42.9		11		66.9		13		57.9		14		240.9		12		202.1		12
Heavy oil		31.9		8		73.9		14		31.1		8		225.3		12		116.5		7
Brokered sales/sulphur		5.9		2		14.4		3		1.8		—		35.6		2		2.5		—
Total oil and gas sales		392.1				518.7				425.2				1,919.0				1,722.0

14 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

OIL AND GAS SALES — PRICE AND VOLUME ANALYSIS

The following table illustrates the effect of changes in prices and volumes on the components of oil and gas sales, including the impact of realized commodity risk management activity, on a year-over-year basis.

($ millions)	Light oil			Natural gas			NGLs			Heavy oil		Other			Total
Period ended Dec 31, 2007		690.8			710.1			202.1			116.5		2.5			1,722.0
Effect of change in product prices		225.9			142.1			40.3			92.9		—			501.2
Effect of change in sales volumes		(49.1	)		(62.4	)		(1.5	)		15.9		—			(97.1	)
Effect of change in realized commodity risk management activities		(172.4	)		(67.9	)		—			—		—			(240.3	)
Other		(0.1	)		0.2			—			—		33.1	(1)		32.2
Period ended Dec 31, 2008		695.1			722.1			240.9			225.3		35.6			1,919.0

(1) Primary sulphur sales.

PROCESSING AND OTHER INCOME

	Three months ended							Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008			Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Processing & other income		2.3		5.2	(1)		4.1		15.5		20.6
$  per boe		0.31		0.70			0.53		0.52		0.64

(1) Prior quarter restated to conform to presentation adopted in the current period.

Processing and other income is primarily derived from fees charged for processing and gathering third party gas, road use, oil and water processing. Fourth quarter 2008 income is lower in comparison to the third quarter of 2008, which is primarily a result of prior period road use income being booked in the third quarter.

This income primarily represents the partial recovery of operating expenses reported separately.

ROYALTY EXPENSE

	Three months ended									Twelve months ended
($ millions)	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Royalty expense		80.7			129.5			85.4			434.0			319.3
$  per boe		10.51			17.39			11.01			14.46			10.01
Royalties as a percent of sales		20.6	%		25.0	%		20.0	%		22.6	%		18.5	%
Royalties as a percent of sales excluding realized risk management contracts		21.7	%		21.2	%		19.9	%		20.5	%		19.1	%

Royalties include Crown, freehold and overriding royalties as well as mineral taxes. The royalty rate for 2008 is higher than 2007 primarily a reflection of the higher average market prices used for the calculation of royalty expense. The fourth quarter 2008 royalty rate is lower compared to the third quarter as a result of lower average market prices. Additionally, gains or losses from realized commodity risk management activities affect royalty rates as a percentage of sales, since royalty payments are based on revenue prior to commodity risk management activities. Royalty expense would represent 21.7 and 20.5 percent of sales for the fourth quarter and the full year of 2008, respectively, excluding the effects of realized commodity risk management contracts.

Effective January 1, 2009, the Alberta Government’s changes to the royalty calculations were implemented. Under this new regime, Pengrowth’s outlook for 2009 royalty expense is forecasted to average approximately 22 percent of sales.

PENGROWTH 2008 | MD&A 15

MANAGEMENT’S DISCUSSION AND ANALYSIS

OPERATING EXPENSES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Operating expenses		104.1		105.2		103.8		418.5		406.5
$  per boe		13.57		14.13		13.38		13.95		12.74

Operating expenses decreased slightly from the third quarter of 2008 as increased utility costs of $3.6 million were more than offset by decreases in turnaround expenses and subsurface maintenance work at Goose River, Carson Creek and Judy Creek. Operating expenses year-over-year increased by three percent, or nine percent on a per boe basis. The increase for the full year 2008 compared to the full year 2007 is mainly attributable to higher utility costs which increased $20.1 million reflective of a 23 percent increase in the Alberta power pool price. Other increased expenses in 2008 related to the Olds turnaround and increased maintenance costs associated with the Quirk Creek field shutdown, which were offset by lower subsurface maintenance activity at Judy Creek, Carson Creek and Bodo.

Operating expenses are expected to decrease slightly for the full year 2009; however per boe operating costs are estimated to increase to approximately $14.45 per boe, a four percent increase from the full year 2008. The expected increase in per boe operating costs is primarily attributed to the anticipated production decline in 2009.

NET OPERATING EXPENSES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Net operating expenses		101.8		100.0		99.7		403.0		385.9
$  per boe		13.27		13.43		12.85		13.43		12.10

Included in the table above are operating expenses net of processing and other income.

TRANSPORTATION COSTS

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Light oil transportation		0.4		0.7		1.2		3.4		3.5
$  per bbl		0.19		0.33		0.49		0.38		0.37
Natural gas transportation		2.3		2.6		2.1		9.1		9.1
$  per mcf		0.10		0.11		0.09		0.10		0.09

Pengrowth incurs transportation costs for its product once the product enters a feeder or main pipeline to the title transfer point. The transportation cost is dependant upon third party rates and distance the product travels on the pipeline prior to changing ownership or custody. Pengrowth has the option to sell some of its natural gas directly to premium markets outside of Alberta by incurring additional transportation costs. Pengrowth sells most of its natural gas without incurring significant additional transportation costs. Similarly, Pengrowth has elected to sell approximately 65 percent of its crude oil at market points beyond the wellhead but at the first major trading point, requiring minimal transportation costs.

AMORTIZATION OF INJECTANTS FOR MISCIBLE FLOODS

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Purchased and capitalized		5.4		4.8		8.1		21.0		26.1
Amortization		5.9		6.5		7.5		25.9		34.1

16 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

The cost of injectants (primarily natural gas and ethane) purchased for injection in the miscible flood program at Judy Creek and Swan Hills is amortized equally over the period of expected future economic benefit. The cost of injectants purchased in 2008 and 2007 are amortized over a 24 month period. As of December 31, 2008, the balance of the unamortized injectant costs was $22.4 million.

The amount of injectants purchased and capitalized in the fourth quarter 2008 was higher than the third quarter of 2008 due to the timing and the requirements of this ongoing program. The value of Pengrowth’s proprietary injectants is not recorded as an asset or a sale; the cost of producing these injectants is included in operating expenses.

OPERATING NETBACKS

There is no standardized measure of operating netbacks and therefore operating netbacks, as presented below, may not be comparable to similar measures presented by other companies. Certain assumptions have been made in allocating operating expenses, other production income, other income and royalty injection credits between light crude, heavy oil, natural gas and NGL production.

Pengrowth recorded an average operating netback of $26.23 per boe in the fourth quarter of 2008 compared to $37.48 per boe in the third quarter of 2008 and $29.56 per boe for the fourth quarter of 2007. The decrease in the netback in the fourth quarter compared to the third quarter of 2008 and the fourth quarter of 2007 was primarily a result of lower combined commodity price realizations.

The sales price used in the calculation of operating netbacks is after realized commodity risk management gains or losses.

	Three months ended									Twelve months ended
Combined Netbacks ($ per boe)	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Sales price (after commodity risk management)		50.34			67.71			54.58			62.76			53.90
Other production income		0.78			1.91			0.23			1.19			0.08
		51.12			69.62			54.81			63.95			53.98
Processing and other income(1)		0.31			0.70			0.53			0.52			0.64
Royalties		(10.51	)		(17.39	)		(11.01	)		(14.46	)		(10.01	)
Operating expenses		(13.57	)		(14.13	)		(13.38	)		(13.95	)		(12.74	)
Transportation costs		(0.35	)		(0.44	)		(0.42	)		(0.42	)		(0.40	)
Amortization of injectants		(0.77	)		(0.88	)		(0.97	)		(0.86	)		(1.07	)
Operating netback		26.23			37.48			29.56			34.78			30.40

	Three months ended									Twelve months ended
Light Crude Netbacks ($ per bbl)	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Sales price (after commodity risk management)		65.87			82.00			73.69			77.78			71.88
Other production income		(0.02	)		(0.01	)		0.36			0.19			0.15
		65.85			81.99			74.05			77.97			72.03
Processing and other income(1)		0.06			1.47			0.33			0.62			0.44
Royalties		(14.02	)		(20.10	)		(13.86	)		(16.73	)		(11.57	)
Operating expenses(1)		(14.86	)		(14.72	)		(14.98	)		(15.39	)		(13.73	)
Transportation costs		(0.19	)		(0.33	)		(0.49	)		(0.38	)		(0.37	)
Amortization of injectants		(2.64	)		(3.05	)		(3.14	)		(2.90	)		(3.54	)
Operating netback		34.20			45.26			41.91			43.19			43.26

PENGROWTH 2008 | MD&A 17

MANAGEMENT’S DISCUSSION AND ANALYSIS

	Three months ended									Twelve months ended
Heavy Oil Netbacks ($ per bbl)	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Sales price		42.20			96.93			45.47			75.77			44.53
Processing and other income		0.29			0.02			0.19			0.32			0.27
Royalties(2)		(1.95	)		(15.87	)		(5.91	)		(10.54	)		(5.86	)
Operating expenses(1)		(12.77	)		(13.17	)		(11.92	)		(12.47	)		(12.60	)
Operating netback		27.77			67.91			27.83			53.08			26.34

	Three months ended									Twelve months ended
Natural Gas Netbacks ($ per mcf)	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Sales price (after commodity risk management)		7.40			8.29			6.90			8.19			7.29
Other production income		0.27			0.63			0.04			0.39			0.01
		7.67			8.92			6.94			8.58			7.30
Processing and other income(1)		0.09			0.09			0.14			0.10			0.16
Royalties		(1.62	)		(2.19	)		(1.22	)		(1.88	)		(1.33	)
Operating expenses(1)		(2.19	)		(2.31	)		(2.06	)		(2.23	)		(2.04	)
Transportation costs		(0.10	)		(0.11	)		(0.09	)		(0.10	)		(0.09	)
Operating netback		3.85			4.40			3.71			4.47			4.00

	Three months ended									Twelve months ended
NGL Netbacks ($ per bbl)	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Sales price		43.87			87.06			67.64			70.67			58.86
Royalties		(12.27	)		(32.22	)		(23.61	)		(25.74	)		(18.49	)
Operating expenses(1)		(12.93	)		(14.62	)		(14.67	)		(13.93	)		(12.57	)
Operating netback		18.67			40.22			29.36			31.00			27.80

(1)	Prior Period restated to conform to presentation in the current period.
(2)	Heavy Oil Royalties in the fourth quarter of 2008 includes accounting adjustments related to overpayment of royalties in the third quarter.

INTEREST EXPENSE

	Three months ended							Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008			Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Interest Expense		22.6		19.0	(1)		19.7		76.3		84.3

(1) Prior quarter restated to conform to presentation adopted in the current period.

Interest expense increased in the fourth quarter of 2008 compared to the third quarter of 2008 primarily due to higher debt levels. The increase compared to the same time period of 2007 is a result of higher debt levels and the weakening of the Canadian dollar. See Note 9 to the consolidated financial statements for further details. Interest expense decreased ten percent year-over-year which is reflective of a lower average debt level in 2008 compared to the same time period of 2007 which included $13.9 million of interest on bank indebtedness incurred on a $600 million credit facility that Pengrowth fully repaid on July 13, 2007 and debt relating to the ConocoPhillips properties (“CP properties”) acquisition. Approximately 65 percent of Pengrowth’s outstanding long term debt as at December 31, 2008 incurs interest that is payable in U.S. dollars and therefore the recorded amount of interest expense is subject to fluctuations in the U.S. dollar exchange rate.

18 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Cash G&A expense		13.7		11.3		12.4		48.9		50.5
$  per boe		1.79		1.52		1.60		1.63		1.58
Non-cash G&A expense		3.5		1.9		1.8		10.0		5.4
$  per boe		0.45		0.26		0.22		0.33		0.17
Total G&A		17.2		13.2		14.2		58.9		55.9
$  per boe		2.24		1.78		1.82		1.96		1.75

The cash component of general and administrative (G&A) expenses for the fourth quarter of 2008 compared to the third quarter of 2008 increased $2.4 million. This increase is primarily due to higher professional fees and fees for annual reserve reporting, $0.3 million increase in legal fees and $1.0 million for the estimated reimbursement of G&A incurred by the Manager, pursuant to the management agreement. Cash G&A decreased $1.6 million year-over year due to the absence of the CP properties transition services fees of $3.0 million and lower legal fees of $2.4 million offset by increased charges of $2.2 million related to relocating to offices in Livingston Place.

The non-cash component of G&A represents the compensation expense associated with Pengrowth’s Long Term Incentive Programs (LTIP) including trust unit rights and deferred entitlement units. The increase comparing the fourth quarter of 2008 compared to the third quarter of 2008 and the comparative periods of 2007 is due to higher LTIP expenses resulting from an improvement to the performance multiplier and from granting additional trust units under the LTIP as a result of the increased number of employees.

Total G&A expenses per boe are expected to increase slightly in 2009 when compared to 2008. On a per boe basis, G&A is anticipated to be approximately $2.37 per boe for full year 2009, which includes non-cash G&A and anticipated management fees of approximately $0.21 per boe.

MANAGEMENT FEES

	Three months ended								Twelve months ended
($ millions)	Dec 31, 2008			Sept 30, 2008		Dec 31, 2007			Dec 31, 2008		Dec 31, 2007
Management Fee		(2.0	)		3.0		(2.2	)		7.0		6.8
$  per boe		(0.26	)		0.40		(0.28	)		0.23		0.21

Commencing July 1, 2006, for the remaining three year term, the maximum fees payable to the Manager are limited to 60 percent of the fees that would have been payable under the original agreement or $12 million, whichever is lower, plus certain expenses. The current agreement expires on June 30, 2009 and does not contain a further right of renewal. 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.

Upon expiry of the contract, Mr. James S. Kinnear will continue in the capacity of Chairman and Chief Executive Officer of the Corporation under the terms of a traditional executive contract.

Management fees are lower in the fourth quarter of 2008 compared to the third quarter, and relatively consistent for the full year of 2008 and fourth quarter of 2008 compared to the same periods of 2007 due to the performance fee component of the calculation. The performance fee is only paid when a specific rate of return to unitholders is achieved over a three year period. In the fourth quarter of the year, a final calculation of amounts due under the contract is performed.

Management fees are expected to be approximately $0.21 per boe for the full year of 2009.

PENGROWTH 2008 | MD&A 19

MANAGEMENT’S DISCUSSION AND ANALYSIS

RELATED PARTY TRANSACTIONS

Details of related party transactions undertaken in 2008 and 2007 are provided in Note 17 to the financial statements. These transactions include the management fees paid to the Manager. The Manager is controlled by James S. Kinnear, the Chairman, President and Chief Executive Officer of the Corporation. The management fees paid to the Manager are pursuant to a management agreement which has been approved by the trust unitholders. Mr. Kinnear does not receive any salary or bonus in his capacity as a director and officer of the Corporation and has not received any new trust unit options or rights since November 2002.

Related party transactions in 2008 also include $1.0 million (2007 — $1.1 million) paid to a law and corporate finance firm controlled by the Vice President and Corporate Secretary of the Corporation, Charles V. Selby. These fees are paid in respect of legal and advisory services provided by the Vice President and Corporate Secretary of the Corporation. Mr. Selby does not receive a salary from Pengrowth but has been granted trust unit rights and deferred entitlement units from time to time, the costs of which are not included in the legal fees. During 2008, the Vice President and Corporate Secretary was granted 23,670 trust unit rights and 3,945 DEUs (2007 — 20,901 trust unit rights and 3,484 DEUs).

TAXES

In determining its taxable income, the Corporation deducts payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing the Corporation’s taxable income to nil. Under the Corporation’s current distribution policy, at the discretion of the board, funds can be withheld to fund future capital expenditures, repay debt or used for other corporate purposes. If withholdings increased sufficiently or the Corporation’s tax pool balances were reduced sufficiently, the Corporation could become subject to taxation on a portion of its income in the future. This can be mitigated through various options including the issuance of additional trust units, increased tax pools from additional capital spending, modifications to the distribution policy or potential changes to the corporate structure.

Bill C-52 Budget Implementation Act 2007

Bill C-52 modifies the taxation of certain flow-through entities including mutual fund trusts referred to as “specified investment flow-through” entities or “SIFTS” and the taxation of distributions from such entities (the “SIFT Legislation”). Bill C-52 applies a tax at the trust level on distributions of certain income from such a SIFT trust at a rate of tax comparable to the combined federal and provincial corporate tax rate. These distributions will be treated as dividends to the trust unitholders.

Pengrowth believes that it is characterized as a SIFT trust and, as a result, will be subject to Bill C-52 commencing on January 1, 2011 subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of “undue expansion”. Pengrowth may lose the benefit of the grandfathering period, which ends December 31, 2010, if Pengrowth exceeds the limits on the issuance of new trust units and convertible debt that constitute normal growth during the grandfathering period (subject to certain exceptions). The normal growth limits are calculated as a percentage of Pengrowth’s market capitalization of approximately $4.8 billion on October 31, 2006. The normal growth guidelines have been revised to accelerate the safe harbour amount for each of 2009 and 2010. As of December 31, 2008 Pengrowth may issue $4.22 billion of equity in total for 2009 and 2010 under the safe harbour provision. The normal growth restriction on trust unit issuance is monitored by management as part of the overall capital management objectives. Pengrowth is in compliance with the normal growth restrictions.

Based on existing tax legislation, the tax rate in 2011 is expected to be 26.5 percent and 25 percent in 2012 and subsequent years. The payment of this tax will reduce the amount of cash available for distribution to unitholders.

On July 14, 2008, Finance released for comment proposed amendments to the Income Tax Act (Canada) to facilitate the conversion of existing income trusts and other public flow through entities into corporations on a tax deferred basis. On January 27, 2009, Finance introduced a notice of ways and mean motion in Parliament to implement the conversion rules. The conversion rules would provide an existing income trust with tax efficient structuring options to convert to a corporate form. The conversion rules would be available to Pengrowth if Pengrowth determines to convert to a corporation. The transition provisions are only available to trusts that convert prior to 2013. Accordingly, Pengrowth has four more years before a final course of action would have to be adopted and Pengrowth can continue to have the benefit of its tax structure through December 31, 2010. Commencing in 2011, Pengrowth would be subject to the SIFT tax and would utilize existing tax pools to mitigate a portion of the SIFT tax, should it remain a trust for any period after January 1, 2011.

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. Pengrowth currently has available tax pool balances of approximately $3 billion, which will be considered in identifying the alternatives and timing of our response to the enactment of the SIFT Legislation.

20 MD&A | PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

Future Income Taxes

Future income tax is a non-cash item relating to temporary differences between the accounting and tax basis of Pengrowth’s assets and liabilities and has no immediate impact on Pengrowth’s cash flows. During the fourth quarter of 2008, Pengrowth recorded a future tax recovery of $3.7 million to reflect temporary differences primarily relating to recording an unrealized mark-to-market gain.

FOREIGN CURRENCY GAINS & LOSSES

Pengrowth recorded a $189.2 million net foreign exchange loss in 2008, compared to a $61.9 million gain in 2007. Included in the loss is a $181.8 million unrealized foreign exchange loss related to the translation of the U.S. dollar denominated debt and a $9.2 million unrealized foreign exchange gain for the U.K. Pound Sterling denominated debt using the closing exchange rate at the end of each year. Pengrowth has mitigated the foreign exchange risk on the interest and principal payments related to the U.K. Pound Sterling denominated notes (see Note 9 to the financial statements) by using foreign exchange swaps.

Revenues are recorded at the average exchange rate for the production month in which they accrue, with payment being received on or about the 25th of the following month. As a result of the changes in the Canadian dollar relative to the U.S. dollar over the course of the year, a foreign exchange loss was recorded to the extent that there was a difference between the average exchange rate for the month of production and the exchange rate at the date the payments were received on that portion of production sales that are received in U.S. dollars. The amount recorded in 2008 was not material.

Pengrowth has arranged a portion of its long term debt in U.S. dollars as a natural hedge against changes in the Canadian dollar. As revenues are based on U.S. dollar benchmarks, a lower U.S. dollar has changed oil and gas sales, this is partially offset by a reduction in the U.S. dollar denominated interest cost. (See Note 15 to the financial statements.)

DEPLETION, DEPRECIATION AND ACCRETION

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2008		Sept 30, 2008		Dec 31, 2007		Dec 31, 2008		Dec 31, 2007
Depletion and depreciation		157.6		151.5		156.0		609.3		639.1
$  per boe		20.55		20.34		20.11		20.31		20.03
Accretion		7.3		7.1		6.5		28.1		25.7
$  per boe		0.95		0.95		0.84		0.93		0.81

Depletion and depreciation of property, plant and equipment is calculated on the unit of production method based on total proved reserves.

Pengrowth’s Asset Retirement Obligations (ARO) liability changes from net acquisitions and by the amount of accretion, which is a charge to net income over the lifetime of the producing oil and gas assets.

CEILING TEST

Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties, and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties, and the cost of major development projects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate, when required. There was a significant surplus in the Canadian GAAP ceiling test at year-end 2008.

As required annually under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at ten percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. At December 31, 2008, the application of the full cost ceiling test under U.S. GAAP resulted in an after tax write-down of capitalized costs of $1,101.6 million. At December 31, 2007, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs. As per Note 24 to the consolidated financial statements, in December 2008, the Securities and Exchange Commission published final updated rules for disclosure of oil and gas reserves by public companies.

PENGROWTH 2008 | MD&A 21

MANAGEMENT’S DISCUSSION AND ANALYSIS

The new rules include using the average of the commodity prices on the first day of each month of the year rather than year end pricing for impairment testing, in addition to a number of changes to reserve reporting. These changes are effective for reporting on or after January 1, 2010. For Pengrowth, these changes will take effect for the December 31, 2009 year end. Pengrowth anticipates a significant impact on the future write-downs of capitalized costs. Under the new rules, it is unlikely Pengrowth would have recorded any impairment of capitalized costs for the year ended December 31, 2008.

ASSET RETIREMENT OBLIGATIONS

The total future ARO is based on management’s estimate of costs to remediate, reclaim and abandon wells and facilities having regard for Pengrowth’s working interest and the estimated timing of the costs to be incurred in future periods. Pengrowth has developed an internal process to calculate these estimates which considers applicable regulations, actual and anticipated costs, type and size of well or facility and the geographic location. Pengrowth has estimated the net present value of its total ARO to be $344 million as at December 31, 2008 (December 31, 2007 — $352 million), based on a total escalated future liability of $2,283 million (December 31, 2007 – $2,015 million). These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2040 and 2054. A credit adjusted risk free rate of eight percent and an inflation rate of two percent per annum were used to calculate the net present value of the ARO.

REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE

During 2008, Pengrowth contributed $9.3 million into trust funds established to fund certain abandonment and reclamation costs associated with Judy Creek and SOEP. The balance in these remediation trust funds was $27.1 million at December 31, 2008.

Every five years Pengrowth must evaluate the value of the assets in the Judy Creek remediation trust fund and the outstanding ARO, and make recommendations to the former owner of the Judy Creek properties as to whether contribution levels should be changed. The next evaluation is anticipated to occur in 2012. Contributions to the Judy Creek remediation trust fund may change based on future evaluations of the fund.

As an interest holder in SOEP, Pengrowth is under a contractual obligation to contribute to a remediation trust fund. The funding levels are based on the feedstock handled and delivered to the various facilities; funding levels for this fund may change each year pending a review by the owners.

Pengrowth takes a proactive approach to managing its well abandonment and site restoration obligations. There is an on-going program to abandon wells and reclaim well and facility sites. In 2008, Pengrowth spent $32.7 million on abandonment and reclamation (2007 — $11.4 million). The increase in 2008 was due to an expanded program to meet regulatory requirements for certain wells purchased through the CP properties acquisition and higher than expected abandonment costs in the Red Earth and Fenn Big Valley areas. Pengrowth expects to spend approximately $29.0 million for 2009, excluding contributions to remediation trust funds on remediation and abandonment.

CLIMATE CHANGE PROGRAMS

In Alberta, climate change regulations became effective July 1, 2007. These regulations require Alberta facilities that emit more than 100,000 tonnes of greenhouse gases a year to reduce emissions intensity by 12 per cent over the average emission levels of 2003, 2004 and 2005. Companies can make their reductions through improvements to their operations; by purchasing Alberta-based offset credits or by contributing to the Climate Change and Emissions Management Fund. Pengrowth currently operates two facilities that are subject to the Alberta climate change regulations. Collectively these facilities have reduced emissions by fifteen percent from the base line emissions (2007 data). This reduction is an improvement over current-day requirements. Pengrowth is assessing options for meeting future greenhouse gas emission requirements. However, if the emissions remain at the current levels, Pengrowth would experience additional annual costs of as much as $0.5 million. For further information, see Pengrowth’s AIF. Recently, the Government of Canada announced a draft climate change plan outlining a 20 percent reduction by 2020. Pengrowth is waiting on additional information to assess the impact the plan will have on its operations.

OTHER EXPENSES

The decrease in other expenses comparing year-over-year relates to equity income of $1.4 million and a dilution gain of $1.8 million recorded in 2008 relating to Pengrowth’s investment in Monterey Exploration Ltd offset by increased Saskatchewan capital tax of $5.1 million.

22 MD&A |PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

GOODWILL

As at December 31, 2008, Pengrowth recorded goodwill of $660.9 million, an increase of $0.3 million from December 31, 2007. The increase in goodwill is related to a revision of the purchase price allocation on CP properties. Details of the acquisition are provided in Note 4 of the financial statements. Management has assessed goodwill for impairment and determined there is no impairment at December 31, 2008.

CAPITAL EXPENDITURES

	Three months ended									Twelve months ended
($ millions)	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Seismic acquisitions(1)(2)		0.5			2.0			(0.5	)		7.6			6.1
Drilling, completions and facilities(1)		82.6			64.2			71.2			276.5			226.7
Maintenance capital(1)		26.2			13.0			15.4			57.5			37.1
Land purchases		0.1			17.9			2.7			26.7			13.2
Development capital		109.4			97.1			88.8			368.3			283.1
Lindbergh Project		10.4			3.0			—			20.0			—
Other capital		3.8			(0.6	)		6.9			13.6			26.6
Total capital expenditures		123.6			99.5			95.7			401.9			309.7
Business acquisitions(3)		0.2			90.2			(0.6	)		90.4			923.1
Property acquisitions		0.2			18.1			9.0			35.9			9.0
Proceeds on property dispositions		(20.4	)		0.1			(23.7	)		(17.4	)		(458.8	)
Net capital expenditures and acquisitions		103.6			207.9			80.4			510.8			783.0

(1)	Prior year restated to conform to presentation adopted in current year.
(2)	Seismic acquisitions are net of seismic sales revenue.
(3)	Accrete acquisition valued at consideration paid (see Note 4 of consolidated financial statements).

For the full year of 2008, Pengrowth spent $368.3 million on development and optimization activities. The largest expenditures were at Heavy Oil Properties ($26.2 million), Harmattan and Olds ($24.0 million), Judy Creek ($24.6 million), Fenn Big Valley ($ 23.9 million) Northeast B.C. ($18.2 million), Carson Creek ($24.4 million), Red Earth ($16.4 million), and Deer Mountain ($13.5 million). In addition to development activities, $20.0 million was spent on the Lindbergh project and $13.6 million was spent on office premises and Information Technology (IT).

Pengrowth currently anticipates the 2009 capital development program to be $209 million. The 2009 capital development program represents a reduction of expenditures of approximately 46 percent compared with 2008 expenditures of $388 million. Included in the capital program are planned expenditures of $20 million for the oilsands pilot project at Lindbergh. The current commodity price outlook has necessitated much lower capital funding than recent levels as Pengrowth relies on undistributed cash from operations to partially fund the capital program. In deciding which projects to fund, Pengrowth reviewed its extensive portfolio and identified those projects that created the greatest economic value. Those projects which created the greatest value for each capital dollar invested were preferentially identified for the budget. Pengrowth also anticipates spending approximately $6 million on Information Technology and office premises.

RESERVES

Pengrowth’s 2008 development program resulted in 23.9 mmboe’s of proved plus probable reserve additions including revisions, resulting in a finding and development cost of $16.27 per boe. Including net acquisitions of 9.7 mmboe’s, finding, development and acquisition costs were $15.47 per boe on a proved plus probable basis. The reserve additions result in a reserve replacement of 80 percent for Total Proved plus Probable Reserves excluding acquisitions, and 112 percent including acquisitions.

Pengrowth reported year-end proved reserves of 235.2 mmboe and proved plus probable reserves of 323.5 mmboe for 2008 compared to 241.2 mmboe and 319.9 mmboe, respectively at year end 2007. Further details of Pengrowth’s 2008 year-end reserves will be provided in the AIF.

PENGROWTH 2008 | MD&A 23

MANAGEMENT’S DISCUSSION AND ANALYSIS

ACQUISITIONS AND DISPOSITIONS

During the fourth quarter of 2008, Pengrowth completed the divestiture of certain non-core, non-producing lands in the Dawson area in British Columbia. Proceeds of the disposition were approximately $27 million, with $21 million received in 2008.

On September 30, 2008, Pengrowth and Accrete completed a business combination (the “Combination”). Under the terms of the Combination, each Accrete share was exchanged for 0.277 of a Pengrowth trust unit. Pengrowth also assumed $22 million of net liabilities which included $16 million of bank debt. As a result of the Combination, approximately five million Pengrowth trust units were issued to Accrete shareholders. The value assigned to each Pengrowth unit issued was approximately $17.95 per trust unit based on the weighted average market price of the trust units on the five days surrounding the announcement of the Combination. In conjunction with the Combination, all of Accrete’s oil and gas properties except those in the Harmattan area were transferred to Argosy Energy Inc., an unrelated company.

During the third quarter of 2008, Pengrowth completed the acquisition of additional working interest in the Harmattan area from Fairmount Energy Inc. for $12 million. Also in the third quarter of 2008, Pengrowth purchased additional working interest in both the Carson Creek area and the Garrington area.

During the second quarter of 2008, Pengrowth completed property acquisitions of approximately $17 million, which included exercising a right of first refusal in Three Hills and purchasing additional working interest at Swan Hills.

In the first quarter of 2007, Pengrowth closed the acquisition of the shares of four subsidiaries of Burlington Resources Canada Ltd., a subsidiary of ConocoPhillips, holding Canadian oil and natural gas producing properties and undeveloped lands for a purchase price of $1.0375 billion, prior to adjustments.

WORKING CAPITAL

The working capital deficiency decreased by $119.4 million from $189.6 million at December 31, 2007 to $70.2 million at December 31, 2008. Most of the decrease in the working capital deficiency is attributable to an increase in the value of risk management contracts, where there is a net non-cash current asset at December 31, 2008 of $120.1 million compared to net non-cash current liability of $62.8 million at December 31, 2007. Liabilities and assets relating to commodity risk management activities are estimated and recognized in the current period, but will only be settled during future period sales, at amounts that may be different than the amount estimated depending on future realized commodity prices. Partially offsetting the effect of the risk management contracts was a change in future taxes which changed from a current future tax asset of $18.8 million at December 31, 2007 to a current future tax liability of $34.9 million at December 31, 2008.

Pengrowth frequently operates with a working capital deficiency, as distributions relating to two production months are payable to unitholders at the end of any month, but cash flow from one month of production is still receivable. For example, at the end of December, distributions related to November and December production months being payable on January 15 and February 15, respectively. November’s production revenue, received on December 25, is temporarily applied against Pengrowth’s term credit facility until the distribution payment on January 15.

24 MD&A |PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

FINANCIAL RESOURCES AND LIQUIDITY

Pengrowth’s capital structure is as follows:

($ thousands)	Dec 31,			Dec 31,
As at:	2008			2007
Term credit facilities	$	372,000		$	513,998
Senior unsecured notes		1,152,503			689,238
Working capital deficit		70,159			189,603
Total debt excluding convertible debentures	$	1,594,662		$	1,392,839
Convertible debentures		74,915			75,030
Total debt including convertible debentures	$	1,669,577		$	1,467,869
	Dec 31,			Dec 31,
Years ended	2008			2007
Net income (loss)	$	395,850		$	359,652
Add:
Interest expense	$	76,304			84,292
Future tax reduction	$	(71,925	)		(264,612	)
Depletion, depreciation, amortization and accretion	$	637,377			664,806
Other non-cash (income) expenses	$	(26,864	)		90,497
EBITDA	$	1,010,742		$	934,635
Total debt excluding convertible debentures to EBITDA		1.6			1.5
Total debt including convertible debentures to EBITDA		1.7			1.6
Total capitalization excluding convertible debentures(1)	$	4,188,308		$	3,959,456
Total capitalization including convertible debentures	$	4,263,223		$	4,034,486
Total debt excluding convertible debentures as a percentage of total capitalization		38.1	%		35.2	%
Total debt including convertible debentures as a percentage of total capitalization		39.2	%		36.4	%

(1) Total capitalization includes total debt plus Unitholders Equity. (Total debt excludes working capital deficit)

The $202.8 million increase in debt, excluding convertible debentures from December 31, 2007, is primarily attributable to increased unrealized foreign exchange losses on foreign denominated debt. This increase in debt excluding convertible debentures resulted in the debt excluding convertible debentures to EBITDA multiple to increase compared to December 31, 2007. Although debt excluding convertible debentures was higher at December 31, 2008 compared to December 31, 2007, the increase in EBITDA, primarily from higher average realized commodity prices, more than offset lower production volumes and higher operating and royalty expenses in 2008 which resulted in little change to the ratio.

Capital spending and acquisitions may be funded by the excess of cash flows from operating activities over distributions declared, through additional debt or the issuance of equity and property dispositions. The credit facilities and other sources of cash are expected to be sufficient to meet Pengrowth’s near term capital requirements and provide the flexibility to pursue profitable growth opportunities. A significant decline in oil and natural gas prices could affect our access to bank credit facilities and our ability to fund operations, maintain distributions and pursue profitable growth opportunities.

PENGROWTH 2008 | MD&A 25

MANAGEMENT’S DISCUSSION AND ANALYSIS

Pengrowth has implemented an Equity Distribution Program which will permit Pengrowth to distribute up to 25,000,000 trust units from time to time until January of 2010 through the New York Stock Exchange (NYSE) or the Toronto Stock Exchange (TSX). The shelf prospectus enabling the at-the-market distribution expired in the fourth quarter of 2008. Although the Equity Distribution Agreement is still in effect, no units can be issued until a new shelf prospectus is filed. No trust units were issued under the Equity Distribution Program during the year ended December 31, 2008.

At December 31, 2008, Pengrowth maintained a committed $1.2 billion term credit facility with a syndicate of seven Canadian banks and four foreign banks for a remaining term of 2 1/2 years and a $50 million operating line of credit. The credit facilities were reduced by drawings of $372 million on a revolver loan and by outstanding letters of credit of approximately $12 million.

Pengrowth expects to be able to fund its 2009 development program and to take advantage of acquisition opportunities as they arise. At December 31, 2008, Pengrowth had approximately $864 million available to draw from its credit facilities.

Unitholders are eligible to participate in the Distribution Reinvestment Plan (DRIP). DRIP entitles the unitholder to reinvest cash distributions in additional units of the Trust. The trust units under the plan are issued from treasury at a five percent discount to the weighted average closing price of all trust units traded on the TSX for the 20 trading days preceding a distribution payment date. For the year ended December 31, 2008, 3.7 million trust units were issued for cash proceeds of $59.4 million under the DRIP compared to 2.5 million trust units for cash proceeds of $44.9 million at December 31, 2007.

Pengrowth does not have any off balance sheet financing arrangements.

There have been no significant changes to the number of trust units outstanding since December 31, 2008.

On August 21, 2008, Pengrowth closed a U.S. $265 million private placement of senior unsecured notes. The notes bear interest at 6.98 percent and are due August 2018. The notes contain certain financial maintenance covenants and interest is paid semi-annually. Costs incurred in connection with issuing the notes, in the amount of $1.5 million, were deducted from the carrying amount of the debt and are being amortized to income using the effective interest method over the expected term of the notes.

On August 21, 2008, Pengrowth closed a Cdn $15 million private placement of senior unsecured notes. The notes bear interest at 6.61 percent and are due August 2018. The notes contain certain financial maintenance covenants and interest is paid semi-annually.

Pengrowth’s U.S. $865 million, Cdn $15 million and, U.K. Pound Sterling denominated £50 million senior unsecured notes and the credit facilities have certain financial covenants, which may restrict the total amount of Pengrowth’s borrowings. The calculation for each financial covenant is based on specific definitions, is not in accordance with GAAP and cannot be readily replicated by referring to Pengrowth’s financial statements. The financial covenants are different between the credit facilities and the senior unsecured notes and some of the covenants are summarized below:

1. Total senior debt should not be greater than three times EBITDA

2. Total debt should not be greater than 3.5 times EBITDA for the last four fiscal quarters

3. Total senior debt should be less than 50 percent of total book capitalization

4. EBITDA should not be less than four times interest expense

In the event that Pengrowth enters into a significant acquisition, certain credit facility financial covenants are relaxed for two fiscal quarters after the close of the acquisition. Pengrowth may also make certain pro forma adjustments in calculating the financial covenant ratios.

26 MD&A |PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

The actual loan documents are filed on SEDAR as “Other” or “Material document”. As at December 31, 2008, Pengrowth was in compliance with all its financial covenants. Failing a financial covenant may result in one or more of Pengrowth’s loans being in default. In certain circumstances, being in default of one loan will, absent a cure, result in other loans to also be in default. In the event that Pengrowth was not in compliance with any one of the financial covenants in its credit facility or senior unsecured notes, Pengrowth would be in default of one or more of its loans and would have to repay the debt, refinance the debt or negotiate new terms with the debt holders and may have to suspend distributions to unitholders.

As a result of the October 2, 2006 business combination with Esprit Trust, Pengrowth assumed all of Esprit Trust’s 6.5 percent convertible unsecured subordinated debentures (the “debentures”). 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. As at December 31, 2008, the principal amount of debentures outstanding was $74.7 million.

Financial Instruments

Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations, foreign currency and interest rate exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes. Please see Note 2 of the financial statements for a description of the accounting policies for financial instruments. Please see Note 20 of the financial statements for additional information regarding market risk, credit risk, liquidity risk and fair value of Pengrowth’s financial instruments.

CASH FLOWS AND DISTRIBUTIONS

The following table provides cash flows from operating activities, net income and distributions declared with the excess (shortfall) over distributions and the ratio of distributions declared over cash flows from operating activities:

($ thousands, except per trust unit amounts)	Three months ended									Twelve months ended
	Dec 31, 2008			Sept 30, 2008			Dec 31, 2007			Dec 31, 2008			Dec 31, 2007
Cash flows from operating activities		154,807			273,597			196,325			912,516			800,344
Net income/(loss)		148,688			422,395			(3,665	)		395,850			359,652
Distributions declared		144,663			170,959			166,631			651,015			706,601
Distributions declared per trust unit		0.565			0.675			0.675			2.590			2.875
Excess of cash flows from operating activities over distributions declared		10,144			102,638			29,694			261,501			93,743
Per trust unit		0.04			0.41			0.12			1.05			0.38
Excess (shortfall) of net income (loss) over distributions declared		4,025			251,436			(170,296	)		(255,165	)		(346,949	)
Per trust unit		0.02			1.01			(0.69	)		(1.02	)		(1.41	)
Ratio of distributions declared over cash flows from operating activities		93	%		62	%		85	%		71	%		88	%

Distributions typically exceed net income as a result of non-cash expenses which may include unrealized losses on commodity risk; depletion, depreciation, and amortization; future income tax expense; trust unit based compensation; and accretion. These non-cash expenses result in a reduction to net income, with no impact to cash flow from operating activities. Pengrowth’s goal over longer periods of time is to maximize returns to the unitholders through cash distributions on a per Trust Unit basis and enhancing the value of the Trust Units. Accordingly, we expect that distributions will exceed net income in most periods. In most periods, we would not expect distributions to exceed cash flows from operating activities. In the event distributions exceed cash flows from operating activities, the shortfall would be funded by available bank facilities. The most likely circumstance for this to occur would be where there is a significant negative impact to working capital during the reporting period.

PENGROWTH 2008 | MD&A 27

MANAGEMENT’S DISCUSSION AND ANALYSIS

As a result of the depleting nature of Pengrowth’s oil and gas assets, capital expenditures are required to offset production declines while other capital is required to maintain facilities, acquire prospective lands and prepare future projects. Capital spending and acquisitions may be funded by the excess of cash flows from operating activities over distributions declared, through additional debt or the issuance of equity. Pengrowth does not deduct capital expenditures when calculating cash flows from operating activities. However, Pengrowth does deduct costs associated with environmental activities when calculating cash flows from operating activities.

Notwithstanding the fact that cash flow from operating activities normally exceeds distributions, the difference is not sufficient to fund the capital spending required to fully replace production. That difference is funded by equity or a combination of equity and debt. Accordingly, Pengrowth believes our distributions include a return of capital.

Forecasted development capital spending in 2009 of $209 million will not be sufficient to fully replace the oil and gas reserves Pengrowth expects to produce during the year. If the produced reserves are not offset in the future by additional capital or acquisitions, future distributions could be impacted. Pengrowth has historically paid distributions at a level that includes a portion which is a return of capital to its investors. From time to time Pengrowth may issue additional trust units to fund capital programs and acquisitions. Investors can elect to participate in the distribution re-investment program.

Cash flows from operating activities are derived from producing and selling oil, natural gas and related products. As such, cash flow from operating activities is highly dependent on commodity prices. Pengrowth entered into forward commodity contracts to mitigate price volatility and to provide a measure of stability to monthly cash flows. Details of commodity contracts are contained in Note 20 to the financial statements.

The board of directors and management regularly review the level of distributions. The board considers a number of factors, including expectations of future commodity prices, capital expenditure requirements, and the availability of debt and equity capital. Pursuant to the Royalty Indenture, the board can establish a reserve for certain items including up to 20 percent of the Corporation’s gross revenue to fund various costs including future capital expenditures, royalty income in any future period and future abandonment costs. As a result of the volatility in commodity prices, changes in production levels and capital expenditure requirements, there can be no certainty that Pengrowth will be able to maintain current levels of distributions and distributions can and may fluctuate in the future. In the current production and price environment, the possibility of suspending distributions in the near future is unlikely, but the amount may vary. Pengrowth has no restrictions on the payment of its distributions other than maintaining its financial covenants in its borrowings.

Cash distributions are generally paid to unitholders on or about the 15th day of the second month following the month of production. Pengrowth paid $0.62 per trust unit as cash distributions during the fourth quarter of 2008 and $2.645 per trust unit for the full year of 2008 compared to $0.675 and $2.93 for the comparable periods in 2007.

TAXABILITY OF DISTRIBUTIONS

In 2008, 100 percent of Pengrowth’s 2008 distributions and 100 percent of 2009 distributions are anticipated to be taxable to Canadian 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 provisions of the Income Tax Act (Canada), distributions to U.S. unitholders of amounts in excess of Pengrowth’s income (i.e. returns of capital) are also subject to a 15 percent Canadian withholding tax. On September 21, 2007, Canada and the United States signed the fifth protocol of the Canada-United States Tax Convention (the “Protocol”) which increases the amount of Canadian withholding tax from 15 percent to 25 percent on distributions of income. The Protocol came into force on December 15, 2008. The increase in the Canadian withholding tax rate on distributions 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 on and after January 1, 2010. Residents of the U.S. should consult their individual tax advisors on the impact of any additional Canadian withholding tax. The Canadian withholding tax rate on distributions paid to unitholders in other countries varies based on individual tax treaties.

28 MD&A |PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

($ thousands)	2009		2010		2011		2012		2013		thereafter		Total
Long term debt(1)		—		182,180		372,000		—		60,900		925,459		1,540,539
Interest payments on long term debt(2)		72,313		66,308		63,306		63,306		61,085		230,955		557,273
Convertible debentures(3)		—		74,700		—		—		—		—		74,700
Interest payments on convertible debentures(4)		4,810		4,810		—		—		—		—		9,620
Other(5)		10,797		10,427		9,560		7,646		8,107		31,735		78,272
		87,920		338,425		444,866		70,952		130,092		1,188,149		2,260,404
Purchase obligations
Pipeline transportation		40,468		22,006		19,326		16,405		16,046		26,462		140,713
CO2 purchases(6)		2,919		2,943		2,601		2,352		2,365		5,475		18,655
		43,387		24,949		21,927		18,757		18,411		31,937		159,368
Remediation trust fund payments		250		250		250		250		250		11,250		12,500
		131,557		363,624		467,043		89,959		148,753		1,231,336		2,432,272

(1)	The debt repayment includes the principal owing at maturity on foreign denominated fixed rate debt. (see Note 4 of the financial statements)
(2)	Interest payments relate to the interest payable on the fixed rate debt. Foreign denominated debt is translated using the year-end exchange rate.
(3)	Includes repayment of convertible debentures on maturity (see Note 14 of the financial statements), and assumes no conversion of convertible debentures to trust units.
(4)	Includes annual interest on convertible debentures outstanding at year-end and assumes no conversion of convertible debentures prior to maturity.
(5)	Includes office rent and vehicle leases.
(6)	For the Weyburn CO2 project, prices are denominated in U.S. dollars and have been translated at the year-end exchange rate. For the Judy Creek CO2 Pilot Project, Prices are denominated in Canadian dollars.

SUMMARY OF TRUST UNIT TRADING DATA

							Volume		Value
	High		Low		Close		(000’s)		($ millions)
TSX — PGF.UN ($ Cdn)
2008 1st quarter		19.82		14.16		19.67		30,755		557.9
2nd quarter		21.56		19.17		20.50		28,004		569.7
3rd quarter		20.55		14.73		15.99		31,735		565.4
4th quarter		15.98		8.55		9.35		35,035		402.7
Year		21.56		8.55		9.35		125,529		2,095.7
2007 1st quarter		20.85		18.62		19.45		37,742		744.8
2nd quarter		21.04		18.82		20.27		28,348		561.5
3rd quarter		20.70		16.92		18.64		27,970		524.5
4th quarter		18.68		17.00		17.62		23,559		423.1
Year		21.04		16.92		17.62		117,619		2,253.9
NYSE — PGH ($ U.S.)
2008 1st quarter		19.47		13.67		19.10		14,293		257.5
2nd quarter		21.90		18.86		20.11		19,425		392.7
3rd quarter		20.20		14.16		14.94		26,815		457.7
4th quarter		15.00		6.84		7.62		41,776		401.2
Year		21.90		6.84		7.62		102,309		1,509.1
2007 1st quarter		17.96		15.82		16.87		26,633		449.1
2nd quarter		19.84		16.45		19.09		23,668		428.6
3rd quarter		19.85		16.25		18.84		19,284		346.9
4th quarter		19.21		17.30		17.77		13,980		256.4
Year		19.85		15.82		17.77		83,565		1,481.0

PENGROWTH 2008 | MD&A 29

MANAGEMENT’S DISCUSSION AND ANALYSIS

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly information for 2008 and 2007.

2008	Q1			Q2			Q3		Q4
Oil and gas sales ($000’s)		457,606			550,623			518,662		392,158
Net income/(loss) ($000’s)		(56,583	)		(118,650	)		422,395		148,688
Net income/(loss) per trust unit ($)		(0.23	)		(0.48	)		1.69		0.58
Net income/(loss) per trust unit — diluted ($)		(0.23	)		(0.48	)		1.69		0.58
Cash flow from operating activities ($000’s)		216,238			267,874			273,597		154,807
Distributions declared ($000’s)		167,234			168,159			170,959		144,663
Distributions declared per trust unit ($)		0.675			0.675			0.675		0.565
Daily production (boe)		82,711			80,895			80,981		83,373
Total production (mboe)		7,527			7,361			7,450		7,670
Average realized price ($  per boe)		60.30			73.21			67.71		50.34
Operating netback ($  per boe)(1)		33.62			42.15			37.48		26.23

2007	Q1			Q2		Q3		Q4
Oil and gas sales ($000’s)		432,108			443,977		420,704		425,249
Net income/(loss) ($000’s)		(69,834	)		271,659		161,492		(3,665	)
Net income/(loss) per trust unit ($)		(0.29	)		1.11		0.66		(0.01	)
Net income/(loss) per trust unit — diluted ($)		(0.29	)		1.10		0.66		(0.01	)
Cash flow from operating activities ($000’s)		136,429			249,960		217,630		196,325
Distributions declared ($000’s)		183,534			184,327		172,109		166,631
Distributions declared per trust unit ($)		0.75			0.75		0.70		0.675
Daily production (boe)		90,068			89,633		85,654		84,331
Total production (mboe)		8,106			8,157		7,880		7,758
Average realized price ($  per boe)		53.30			54.39		53.34		54.58
Operating netback ($  per boe)		29.87			29.56		32.66		29.56

(1) Restated to conform to presentation adopted in the current period.

Production changes over these quarters was a result of property dispositions completed by Pengrowth throughout 2007, production limitations due to plant turnarounds and unscheduled maintenance in the second, third and fourth quarters of 2008 and property acquisition in the fourth quarter of 2008. Changes in commodity prices have positively affected oil and gas sales, which have been partially muted by risk management activity to mitigate price volatility and to provide a measure of stability to monthly cash flows . Net income in 2007 and 2008 has been impacted by non-cash charges, in particular depletion, depreciation and accretion, unrealized mark-to-market gains and losses, unrealized foreign exchange gains and losses and future taxes. Cash flow has not been impacted by the non-cash charges, however, reflects the impact of higher operating and general and administrative costs.

30 MD&A |PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

SELECTED ANNUAL INFORMATION

Oil and gas sales for 2008 increased as a result of higher realized prices through the third quarter. Higher production volumes in 2007 contributed to increased oil and gas sales due to a full year of production from the Carson Creek and Esprit Trust acquisitions completed late in the third and fourth quarters of 2006 respectively and the CP acquisition completed early in 2007.

	Twelve months ended December 31
($ thousands)	2008		2007		2006
Oil and gas sales		1,919,049		1,722,038		1,214,093
Net income		395,850		359,652		262,303
Net income per trust unit ($)		1.58		1.47		1.49
Net income per trust unit — diluted ($)		1.58		1.46		1.49
Distributions declared per trust unit ($)		2.59		2.875		3.00
Total assets		5,317,341		5,234,251		4,690,129
Long term debt(1)		1,599,418		1,278,266		679,327
Trust unitholders’ equity		2,663,805		2,756,220		3,049,677
Number of trust units outstanding at year end (thousands)		256,076		246,846		244,017

(1) Includes long term debt and convertible debentures.

BUSINESS RISKS

The amount of distributions available to unitholders and the value of Pengrowth trust units are subject to numerous risk factors. As the trust units allow investors to participate in the net cash flow from Pengrowth’s portfolio of producing oil and natural gas properties, the principal risk factors that are associated with the oil and gas business include, but are not limited to, the following influences:

• Continued uncertainty in the credit markets may restrict the availability or increase the cost of borrowing required for future development and acquisitions. This uncertainty may also impair Pengrowth’s normal business counterparties to meet their obligations to Pengrowth. Additional credit risk could exist where little or none previously existed.

• The prices of Pengrowth’s products (crude oil, natural gas, and NGLs) fluctuate due to many factors including local and global market supply and demand, weather patterns, pipeline transportation and political and economic stability.

• The marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Operational or economic factors may result in the inability to deliver our products to market.

• Geological and operational risks affect the quantity and quality of reserves and the costs of recovering those reserves. Our actual results will vary from our reserve estimates and those variations could be material.

• Government royalties, income taxes, commodity taxes and other taxes, levies and fees have a significant economic impact on Pengrowth’s financial results. Changes to federal and provincial legislation governing such royalties, taxes and fees, including implementation of the SIFT Legislation, could have a material impact on Pengrowth’s financial results and the value of Pengrowth trust units.

• Pengrowth could lose its grandfathered status under the SIFT Legislation and become subject to the SIFT tax prior to January 1, 2011 if it exceeds the normal growth guidelines.

• Oil and gas operations carry the risk of damaging the local environment in the event of equipment or operational failure. The cost to remediate any environmental damage could be significant.

• Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We may incur substantial capital and operating expenses 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 future regulations to reduce greenhouse gas and other emissions.

• Pengrowth’s oil and gas reserves will be depleted over time and our level of cash flow from operations and the value of our trust units could be reduced if reserves and production are not replaced. The ability to replace production depends on the amount of capital invested and success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity within the context of the capital markets.

PENGROWTH 2008 | MD&A 31

MANAGEMENTS DISCUSSION AND ANALYSIS

• Increased competition for properties will drive the cost of acquisitions up and expected returns from the properties down.

• Timing of oil and gas operations is dependent on gaining timely access to lands. Consultations, that are mandated by governing authorities, with all stakeholders (including surface owners, First Nations and all interested parties) are becoming increasingly time consuming and complex, and are having a direct impact on cycle times.

• A significant portion of Pengrowth’s properties are operated by third parties. If these operators fail to perform their duties properly, or become insolvent, we may experience interruptions in production and revenues from these properties or incur additional liabilities and expenses as a result of the default of these third party operators.

• During periods of increased activity within the oil and gas sector, the cost of goods and services may increase and it may be more difficult to hire and retain professional staff.

• Changing interest rates influence borrowing costs and the availability of capital.

• Failing a financial covenant may result in one or more of Pengrowth’s loans being in default. In certain circumstances, being in default of one loan will result in other loans to also be in default.

• Investors’ interest in the oil and gas sector may change over time which would affect the availability of capital and the value of Pengrowth trust units.

• Inflation may result in escalating costs, which could impact unitholder distributions and the value of Pengrowth trust units.

• Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs. Pengrowth is also exposed to foreign currency fluctuations on the U.S. dollar denominated notes for both interest and principal payments.

• The value of Pengrowth trust units is impacted directly by the related tax treatment of the trust units and the trust unit distributions, and indirectly by the tax treatment of alternative equity investments. Changes in Canadian or U.S. tax legislation could adversely affect the value of our trust units. As 2011 approaches, the expectation of taxability of distributions may negatively impact the value of trust units.

• Attacks by individuals against facilities and the threat of such attacks may have an adverse impact on Pengrowth and the implementation of security measures as a precaution against possible attacks would result in increased cost to Pengrowth’s business.

• Substantial and sustained reductions in commodity prices or equity markets, including Pengrowth’s unit price, in some circumstances could result in Pengrowth reducing the recorded book value of some of its assets.

• Delays in business operations could adversely affect Pengrowth’s distributions to unitholders and the market price of the trust units.

These factors should not be considered exhaustive. Additional risks are outlined in the AIF of the Trust available on SEDAR at www.sedar.com.

SUBSEQUENT EVENTS

Subsequent to December 31, 2008, Pengrowth has entered into a series of crude oil fixed price commodity sales contracts with third parties as noted below.

Remaining term	Volume (bbl/d)		Reference Point		Price per bbl
Financial:
Mar 1, 2009 - Dec 31, 2009		500	WTI	(1)	$58.00 Cdn
April 1, 2009 - Dec 31, 2009		1,000	WTI	(1)	$57.78 Cdn
Jan 1, 2010 - Dec 31, 2010		5,000	WTI	(1)	$69.06 Cdn

⁽¹⁾ Associated Cdn $/U.S. $ foreign exchange rate has been fixed

OUTLOOK

At this time, Pengrowth is forecasting average 2009 production of 76,000 to 78,000 boe per day from our existing properties. This estimate excludes the impact from future acquisitions or divestitures.

Full year outlook for operating costs for 2009 are expected to increase on a per unit basis to $14.45 per boe.

32 MD&A |PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

Royalty expense is expected to be approximately 22 percent of Pengrowth’s sales for 2009.

G&A expenses per boe are expected to increase slightly in 2009 when compared to 2008. On a per boe basis, G&A is anticipated to be approximately $2.37 for the full year of 2009, including non-cash G&A and anticipated management fees of approximately $0.21 per boe.

The total capital program of $215 million is a reduction of expenditures of approximately 47 percent compared with 2008 full year expenditure of $402 million. Included in the 2009 capital program is $20 million for the oilsands pilot project at Lindbergh and $6 million in office premises and information technology (IT) capital.

Pengrowth expects to spend approximately $29 million for 2009 on remediation and abandonment, excluding contributions to remediation trust funds.

CURRENT GLOBAL ECONOMIC CONDITIONS

Towards the end of 2008, the global economic environment deteriorated rapidly and resulted in a very challenging time for commodity prices, the capital markets and equity values. This deterioration could negatively affect Pengrowth as continued uncertainty in the credit markets may restrict the availability or increase the cost of borrowing required for future development and acquisitions. The dramatic decreases in commodity prices since highs reached in the summer of 2008 negatively impacts operating cash flow and future borrowing capacity. This uncertainty may also impair Pengrowth’s normal business counterparties to meet their obligations to Pengrowth. Additional credit risk could exist where little or none previously existed.

Pengrowth’s guidance on the capital expenditure program for 2009 is focused on reducing risk and repositioning the Trust to adjust to current market conditions. Pengrowth continues to maintain a strong mix of both conventional and non-conventional assets and a solid overall financial structure. Management and the Board of Directors will continue to evaluate both capital expenditures and distribution levels within the context of economic and commodity price outlooks.

RECENT ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2008, Pengrowth adopted new Canadian accounting standards related to capital disclosures. The new standards require disclosure about Pengrowth’s objectives, policies and processes for managing capital. Refer to Note 19 in the notes to the consolidated financial statements.

Effective January 1, 2008, Pengrowth adopted several new and revised Canadian accounting standards related to financial instruments disclosure and presentation. The new standards require additional disclosures regarding the nature and extent of the risks associated with financial instruments and how those risks are managed. The presentation standards for financial instruments under the new handbook section did not change significantly from the previous standards. Refer to Note 20 in the notes to the consolidated financial statements.

On February 13, 2008, the Canadian Accounting Standards Board confirmed that publicly accountable enterprises will be required to adopt International Financial Reporting Standards (“IFRS”) in place of Canadian GAAP for interim and annual periods beginning on or after January 1, 2011. At this time, the impact on Pengrowth’s future financial position and results of operations is not reasonably determinable or estimable.

Pengrowth commenced its IFRS conversion project in 2008 and has established a formal governance structure. This structure includes a full time IFRS Project Coordinator, a steering committee consisting of senior members of the finance team on an ongoing basis and also includes information technology, treasury and operations personnel. Regular reporting is provided to senior management and to the Audit Committee of the Board of Directors. Pengrowth has also engaged an external expert advisory firm.

Pengrowth’s project consists of four phases: diagnostic; design and planning; solution development; and implementation. Pengrowth has completed the diagnostic phase, which involved a high level review of the major differences between Canadian GAAP and IFRS, and identification of potential information systems and process changes. Currently, Pengrowth has determined that the areas of accounting difference with the highest potential impact are accounting for exploration and development activities including classification of exploration and evaluation expenditures, depletion and impairment of capital assets, business combination accounting and asset retirement obligation accounting.

PENGROWTH 2008 | MD&A 33

MANAGEMENT’S DISCUSSION AND ANALYSIS

Pengrowth is currently engaged in the design and planning and solution development phases of our project, working with issue-specific teams to focus on generating options and making recommendations in the identified areas. During the design and planning phase, Pengrowth has initiated training for key personnel and has been involved in documenting the high impact areas identified, including an analysis of discussions with its external advisors and auditors. The impact on disclosure controls and internal controls over financial reporting will also be determined.

In September 2008, the International Accounting Standards Board issued an exposure draft to amend IFRS 1 in respect of property plant and equipment as at the date of initial transition to IFRS. That exposure draft, if adopted, would permit issuers currently using the full cost method of accounting to allocate the balance of property plant and equipment (as determined under Canadian GAAP) to the IFRS categories of exploration and evaluation assets and development and producing properties without significant adjustment arising from the retroactive adoption of IFRS. If the exposure draft becomes part of IFRS, Pengrowth intends to use the exemption provided therein.

Pengrowth is also monitoring the development of guidance on how to apply IFRS to oil and gas exploration and development activities. This guidance is being prepared by a committee of the Canadian Association of Petroleum Producers. Members of Pengrowth’s IFRS Steering Committee have been involved in the development of this guidance. Pengrowth will also be monitoring the IFRS adoption efforts of many of its peers and will participate in any related processes, as appropriate.

New Canadian accounting standards related to business combinations have been issued which will require changes to the way business combinations are accounted. The new standards broaden the scope of business combinations and require transaction costs to be expensed as incurred as well as require valuing all assets and liabilities and measuring consideration paid at the closing date. The new Canadian standards are required for all business combinations occurring on or after January 1, 2011 although early adoption is allowed. Pengrowth has not yet determined the impact on the financial position, results of operations or cash flows. Pengrowth has not determined if it will adopt this standard earlier than the required date.

New Canadian accounting recommendations related to goodwill and intangible assets have been issued which establish standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. These recommendations are effective for years beginning on or after October 1, 2008. Pengrowth does not expect these recommendations to have a material impact on the financial position, results of operations or cash flows.

DISCLOSURE CONTROLS AND PROCEDURES

As a Canadian reporting issuer with securities listed on both the TSX and the NYSE, Pengrowth is required to comply with Multilateral Instrument 52-109 — Certification of Disclosure in Issuers’ Annual and Interim Filings, as well as the Sarbanes Oxley Act (SOX) enacted in the United States. Both the Canadian and U.S. certification rules include similar requirements that require both the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) to assess and certify as to the effectiveness of the disclosure controls and procedures as defined in Canada by Multilateral Instrument 52-109 — Certification of Disclosure in Issuers’ Annual and Interim Filings and in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended.

The CEO, James S. Kinnear, and the CFO, Christopher G. Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the period ending December 31, 2008. This evaluation considered the functions performed by its Disclosure Committee, the review and oversight of all executive officers and the board, as well as the process and systems in place for filing regulatory and public information. Pengrowth’s established review process and disclosure controls are designed to provide reasonable assurance that all required information, reports and filings required under Canadian securities legislation and United States securities laws are properly submitted and recorded in accordance with those requirements.

Based on that evaluation, the CEO and CFO concluded that the design and operation of our disclosure controls and procedures were effective at the reasonable assurance level as at December 31, 2008, to ensure that information required to be disclosed by us in reports that we file under Canadian and U.S. securities laws is gathered, recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws and is accumulated and communicated to the management of Pengrowth Corporation, including the CEO and CFO, to allow timely decisions regarding required disclosure as required under Canadian and U.S. securities laws.

34 MD&A |PENGROWTH 2008

MANAGEMENT’S DISCUSSION AND ANALYSIS

It should be noted that while Pengrowth’s Chief Executive Officer and Chief Financial Officer believe that Pengrowth’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Pengrowth’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended and in Canada as defined in Multilateral Instrument 52-109 — Certification of Disclosure in Issuers’ Annual and Interim Filings. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with accounting principles generally accepted in Canada and reconciling to accounting principles generally accepted in the U.S. for note disclosure purposes. Our internal control over financial reporting includes those policies and procedures that: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of our assets are being made only in accordance with authorizations of our management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2008.

The effectiveness of internal control over financial reporting as of December 31, 2008 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included with our audited consolidated financial statements for the year ended December 31, 2008.

PENGROWTH 2008 | MD&A 35

APPENDIX C

CONSOLIDATED FINANCIAL STATEMENTS OF PENGROWTH ENERGY TRUST INCLUDING MANAGEMENT’S REPORT TO UNITHOLDERS, THE AUDITORS’ REPORTS AND NOTE 24 THEREOF WHICH INCLUDES A RECONCILIATION OF THE CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

MANAGEMENT’S REPORT TO UNITHOLDERS

MANAGEMENT’S RESPONSIBILITY TO UNITHOLDERS

The financial statements are the responsibility of the management of Pengrowth Energy Trust. They have been prepared in accordance with generally accepted accounting principles, using management’s best estimates and judgments, where appropriate.

Management is responsible for the reliability and integrity of the financial statements, the notes to the financial statements, and other financial information contained in this report. In the preparation of these statements, estimates are sometimes necessary because a precise determination of certain assets and liabilities is dependent on future events. Management believes such estimates have been based on careful judgments and have been properly reflected in the accompanying financial statements.

Management is also responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board is assisted in exercising its responsibilities through the Audit Committee of the Board, which is composed of four non-management directors. The Committee meets periodically with management and the auditors to satisfy itself that management’s responsibilities are properly discharged, to review the financial statements and to recommend approval of the financial statements to the Board.

KPMG LLP, the independent auditors appointed by the unitholders, have audited Pengrowth Energy Trust’s consolidated financial statements in accordance with generally accepted auditing standards and provided an independent professional opinion. The auditors have full and unrestricted access to the Audit Committee to discuss their audit and their related findings as to the integrity of the financial reporting process.

James S. Kinnear	Christopher G. Webster
Chairman, President and	Chief Financial Officer
Chief Executive Officer
March 2, 2009

36 MANAGEMENT’S REPORT TO UNITHOLDERS |PENGROWTH 2008

AUDITOR’S REPORT

TO THE UNITHOLDERS OF PENGROWTH ENERGY TRUST

We have audited the consolidated balance sheets of Pengrowth Energy Trust (“the Trust”) as at December 31, 2008 and 2007 and the consolidated statements of income and deficit, and cash flows for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2008 and 2007 and the results of its operations and its cash flows for each of the years then ended in accordance with Canadian generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2008 based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2009 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Chartered Accountants

Calgary, Canada

March 1, 2009

PENGROWTH 2008 | AUDITOR’S REPORT 37

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS OF PENGROWTH CORPORATION, AS ADMINISTRATOR OF PENGROWTH ENERGY TRUST AND THE UNITHOLDERS OF PENGROWTH ENERGY TRUST

We have audited Pengrowth Energy Trust (“the Trust”)’s internal control over financial reporting as of December 31, 2008 based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report to the Unitholders. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Trust Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008 based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have conducted our audits on the consolidated financial statements in accordance with Canadian generally accepted auditing standards and in accordance with the standards of the Public Trust Accounting Oversight Board (United States). Our report dated March 1, 2009, expressed an unqualified opinion on those consolidated financial statements.

Chartered Accountants

Calgary, Canada

March 1, 2009

38 CONSOLIDATED FINANCIAL STATEMENTS |PENGROWTH 2008

CONSOLIDATED BALANCE SHEETS

(stated in thousands of dollars)

As at December 31		2008			2007
	��
ASSETS
Current assets
Cash and term deposits		$	—		$	2,017
Accounts receivable			197,131			206,583
Due from Pengrowth Management Limited			623			731
Fair value of risk management contracts (Note 20)			122,841			8,034
Future income taxes (Note 11)			—			18,751
			320,595			236,116
Fair value of risk management contracts(Note 20)			41,851			6,024
Other assets(Note 5)			42,618			24,831
Property, plant and equipment(Note 6)			4,251,381			4,306,682
Goodwill			660,896			660,598
TOTAL ASSETS		$	5,317,341		$	5,234,251
LIABILITIES AND UNITHOLDERS’ EQUITY
Current liabilities
Bank indebtedness		$	2,631		$	—
Accounts payable and accrued liabilities			260,828			239,091
Distributions payable to unitholders			87,142			111,119
Fair value of risk management contracts (Note 20)			2,706			70,846
Future income taxes (Note 11)			34,964			—
Contract liabilities (Note 7)			2,483			4,663
			390,754			425,719
Fair value of risk management contracts(Note 20)			16,021			22,613
Contract liabilities(Note 7)			9,680			12,162
Convertible debentures(Note 8)			74,915			75,030
Long term debt(Note 9)			1,524,503			1,203,236
Asset retirement obligations(Note 10)			344,345			352,171
Future income taxes(Note 11)			293,318			387,100
Trust unitholders’ equity(Note 12)
Trust Unitholders’ capital			4,588,587			4,432,737
Equity portion of convertible debentures			160			160
Contributed surplus			16,579			9,679
Deficit (Note 14)			(1,941,521	)		(1,686,356	)
			2,663,805			2,756,220
Commitments(Note 21)
Contingencies(Note 22)
Subsequent events(Note 23)
TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY		$	5,317,341		$	5,234,251

See accompanying notes to the consolidated financial statements.

Approved on behalf of Pengrowth Energy Trust by Pengrowth Corporation, as Administrator.

Director	Director

PENGROWTH 2008 | CONSOLIDATED FINANCIAL STATEMENTS 39

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT

(stated in thousands of dollars)

Years ended December 31	2008			2007
REVENUES
Oil and gas sales	$	1,919,049		$	1,722,038
Unrealized gain (loss) on commodity risk management (Note 20)		249,899			(122,307	)
Processing and other income		15,525			20,573
Royalties, net of incentives		(433,970	)		(319,319	)
Net revenue		1,750,503			1,300,985
EXPENSES
Operating		418,497			406,522
Transportation		12,519			12,672
Amortization of injectants for miscible floods		25,876			34,063
Interest on bank indebtedness		—			13,876
Interest on long term debt		76,304			70,416
General and administrative		58,937			55,903
Management fee		6,950			6,807
Foreign exchange loss (gain) (Note 15)		189,172			(61,857	)
Depletion, depreciation and amortization		609,326			639,084
Accretion (Note 10)		28,051			25,722
Other expenses		946			2,737
		1,426,578			1,205,945
Income before taxes		323,925			95,040
Future income tax reduction (Note 11)		(71,925	)		(264,612	)
NET INCOME AND COMPREHENSIVE INCOME	$	395,850		$	359,652
Deficit, beginning of year		(1,686,356	)		(1,339,407	)
Distributions declared		(651,015	)		(706,601	)
DEFICIT, END OF YEAR	$	(1,941,521	)	$	(1,686,356	)
Net income per trust unit (Note 18)
Basic	$	1.58		$	1.47
Diluted	$	1.58		$	1.46

See accompanying notes to the consolidated financial statements.

40 CONSOLIDATED FINANCIAL STATEMENTS |PENGROWTH 2008

CONSOLIDATED STATEMENTS OF CASH FLOWS

(stated in thousands of dollars)

Years ended December 31	2008			2007
CASH PROVIDED BY (USED FOR):
OPERATING
Net income and comprehensive income	$	395,850			359,652
Depletion, depreciation and accretion		637,377			664,806
Future income tax reduction (Note 11)		(71,925	)		(264,612	)
Contract liability amortization (Note 7)		(4,664	)		(5,017	)
Amortization of injectants		25,876			34,063
Purchase of injectants		(21,009	)		(26,052	)
Expenditures on remediation		(32,691	)		(11,428	)
Unrealized foreign exchange loss (gain) (Note 15)		197,159			(65,873	)
Unrealized (gain) loss on commodity risk management (Note 20)		(249,899	)		122,307
Trust unit based compensation (Note 13)		9,998			5,351
Other items		(1,104	)		2,987
Changes in non-cash operating working capital (Note 16)		27,548			(15,840	)
		912,516			800,344
FINANCING
Distributions paid (Note 14)		(674,993	)		(717,562	)
Bank indebtedness		2,631			(9,374	)
Repayment of Accrete bank debt (Note 4)		(16,289	)		—
Change in long term debt, net		148,064			674,276
Proceeds from issue of trust units		63,499			48,141
		(477,088	)		(4,519	)
INVESTING
Business acquisition (Note 4)		(1,128	)		(923,121	)
Expenditures on property, plant and equipment		(401,928	)		(309,708	)
Other property acquisitions		(35,938	)		(9,012	)
Proceeds on property dispositions		17,361			458,804
Investment in private company		(5,000	)		—
Change in remediation trust funds		(9,013	)		(6,950	)
Change in non-cash investing working capital (Note 16)		(1,799	)		(3,821	)
		(437,445	)		(793,808	)
CHANGE IN CASH AND TERM DEPOSITS		(2,017	)		2,017
CASH AND TERM DEPOSITS AT BEGINNING OF YEAR		2,017			—
CASH AND TERM DEPOSITS AT END OF YEAR	$	—		$	2,017

See accompanying notes to the consolidated financial statements.

PENGROWTH 2008 | CONSOLIDATED FINANCIAL STATEMENTS 41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Tabular amounts are stated in thousands of dollars except per trust unit amounts.)

1. STRUCTURE OF THE TRUST

Pengrowth Energy Trust (the “Trust”) is an open-end investment trust created under the laws of the Province of Alberta pursuant to a Trust Indenture dated December 2, 1988 (as amended) between Pengrowth Corporation (“Corporation”) and Computershare Trust Company of Canada (“Computershare”). The beneficiaries of the Trust are the holders of trust units (the “unitholders”).

The purpose of the Trust is to directly and indirectly explore for, develop and hold interests in petroleum and natural gas properties, through investments in securities, royalty units, net profits interests and notes issued by subsidiaries of the Trust. The activities of the Corporation and its subsidiaries are financed by issuance of royalty units and interest bearing notes to the Trust and third party debt. The Trust owns all of the royalty units and 91 percent of the common shares of the Corporation. The Trust, through the royalty ownership, obtains substantially all the economic benefits of the Corporation. Under the terms of the Royalty Indenture, the Corporation is entitled to retain a one 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 2008 and 2007, this Residual Interest, as computed, did not result in any income retained by the Corporation. The Trust acquired notes receivable and a Net Profits Interest (the “NPI agreement” or “NPI”) in Esprit Exploration Ltd. (“Esprit”) as a result of the 2006 business combination with Esprit Energy Trust (“Esprit Trust”). The NPI agreement entitles the Trust to monthly distributions from Esprit, a wholly owned subsidiary of the Trust. The monthly distribution is equal to the amount by which 99 percent of the gross revenue exceeds 99 percent of certain deductible expenditures as defined in the NPI agreement.

The royalty units and notes of the Corporation held by the Trust entitle it to the net income generated by the Corporation and its subsidiaries’ petroleum and natural gas properties less amounts withheld in accordance with prudent business practices to provide for future operating costs and asset retirement obligations, as defined in the Royalty Indenture. In addition, unitholders are entitled to receive the net income from other investments that are held directly by the Trust. Pursuant to the Royalty Indenture, the Board of Directors of the Corporation can establish a reserve for certain items including up to 20 percent of gross revenue to fund future capital expenditures or for the payment of royalty income in any future period.

Pursuant to the Trust Indenture, trust unitholders are entitled to monthly distributions from interest income on the notes, royalty income under the Royalty Indenture and from other investments held directly by the Trust, less any reserves and certain expenses of the Trust including general and administrative costs as defined in the Trust Indenture.

The Board of Directors has general authority over the business and affairs of the Corporation and derives its authority in respect to the Trust by virtue of the delegation of powers by the trustee to the Corporation as Administrator in accordance with the Trust Indenture.

Pengrowth Management Limited (the “Manager”) has certain responsibilities for the business affairs of the Corporation and the administration of the Trust under the terms of a management agreement and defers to the Board of Directors on all matters material to the Corporation and the Trust. The management agreement expires on June 30, 2009. The Manager owns nine percent of the common shares of the Corporation, and the Manager is controlled by an officer and a director of the Corporation.

2. SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

The Trust’s consolidated financial statements have been prepared in accordance with Generally Accepted Accounting Principles (“GAAP”) in Canada. The consolidated financial statements include the accounts of the Trust, and all of its subsidiaries, collectively referred to as Pengrowth. All inter-entity transactions have been eliminated. These financial statements do not contain the accounts of the Manager.

The Trust owns 91 percent of the shares of Corporation and, through the royalty and notes, obtains substantially all the economic benefits of Corporation. In addition, the unitholders of the Trust have the right to elect the majority of the Board of Directors of the Corporation.

42 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JOINT INTEREST OPERATIONS

A significant proportion of Pengrowth’s petroleum and natural gas development and production activities are conducted with others and accordingly the accounts reflect only Pengrowth’s interest in such activities.

PROPERTY, PLANT AND EQUIPMENT

Pengrowth follows the full cost method of accounting for oil and gas properties and facilities whereby all costs of developing and acquiring oil and gas properties are capitalized. These costs include lease acquisition costs, geological and geophysical expenditures, costs of drilling and completion of wells, plant and production equipment costs and related overhead charges.

Pengrowth capitalizes a portion of general and administrative costs associated with exploration activities and development of all 100 percent owned projects. In addition, general and administrative costs are capitalized to the extent of Pengrowth’s working interest in capital expenditure projects to which overhead fees can be recovered from partners. In addition, transaction costs directly attributable to successful acquisitions are also capitalized.

As a result of growth in capital spending in unproven properties in 2008, Pengrowth began to exclude the cost of acquiring and evaluating certain unproved properties from the cost base subject to depletion. Capitalized costs, including future development costs and excluding the cost of unproven properties commencing in 2008, are depleted on a unit of production method based on proved reserves before royalties as estimated by independent engineers. The effect of the change in accounting policy on prior periods was not material. The fair value of future estimated asset retirement obligations associated with properties and facilities are capitalized and included in the depletion calculation. The associated asset retirement obligations on future development capital costs are also included in the cost base subject to depletion. Natural gas production and reserves are converted to equivalent units of crude oil using their relative energy content.

Repairs and maintenance costs are expensed as incurred.

Proceeds from disposals of oil and gas properties and equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and depreciation by more than 20 percent, in which case a gain or loss on disposal is recorded.

There is a limit on the carrying value of property, plant and equipment and other assets, which may be depleted against revenues of future periods (the “ceiling test”). Initially, the carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, and the lower of cost and market of unproved properties exceeds the carrying value. A separate recoverability test is completed on major development projects. If the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves including the lower of cost and market of unproved properties and the cost of major development projects. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. The carrying value of property, plant and equipment and other assets subject to the ceiling test includes asset retirement costs.

GOODWILL

Goodwill, which represents the excess of the total purchase price over the estimated fair value of the net identifiable assets and liabilities acquired, is not amortized but instead is assessed for impairment annually or as events occur that could suggest impairment exists. Impairment is assessed by determining the fair value of the reporting entity and comparing this fair value to the book value of the reporting entity. If the fair value of the reporting entity is less than the book value, impairment is measured by allocating the fair value of the reporting entity to the identifiable assets and liabilities of the reporting entity as if the reporting entity had been acquired in a business combination for a purchase price equal to its fair value. The excess of the fair value of the reporting entity over the assigned values of the identifiable assets and liabilities is the fair value of the goodwill. Any excess of the book value of goodwill over this implied fair value is the impairment amount. Impairment is charged to earnings in the period in which it occurs. Goodwill is stated at cost less impairment.

INJECTANT COSTS

Injectants (mostly natural gas and ethane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of hydrocarbon injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is currently estimated as 24 months.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ASSET RETIREMENT OBLIGATIONS

Pengrowth recognizes the fair value of an Asset Retirement Obligation (“ARO”) in the period in which it is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit of production method based on proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is expensed to income in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO.

Pengrowth has placed cash in segregated remediation trust accounts to fund certain ARO for the Judy Creek properties and the Sable Offshore Energy Project (“SOEP”).

INCOME TAXES

Pengrowth follows the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period the change occurs. Pengrowth’s policy for income tax uncertainties is that tax benefits will be recognized only when it is more likely than not the position will be sustained on examination.

TRUST UNIT COMPENSATION PLANS

Pengrowth has trust unit based compensation plans, which are described in Note 13. Compensation expense associated with trust unit based compensation plans is recognized in income over the vesting period of the plan with a corresponding increase in contributed surplus. Pengrowth estimates the forfeiture rate of trust unit rights and deferred entitlement trust units (“DEUs”) at the date of grant. Any consideration received upon the exercise of trust unit based compensation together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in trust unitholders’ capital. Compensation expense is based on the estimated fair value of the trust unit based compensation at the date of grant.

Pengrowth does not have any outstanding trust unit compensation plans that call for settlement in cash or other assets. Grants of such items, if any, will be recorded as liabilities, with changes in the liabilities charged to net income, based on the intrinsic value.

FINANCIAL INSTRUMENTS

Financial instruments are utilized by Pengrowth to manage its exposure to commodity price fluctuations, foreign currency and interest rate exposures. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

Financial instruments are classified into one of five categories: held for trading, held to maturity investments, loans and receivables, available for sale financial assets or other liabilities. Pengrowth has designated cash and term deposits as held for trading which are measured at fair value. Accounts receivable and due from the Manager are classified as loans and receivables which are measured at amortized cost. Investments held in the remediation trust funds have been designated as held to maturity and held for trading based on the type of investments in the fund. Other investments included in other assets have been designated as held for trading and available for sale based on the type of investment. The available for sale securities included in other assets are recorded at cost as the investment is in a private entity whose shares are not quoted in an active market. Held to maturity investments are measured at amortized cost, held for trading investments are measured at fair value, and available for sale investments are measured at fair value, except those whose shares are not quoted in an active market. Bank indebtedness, accounts payable and accrued liabilities, distributions payable, the debt portion of convertible debentures, and long term debt have been classified as other liabilities which are measured at amortized cost using the effective interest rate method.

All derivatives are classified as held for trading which are measured at fair value with changes in fair value over a reporting period recognized in net income. Changes in the fair value of derivatives used in certain hedging transactions for which cash flow hedge accounting is permitted would be recorded in other comprehensive income. Pengrowth does not have any risk management contracts outstanding for which hedge accounting is being applied.

44 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The receipts or payments arising from commodity contracts are recognized as a component of oil and gas sales. Unrealized gains and losses on commodity contracts are included in the unrealized gain (loss) on commodity risk management. The difference between the interest payments on the U.K. Pound Sterling denominated debt after the foreign exchange swaps and the interest expense recorded at the average foreign exchange rate is included in foreign exchange gains (losses). Unrealized gains (losses) on these swaps are included in foreign exchange gains (losses).

Comprehensive income includes net income and transactions and other events from non-owner sources such as unrealized gains and losses on effective cash flow hedges. There are no amounts that Pengrowth would include in other comprehensive income except for net income.

Transaction costs incurred in connection with the issuance of term debt instruments with a maturity of greater than one year are deducted against the carrying value of the debt and amortized to net income using the effective interest rate method over the expected life of the debt. Transaction costs incurred in connection with the issuance of other debt instruments are expensed as incurred.

FOREIGN CURRENCY

The U.S. dollar and U.K. Pound Sterling denominated debt are translated into Canadian dollars at the exchange rate in effect on the balance sheet date. Foreign exchange gains and losses on the U.S. dollar and U.K. Pound Sterling denominated debt are included in income.

EQUITY INVESTMENT

Pengrowth utilizes the equity method of accounting for investments subject to significant influence. Under this method, investments are initially recorded at cost and adjusted thereafter to include Pengrowth’s pro rata share of post-acquisition earnings. Any dividends received or receivable from the investee would reduce the carrying value of the investment.

MEASUREMENT UNCERTAINTY

The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended.

     The amounts recorded for depletion, depreciation, amortization of injectants, goodwill, future income taxes and ARO are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. The impairment assessment of goodwill is based on the estimated fair value of Pengrowth’s reporting units which is referenced to Pengrowth’s unit price and the premium an arm’s length party would pay to acquire all of the outstanding units. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.

NET INCOME PER TRUST UNIT

Basic net income per unit amounts are calculated using the weighted average number of units outstanding for the year. Diluted net income per unit amounts includes the dilutive effect of trust unit options, trust unit rights and DEUs using the treasury stock method. The treasury stock method assumes that any proceeds obtained on the exercise of in-the-money trust unit options and trust unit rights would be used to purchase trust units at the average price during the period. Diluted net income per unit amounts also include the dilutive effect of convertible debentures using the “if-converted” method which assumes that the convertible debentures were converted at the beginning of the period.

REVENUE RECOGNITION

Revenue from the sale of oil and natural gas is recognized when the product is delivered and collection is reasonably assured. Revenue from processing and other miscellaneous sources is recognized upon completion of the relevant service.

CASH AND TERM DEPOSITS

Cash and term deposits include demand deposits and term deposits with original maturities of less than 90 days.

COMPARATIVE FIGURES

Certain comparative figures have been reclassified to conform to the presentation adopted in the current year.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. CHANGE IN ACCOUNTING POLICIES

Effective January 1, 2008, Pengrowth adopted new Canadian accounting standards related to capital disclosures. The new standards require disclosure about Pengrowth’s objectives, policies and processes for managing capital. Refer to Note 19, Capital Disclosures.

Effective January 1, 2008, Pengrowth adopted new and revised Canadian accounting standards related to the disclosure and presentation of financial instruments. The new standards require additional disclosures regarding the nature and extent of the risks associated with financial instruments and how those risks are managed. The presentation standards for financial instruments under the new handbook section did not change significantly from the previous standards. Refer to Note 20, Financial Instruments.

On February 13, 2008, the Canadian Accounting Standards Board confirmed that publicly accountable enterprises will be required to adopt International Financial Reporting Standards (“IFRS”) in place of Canadian GAAP for interim and annual periods beginning on or after January 1, 2011. Pengrowth has completed the diagnostic phase, which involved a high level review of the major differences between Canadian GAAP and IFRS, and identification of potential information systems and process changes. Currently, Pengrowth has determined that the areas of accounting difference with the highest potential impact are accounting for exploration and development activities including classification of exploration and evaluation expenditures, depletion and impairment of capital assets, and business combination accounting. At this time, the impact on Pengrowth’s future financial position and results of operations is not reasonably determinable or estimable.

In September 2008, the International Accounting Standards Board issued an exposure draft to amend IFRS 1 in respect of property plant and equipment as at the date of initial transition to IFRS. That exposure draft, if adopted, would permit issuers currently using the full cost method of accounting to allocate the balance of property plant and equipment (as determined under Canadian GAAP) to the IFRS categories of exploration and evaluation assets and development and producing properties without significant adjustment arising from the retroactive adoption of IFRS. If the exposure draft becomes part of IFRS, Pengrowth intends to use the exemption provided therein.

New Canadian accounting standards related to business combinations have been issued which will require changes to the way business combinations are accounted. The new standards broaden the scope of business combinations and require transaction costs to be expensed as incurred as well as require valuing all assets and liabilities and measuring consideration paid at the closing date. The new Canadian standards are required for all business combinations occurring on or after January 1, 2011 although early adoption is allowed.

New Canadian accounting recommendations related to goodwill and intangible assets have been issued which establish standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. These recommendations are effective for years beginning on or after October 1, 2008. Pengrowth does not expect these recommendations to have a material impact on the financial position, results of operations or cash flows.

46 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. ACQUISITIONS

2008 ACQUISITIONS

On September 30, 2008, Pengrowth and Accrete Energy Inc. completed a business combination (the “Combination”) whereby each Accrete share was exchanged for 0.277 of a Pengrowth trust unit. As a result of the Combination, approximately 5.0 million Pengrowth trust units were issued to Accrete shareholders. The value assigned to each Pengrowth unit issued was approximately $17.95 per trust unit based on the weighted average market price of the trust units on the five days surrounding the announcement date of the Combination. In conjunction with the Combination, all of Accrete’s oil and gas properties except those in the Harmattan area were transferred to Argosy Energy Inc., an unrelated company. The Combination was accounted for as an acquisition of Accrete by Pengrowth using the purchase method of accounting with the allocation of the purchase price and consideration as follows:

Allocation of Purchase Price:
Property, plant and equipment	$	146,463
Bank debt		(16,289	)
Asset retirement obligations		(2,685	)
Working capital deficit		(5,548	)
Future income taxes		(31,858	)
	$	90,083
Consideration:
Pengrowth units	$	89,253
Acquisition costs		830
	$	90,083

The estimated fair value of property and equipment was determined using an independent reserve evaluation. The future income tax liability was determined based on Pengrowth’s effective income tax rate of approximately 28 percent. The asset retirement obligations were determined using Pengrowth’s estimated costs to remediate, reclaim and abandon the wells and facilities, the estimated timing of the costs to be incurred in future periods, an inflation rate of two percent, and a discount rate of eight percent.

The consolidated financial statements include the results of operations and cash flows from Accrete subsequent to the closing date of September 30, 2008. Final determination of the allocation of the purchase cost to the fair values of the assets and liabilities acquired is still pending.

2007 ACQUISITIONS

On January 22, 2007 Pengrowth acquired four subsidiaries of Burlington Resources Canada Ltd., a subsidiary of ConocoPhillips (the “CP properties”), which hold Canadian oil and natural gas properties and undeveloped land. The transaction was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration paid as follows:

Allocation of Purchase Price:
Property, plant and equipment	$	1,360,491
Goodwill		62,594
Asset retirement obligations		(90,772	)
Future income taxes		(305,144	)
	$	1,027,169
Consideration:
Cash	$	1,024,873
Acquisition costs		2,296
	$	1,027,169

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 47

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Property, plant and equipment represents the fair value of the assets acquired determined in part by an independent reserve evaluation. Goodwill, which is not deductible for tax purposes, was determined based on the excess of the total consideration paid less the value assigned to the identifiable assets and liabilities including the future tax liability.

The future income tax liability was determined based on the enacted income tax rate of approximately 29 percent. The asset retirement obligations were determined using Pengrowth’s estimated costs to remediate, reclaim and abandon the wells and facilities, the estimated timing of the costs to be incurred in future periods, an inflation rate of two percent, and a discount rate of eight percent.

Results of operations from the CP properties subsequent to the closing date of January 22, 2007 are included in the consolidated financial statements.

5. OTHER ASSETS

	2008		2007
Remediation trust funds (Note 10)	$	27,122	$	18,094
Equity investment in Monterey Exploration Ltd.		9,872		6,737
Investment in Result Energy Inc.		624		—
Investment in private corporation		5,000		—
	$	42,618	$	24,831

Effective February 2008, funds in the SOEP remediation trust fund were invested in an exchange traded bond fund. The SOEP remediation trust fund as at December 31, 2008 was $18.4 million (December 31, 2007 — $9.9 million). The investments in the fund have been designated as held for trading and are recorded at fair value each period end. The fair value of the investments in the fund is recognized as an unrealized gain or loss in the period and included in other expense on the consolidated statements of income and deficit. For the years ended December 31, 2008 and 2007, the amount of unrealized loss related to the SOEP remediation trust fund was insignificant. As at December 31, 2008, $8.7 million (December 31, 2007 — $8.2 million) in the Judy Creek remediation trust fund is classified as held to maturity and interest income is recognized as received.

Pengrowth recorded equity income of $1.4 million for the year ended December 31, 2008 (2007 — loss of $0.3 million) to reflect Pengrowth’s proportionate share of Monterey Exploration Ltd.’s (“Monterey”) net income. During the third quarter of 2008, Monterey issued shares in a public offering in which Pengrowth did not participate. The share offering was at a deemed issue price that was greater than the book value of Monterey’s net assets at the time of the share issue resulting in Pengrowth recording a $1.8 million pre-tax dilution gain in the third quarter. The dilution gain represents the increase in Pengrowth’s pro-rata share of the net assets of Monterey. As of December 31, 2008 and 2007, Pengrowth held approximately 8 million common shares of Monterey, which is approximately 24 percent (December 31, 2007 — 32 percent) of the outstanding common shares. The equity income and dilution gain are included in other expenses on the consolidated statements of income and deficit.

In the third quarter of 2008, Pengrowth obtained 4.2 million shares of Result Energy Inc. (“Result”) valued at $2.2 million in connection with a land acquisition. The investment in Result has been designated as a held for trading investment and is recorded at fair value at the end of each period. The change in the fair value of the investment has been recorded as an unrealized gain or loss in the period and included in other expenses in the consolidated statements of income and deficit.

In the fourth quarter of 2008, Pengrowth purchased 1.0 million shares of a private corporation valued at $5.0 million. The investment has been designated as available for sale and is recorded at cost as the shares are not quoted in an active market.

48 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. PROPERTY, PLANT AND EQUIPMENT

	2008			2007
Property, plant and equipment, at cost	$	7,136,374		$	6,577,484
Accumulated depletion, depreciation and amortization		(2,907,409	)		(2,298,083	)
Net book value of property, plant and equipment	$	4,228,965		$	4,279,401
Net book value of deferred injectant costs		22,416			27,281
Net book value of property, plant and equipment and deferred injectants	$	4,251,381		$	4,306,682

In 2008, approximately $5.8 million (2007 — $6.1 million) of general and administrative costs associated with exploration and unproven properties were capitalized. Approximately $45 million (2007 — nil) of costs to acquire and evaluate unproven properties has been excluded from depletion.

Pengrowth performed a ceiling test calculation at December 31, 2008 to assess the recoverable value of the property, plant and equipment. The oil and gas future prices and costs are based on the January 1, 2009 commodity price forecast of our independent reserve evaluators. These prices have been adjusted for commodity price differentials specific to Pengrowth. The following table summarizes the benchmark prices which are provided by an independent recognized valuation firm used in the ceiling test calculation. Based on these assumptions, the undiscounted value of future net revenues from Pengrowth’s proved reserves exceeded the carrying value of property, plant and equipment at December 31, 2008.

			Foreign		Edmonton		AECO
	WTI Oil		Exchange Rate		Light Crude Oil		Gas
Year	(U.S.$/bbl)		(U.S.$/Cdn$)		(Cdn$/bbl)		(Cdn$/mmbtu)
2009	$	57.50		0.825	$	68.61	$	7.58
2010	$	68.00		0.850	$	78.94	$	7.94
2011	$	74.00		0.875	$	83.54	$	8.34
2012	$	85.00		0.925	$	90.92	$	8.70
2013	$	92.01		0.950	$	95.91	$	8.95
2014	$	93.85		0.950	$	97.84	$	9.14
2015	$	95.73		0.950	$	99.82	$	9.34
2016	$	97.64		0.950	$	101.83	$	9.54
2017	$	99.59		0.950	$	103.89	$	9.75
2018	$	101.59		0.950	$	105.99	$	9.95
Thereafter	+ 2.0 percent/yr			0.950	+ 2.0 percent/yr		+ 2.0 percent/yr

7. CONTRACT LIABILITIES

Contract liabilities are composed of the following amounts:

	2008			2007
Fixed price commodity contract	$	956		$	4,110
Firm transportation contracts		11,207			12,715
		12,163			16,825
Less current portion		(2,483	)		(4,663	)
	$	9,680		$	12,162

Pengrowth assumed a natural gas fixed price sales contract and firm transportation commitments in conjunction with certain acquisitions. The fair values of these contracts were estimated on the date of acquisition and the amount recorded is reduced as the contracts settle.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 49

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. CONVERTIBLE DEBENTURES

The 6.5 percent convertible unsecured subordinated debentures (the “Debentures”) mature on December 31, 2010 with interest paid semi-annually in arrears on June 30 and December 31 of each year. Each $1,000 principal amount of Debentures is convertible at the option of the holder at any time into Pengrowth trust units at a conversion price of $25.54 per unit. 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.

The Debentures have been classified as debt, net of the fair value of the conversion feature which is included in equity at the date they were assumed in a business combination. The fair value of the conversion feature was calculated using an option pricing model. The debt premium is being amortized over the term of the Debentures. The amortization of the debt premium and the interest paid are recorded as interest. If the Debentures are converted into trust units, the portion of the value of the conversion feature within Trust Unitholders’ Equity will be reclassified to trust units along with the principal amount converted. As of December 31, 2008 and 2007, Debentures with a face value of $74.7 million remain outstanding.

	Debt			Equity		Total
Balance, December 31, 2007	$	75,030		$	160	$	75,190
Amortization of debt premium		(115	)		—		(115	)
Balance, December 31, 2008	$	74,915		$	160	$	75,075

9. LONG TERM DEBT

	2008		2007
U.S. dollar denominated senior unsecured notes:
150 million at 4.93 percent due April 2010	$	182,180	$	148,053
50 million at 5.47 percent due April 2013		60,727		49,351
400 million at 6.35 percent due July 2017		485,080		394,390
265 million at 6.98 percent due August 2018		321,231		—
	$	1,049,218	$	591,794
U.K. pound sterling denominated 50 million unsecured notes at 5.46 percent due December 2015		88,285		97,444
Canadian dollar 15 million senior unsecured notes at 6.61 percent due August 2018		15,000		—
Canadian dollar revolving credit facility borrowings		372,000		513,998
	$	1,524,503	$	1,203,236

Pengrowth has a committed $1.2 billion syndicated extendible revolving term credit facility. The facility is unsecured; covenant based and has a three year term maturing June 15, 2011. Pengrowth has the option to extend the facility each year, subject to the approval of the lenders, or repay the entire balance at the end of the three year term. The next renewal date is June 15, 2009. Various borrowing options are available under the facility including prime rate based advances and bankers’ acceptance loans. This facility carries floating interest rates that are expected to range between 0.60 percent and 1.15 percent over bankers’ acceptance rates depending on Pengrowth’s consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. In addition, Pengrowth has a $50 million demand operating line of credit. The facilities were reduced by drawings of $372 million and by outstanding letters of credit in the amount of approximately $12 million at December 31, 2008.

On April 23, 2003, Pengrowth closed a U.S. $200 million private placement of senior unsecured notes. The notes were offered in two tranches of U.S. $150 million at 4.93 percent due April 2010 and U.S. $50 million at 5.47 percent due in April 2013. The notes contain certain financial maintenance covenants and interest is paid semi-annually. Costs incurred in connection with issuing the notes, in the amount of $2.1 million, were deducted from the carrying amount of the debt and are being amortized to income using the effective interest method over the expected term of the notes.

50 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS |PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On December 1, 2005, Pengrowth closed a U.K. Pound Sterling 50 million private placement of senior unsecured notes. In a series of related risk management transactions, Pengrowth fixed the Pound Sterling to Canadian dollar exchange rate for all the semi-annual interest payments and the principal repayments at maturity. The notes have an effective rate of 5.49 percent after the risk management transactions. The notes contain the same financial maintenance covenants as the 2003 U.S. dollar denominated notes. Costs incurred in connection with issuing the notes, in the amount of $0.7 million, were deducted from the carrying amount of the debt and are being amortized to income using the effective interest method over the expected term of the notes.

On July 26, 2007, Pengrowth closed a U.S. $400 million private placement of senior unsecured notes. The notes bear interest at 6.35 percent and are due July 2017. The notes contain certain financial maintenance covenants and interest is paid semi-annually. Costs incurred in connection with issuing the notes, in the amount of $2.5 million, were deducted from the carrying amount of the debt and are being amortized to income using the effective interest method over the expected term of the notes.

On August 21, 2008, Pengrowth closed a U.S. $265 million private placement of senior unsecured notes. The notes bear interest at 6.98 percent and are due August 2018. The notes contain certain financial maintenance covenants and interest is paid semi-annually. Costs incurred in connection with issuing the notes, in the amount of $1.6 million, were deducted from the carrying amount of the debt and are being amortized to income using the effective interest method over the expected term of the notes.

On August 21, 2008, Pengrowth closed a Cdn $15 million private placement of senior unsecured notes. The notes bear interest at 6.61 percent and are due August 2018. The notes contain certain financial maintenance covenants and interest is paid semi-annually.

As of December 31, 2008, an unrealized cumulative foreign exchange loss of $66.9 million (December 31, 2007 — gain of $115.0. million) has been recognized on the U.S. dollar term notes since the date of issuance. As of December 31, 2008, an unrealized cumulative foreign exchange gain of $25.4 million (2007 — $16.1 million) has been recognized on the U.K. pound sterling denominated term notes since Pengrowth ceased to designate existing foreign exchange swaps as a hedge on January 1, 2007.

The five year schedule of long term debt repayment based on current maturity dates and assuming the revolving credit facility is not renewed is as follows: 2009 — nil, 2010 — $182.7 million, 2011 — $372.0, 2012 — nil, 2013 — $60.9 million.

10. ASSET RETIREMENT OBLIGATIONS

The ARO were estimated by management based on Pengrowth’s working interest in wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred, considering various factors including the annual reserves evaluation of Pengrowth’s properties from the independent reserve evaluators. Pengrowth has estimated the net present value of its ARO to be $344 million as at December 31, 2008 (2007 — $352 million), based on a total escalated future liability of $2,283 million (2007 — $2,015 million). These costs are expected to be made over 50 years with the majority of the costs incurred between 2040 and 2054. Pengrowth’s credit adjusted risk free rate of eight percent (2007 — eight percent) and an inflation rate of two percent (2007 — two percent) were used to calculate the net present value of the ARO.

The following reconciles Pengrowth’s ARO:

	2008			2007
Asset retirement obligations, beginning of period	$	352,171		$	255,331
Increase (decrease) in liabilities during the period related to:
Acquisitions		3,414			91,333
Dispositions		(5,663	)		(35,199	)
Additions		3,618			3,753
Revisions		(4,555	)		22,659
Accretion Expense		28,051			25,722
Liabilities settled in the period		(32,691	)		(11,428	)
	$	344,345		$	352,171

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 51

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Remediation trust funds

Pengrowth is required to make contributions to a remediation trust fund that is used to cover certain ARO of the Judy Creek properties. Pengrowth makes monthly contributions to the fund of $0.10 per boe of production from the Judy Creek properties and an annual lump sum contribution of $250,000.

Every five years Pengrowth must evaluate the assets in the trust fund and the outstanding ARO, and make recommendations to the former owner of the Judy Creek properties as to whether contribution levels should be changed. The next evaluation is anticipated to occur in 2012. Contributions to the Judy Creek remediation trust fund may change based on future evaluations of the fund.

Pengrowth is required to make contributions to a remediation trust fund that will be used to fund the ARO of the SOEP properties and facilities. Pengrowth currently makes a monthly contribution to the fund of $0.52 per mcf of natural gas production and $1.04 per bbl of natural gas liquids production from SOEP.

The following summarizes Pengrowth’s trust fund contributions for 2008 and 2007 and Pengrowth’s expenditures on ARO:

Remediation Trust Funds	2008			2007
Opening balance	$	18,094		$	11,144
Contributions to Judy Creek Remediation Trust Fund		831			917
Contributions to SOEP Environmental Restoration Fund		8,485			6,441
Remediation funded by Judy Creek Remediation Trust Fund		(288	)		(408	)
Change in remediation trust funds		9,028			6,950
Closing balance	$	27,122		$	18,094

Expenditures on ARO	2008		2007
Expenditures on ARO not covered by the trust funds	$	32,403	$	11,020
Expenditures on ARO covered by the trust funds		288		408
	$	32,691	$	11,428

11. INCOME TAXES

The Trust is a mutual fund trust as defined under the Income Tax Act (Canada). All taxable income earned by the Trust has been allocated to unitholders and such allocations are deducted for income tax purposes.

On June 22, 2007, the Canadian government implemented a new tax (the “SIFT tax”) on publicly traded income trusts and limited partnerships (Bill C-52 Budget Implementation Act). For existing income trusts and limited partnerships, the SIFT tax will be effective in 2011 unless certain rules related to “undue expansion” are not adhered to. As such, the Trust would not be subject to the new measures until the 2011 taxation year provided the Trust continues to meet certain requirements.

52 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2008			2007
Income before taxes	$	323,925		$	95,040
Combined federal and provincial tax rate		29.50	%		32.10	%
Expected income tax		95,558			30,508
Net income of the Trust		(200,998	)		(123,227	)
Impact of SIFT legislation		—			(71,048	)
Unrealized foreign exchange (gain) loss		24,783			(9,254	)
Book to tax differential on dispositions		—			(68,722	)
Change in enacted tax rates		(3,745	)		(59,230	)
Future tax rate difference		4,175			19,679
Other including stock based compensation		1,859			16,682
Valuation allowance		6,443			—
Future income tax reduction	$	(71,925	)	$	(264,612	)

The future income tax rate in 2008 is approximately 25 percent (2007 — 25 percent) and was applied to the temporary differences compared to the federal and provincial statutory rate of approximately 29 percent for the 2008 income tax year (2007 — 32 percent).

The net future income tax liability is composed of:

	2008			2007
Future income tax assets:
Asset retirement obligation	$	84,090		$	85,717
Non-capital losses		117,987			68,611
Unrealized commodity loss		—			22,066
Unrealized foreign exchange loss		6,443			—
Contract liabilities		3,292			3,106
		211,812			179,500
Less: Valuation allowance		(6,443	)		—
		205,369			179,500
Future income tax liabilities:
Property, plant, equipment and other assets		(491,170	)		(504,319	)
Unrealized commodity gain		(42,481	)		—
Unrealized foreign exchange gain		—			(15,601	)
Deferred partnership income		—			(27,929	)
Net future tax liability	$	(328,282	)	$	(368,349	)

In calculating its future income tax liability, Pengrowth has included $462.8 million (2007 - $269.9 million) related to non-capital losses available for carryforward to reduce taxable income in future years. These losses expire between 2014 and 2028.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 53

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. TRUST UNITS

Pengrowth is authorized to issue an unlimited number of trust units.

Total Trust Units:

	2008					2007
	Number of					Number of
Trust Units Issued	Trust Units		Amount			Trust Units		Amount
Balance, beginning of year		246,846,420	$	4,432,737			244,016,623	$	4,383,993
Issued on redemption of DEUs (non-cash)(1)		238,633		2,484			2,931		55
Issued for cash on exercise of trust unit options and rights		290,363		4,274			350,615		4,006
Issued for cash under Distribution Reinvestment Plan (DRIP)		3,727,256		59,423			2,461,299		44,880
Issued for the Accrete business combination		4,973,325		89,253			—		—
Issued on redemption of Royalty Units (non-cash)		—		—			14,952		—
Trust unit rights incentive plan (non-cash exercised)		—		614			—		548
Issue costs		—		(198	)		—		(745	)
Balance, end of year		256,075,997	$	4,588,587			246,846,420	$	4,432,737

(1) Includes 2005 DEU grants vested in 2008 with a performance multiplier of 120% and DEUs granted to retirees.

During the year ended December 31, 2008, no Class A trust units were converted to “consolidated” trust units (2007 — 9,630 Class A trust units were converted). As at December 31, 2008, 1,888 Class A trust units (2007 — 1,888) remain outstanding. All other trust units outstanding are “consolidated” trust units.

Redemption Rights

All 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 of the Corporation (the “Board of Directors”) for the ten days after the trust units are surrendered for redemption and (ii) the closing price of the trust units on such market on the date the trust units are surrendered for redemption. The redemption right permits Unitholders to redeem 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 distribution in specie of 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 are to be redeemed. The price of 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.

Distribution Reinvestment Plan

Unitholders are eligible to participate in the Distribution Reinvestment Plan (“DRIP”). DRIP entitles the unitholder to reinvest cash distributions in additional units of the Trust. The trust units under the plan are issued from treasury at a five percent discount to the weighted average closing price of trust units traded on the TSX for the 20 trading days preceding a distribution payment date.

“At The Market” Distribution

On December 14, 2007, Pengrowth entered into an equity distribution agreement (the “Equity 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 Equity Distribution Agreement (the “Equity Distribution Program”). Sales of Trust Units, if any, pursuant to the Equity

54 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Distribution Agreement will be made in transactions that are deemed to be “at-the-market distributions”, including sales made directly on the New York Stock Exchange or the Toronto Stock Exchange. 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 during the period of distribution. The net proceeds of any given distribution of Trust Units will be used for development capital and general business purposes. The volume and timing of sales, if any, will be at Pengrowth’s discretion. The shelf prospectus enabling the at-the-market distribution expired in the fourth quarter of 2008. Although the Equity Distribution Agreement is still in effect, no units can be issued until a new shelf prospectus is filed. No Trust Units were issued under the Equity Distribution Program during the year ended December 31, 2008.

Contributed Surplus

	2008			2007
Balance, beginning of year	$	9,679		$	4,931
Trust unit rights incentive plan (non-cash expensed)		2,348			1,903
Deferred entitlement trust units (non-cash expensed)		7,650			3,448
Trust unit rights incentive plan (non-cash exercised)		(614	)		(548	)
Deferred entitlement trust units (non-cash exercised)		(2,484	)		(55	)
Balance, end of year	$	16,579		$	9,679

13. TRUST UNIT BASED COMPENSATION PLANS

Up to ten percent of the issued and outstanding trust units, to a maximum of 24 million trust units, may be reserved for DEUs, rights and option grants, in aggregate, subject to a maximum of 5.5 million DEUs available for issuance pursuant to the long term incentive program.

Long Term Incentive Program

The DEUs issued under the plan vest and are converted to trust units in the third year from the date of grant and will receive deemed distributions prior to the vesting date in the form of additional DEUs. However, the number of DEUs actually issued to each participant at the end of the three year vesting period will be subject to an absolute performance test and a relative performance test which compares Pengrowth’s three year average total return to the three year average total return of a peer group of other energy trusts such that upon vesting, the number of trust units issued from treasury may range from zero to one and one-half times the number of DEUs granted plus accrued DEUs through the deemed reinvestment of distributions.

Compensation expense related to DEUs is based on the fair value of the DEUs at the date of grant. The fair value of DEUs is determined using the closing trust unit price on the date of grant. The amount of compensation expense is reduced by the estimated forfeitures at the date of grant, which has been estimated at 25 percent for officers and employees. The number of trust units awarded at the end of the vesting period is subject to certain performance conditions and fluctuations in compensation expense may occur due to changes in estimating the outcome of the performance conditions. A performance multiplier of 100 percent was used for 2008 and 2007 grants and 150 percent for 2006 grants based on Pengrowth’s total return compared to its peer group at year end. Compensation expense is recognized in income over the vesting period with a corresponding increase or decrease to contributed surplus. Upon the issuance of trust units at the end of the vesting period, trust unitholders’ capital is increased and contributed surplus is decreased by the amount of compensation expense related to the DEUs. The trust units are issued from treasury upon vesting.

Pengrowth recorded compensation expense of $7.6 million in 2008 (2007 — $3.4 million) related to the DEUs based on the weighted average grant date fair value of $19.49 per DEU (2007 — $20.07 per DEU). As at December 31, 2008, the amount of compensation expense to be recognized over the remaining vesting period was $8.7 million (December 31, 2007 — $6.6 million) or $8.72 per DEU (2007 - - $10.71 per DEU). The unrecognized compensation cost will be expensed to net income over the remaining weighted average vesting period of 1.3 years (2007 — 1.5 years).

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 55

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2008					2007
	Number			Weighted		Number			Weighted
DEU	of DEUs			average price		of DEUs			average price
Outstanding, beginning of year		868,042		$	20.13		399,568		$	20.55
Granted		578,833		$	17.88		451,615		$	19.73
Forfeited		(158,532	)	$	19.54		(92,672	)	$	20.15
Exercised		(202,020	)	$	18.51		(2,931	)	$	20.06
Deemed DRIP		184,427		$	19.70		112,462		$	20.27
Outstanding, end of year		1,270,750		$	19.38		868,042		$	20.13

Trust Unit Rights Incentive Plan

Pengrowth has a Trust Unit Rights Incentive Plan, pursuant to which rights to acquire trust units may be granted to the directors, officers, employees, and special consultants of the Corporation and the Manager. Pengrowth has not granted Trust Unit Rights to directors since 2006. Under the Rights Incentive Plan, distributions per trust unit to unitholders in a calendar quarter which represent a return of more than 2.5 percent of the net book value of property, plant and equipment at the beginning of such calendar quarter may result, at the discretion of the holder, in a reduction in the exercise price. Total price reductions calculated for 2008 were $1.01 per trust unit right (2007 — $1.14 per trust unit right). One third of the rights granted under the Rights Incentive Plan vest on the grant date, one third on the first anniversary date of the grant and the remaining on the second anniversary. The rights have an expiry date of five years from the date of grant.

As at December 31, 2008, rights to purchase 3,292,622 trust units were outstanding (2007 — 2,250,056) that expire at various dates to November 19, 2013.

	2008					2007
	Number			Weighted		Number			Weighted
Trust Unit Rights	of rights			average price		of rights			average price
Outstanding, beginning of year		2,250,056		$	17.39		1,534,241		$	16.06
Granted(1)		1,703,892		$	17.96		1,259,562		$	19.75
Forfeited		(397,469	)	$	17.49		(199,822	)	$	14.63
Exercised		(263,857	)	$	14.55		(343,925	)	$	11.35
Outstanding, end of year		3,292,622		$	16.78		2,250,056		$	17.39
Exercisable, end of year		1,950,375		$	16.52		1,317,296		$	16.30

⁽¹⁾ Weighted average exercise price of rights granted are based on the exercise price at the date of grant.

The following table summarizes information about trust unit rights outstanding and exercisable at December 31, 2008:

	Rights Outstanding						Rights Exercisable
			Weighted average		Weighted				Weighted
			remaining		average				average
	Number		contractual		exercise		Number		exercise
Range of exercise prices	outstanding		life (years)		price		exercisable		price
$10.00 to $13.99		544,386		0.3	$	12.13		447,656	$	11.96
$14.00 to $17.99		2,351,560		2.7	$	17.40		1,128,871	$	17.35
$18.00 to $22.15		396,676		0.3	$	19.45		373,848	$	19.46
$10.00 to $22.15		3,292,622		3.2	$	16.78		1,950,375	$	16.52

Compensation expense associated with the trust unit rights granted during 2008 was based on the estimated fair value of $1.68 per trust unit right (2007 — $2.04). The fair value of trust unit rights granted in 2008 was estimated at nine percent of the exercise price at the date of grant using a binomial lattice option pricing model with the following assumptions: risk-free rate of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3.9 percent, volatility of 23 percent, expected distribution yield of 14 percent per trust unit and reductions in the exercise price over the life of the trust unit rights. The amount of compensation expense is reduced by the estimated forfeitures at the date of grant which has been estimated at five percent for directors and officers and ten percent for employees.

Compensation expense related to the trust unit rights in 2008 was $2.3 million (2007 — $1.9 million). As at December 31, 2008, the amount of compensation expense to be recognized over the remaining vesting period was $1.2 million (December 31, 2007 — $1.0 million) or $0.37 per trust unit right (2007 — $0.31 per trust unit right). The unrecognized compensation cost will be expensed to net income over the weighted average remaining vesting period of 1.1 year (2007 — 0.9 year). The trust units are issued from treasury upon vesting and exercise.

Trust Unit Option Plan

Pengrowth has a trust unit option plan under which directors, officers, employees and special consultants of the Corporation and the Manager are eligible to receive options to purchase trust units. No new grants have been issued under the plan since November 2002. The options expire seven years from the date of grant. All trust unit options are fully vested and expensed.

As at December 31, 2008, options to purchase 1,700 trust units were outstanding (2007 — 66,318) that expire at various dates to June 28, 2009.

	2008					2007
	Number			Weighted		Number			Weighted
Trust Unit Options	of options			average price		of options			average price
Outstanding, beginning of year		66,318		$	15.25		98,619		$	16.12
Exercised		(26,506	)	$	16.43		(6,690	)	$	15.25
Expired		(33,042	)	$	13.97		(25,611	)	$	18.61
Cancelled		(5,070	)	$	17.48		—		$	—
Outstanding, end of year		1,700		$	14.95		66,318		$	15.25

Employee Savings Plans

Pengrowth has savings plans whereby Pengrowth will match contributions by qualifying employees of one to 12 percent of their annual base salary, less any of Pengrowth’s contributions to the Group Registered Retirement Savings Plan (Group RRSP), to purchase trust units in the open market. Participants in the Group RRSP can make contributions from one to 12 percent and Pengrowth will match contributions to a maximum of six percent of their annual basic salary. Pengrowth’s share of contributions to the Trust Unit Purchase Plan and Group RRSP were $4.2 million in 2008 (2007 — $3.5 million) and $1.0 million in 2008 (2007 — $0.9 million), respectively.

Trust Unit Margin Purchase Plan

Pengrowth has a plan whereby the employees and certain consultants of Pengrowth and the Manager can purchase trust units and finance up to 75 percent of the purchase price through an investment dealer, subject to certain participation limits and restrictions. Participants maintain personal margin accounts with the investment dealer and are responsible for all interest costs and obligations with respect to their margin loans.

Pengrowth has provided a $1 million letter of credit to the investment dealer to guarantee amounts owing with respect to the plan. The amount of the letter of credit may fluctuate depending on the amounts financed pursuant to the plan. At December 31, 2008, 432,789 trust units (2007 — 432,988) were deposited under the plan with a market value of $4.0 million (2007 — $7.6 million) and a corresponding margin loan of $4.3 million (2007 — $4.4 million).

The investment dealer has limited the total margin loan available under the plan to the lesser of $15 million or 35 percent of the market value of the units held under the plan. Pengrowth may be required to make payments or post additional letters of credit to the investment dealer as the margin loan currently exceeds the limit. Any payments made by Pengrowth would be reduced by proceeds of liquidating the individual’s trust units held under the plan. The maximum amount Pengrowth may be required to pay at December 31, 2008 was $4.3 million (2007 — $4.4 million) however, the individual plan members are solely responsible for any margin loans and Pengrowth would only be responsible for any unpaid amounts.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 57

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. DEFICIT

	2008			2007
Accumulated earnings	$	2,071,188		$	1,675,338
Accumulated distributions declared		(4,012,709	)		(3,361,694	)
	$	(1,941,521	)	$	(1,686,356	)

Pengrowth is obligated by virtue of its Royalty and Trust Indentures and NPI agreement to distribute to unitholders a significant portion of its cash flow from operations. Cash flow from operations typically exceeds net income as a result of non-cash expenses such as unrecognized gains (losses) on commodity contracts, depletion, depreciation and accretion. These non-cash expenses result in a deficit being recorded despite Pengrowth distributing less than its cash flow from operations.

Distributions paid

Actual cash distributions paid in 2008 were $675.0 million (2007 — $717.6 million). Distributions declared have been determined in accordance with the Trust Indenture. Distributions are declared payable in the following month after the distributions were earned. The amount of cash not distributed to unitholders is at the discretion of the Board of Directors.

15. FOREIGN EXCHANGE LOSS (GAIN)

	2008			2007
Unrealized foreign exchange loss (gain) on translation of U.S. dollar denominated debt	$	181,856		$	(57,820	)
Unrealized foreign exchange gain on translation of U.K. pound denominated debt		(9,230	)		(16,120	)
	$	172,626		$	(73,940	)
Unrealized loss on foreign exchange risk management contracts		24,533			8,067
	$	197,159		$	(65,873	)
Realized foreign exchange (gain) loss		(7,987	)		4,016
	$	189,172		$	(61,857	)

16. OTHER CASH FLOW DISCLOSURES

CHANGE IN NON-CASH OPERATING WORKING CAPITAL

Cash provided by (used for):	2008			2007
Accounts receivable	$	9,452		$	(34,707	)
Accounts payable and accrued liabilities		23,536			21,699
Due from Pengrowth Management Limited		108			(2,832	)
Net working capital on acquisition		(5,548	)		—
	$	27,548		$	(15,840	)

CHANGE IN NON-CASH INVESTING WORKING CAPITAL

Cash provided by (used for):	2008			2007
Accounts payable and capital accruals	$	(1,799	)	$	(3,821	)

CASH INTEREST PAYMENTS

	2008		2007
Interest on long term debt	$	66,267	$	58,192
Interest on bank indebtedness		—		13,876
	$	66,267	$	72,068

In 2008 interest of nil (2007 — $13.9 million) on bank indebtedness was incurred on a $600 million credit facility that Pengrowth fully repaid on July 13, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

17. RELATED PARTY TRANSACTIONS

The Manager provides certain services pursuant to a management agreement in 2008 Pengrowth was charged nil (2007 — $0.1 million) for performance fees and $6.9 million (2007 — $6.7 million) for management fees. In addition, Pengrowth was charged $1.1 million (2007 — $1.0 million) for reimbursement of general and administrative expenses incurred by the Manager. Amounts charged by the Manager are pursuant to a management agreement approved by the unitholders. The law firm controlled by the Vice President and Corporate Secretary of the Corporation charged $1.0 million (2007 — $1.1 million) for legal and advisory services provided to Pengrowth. The fees charged by the law firm controlled by the Vice President and Corporate Secretary of the Corporation have been recorded at the exchange amount which management believes approximate the fair value. Amounts receivable or payable from or to the related parties are unsecured, non-interest bearing and have no set terms of repayment. During 2008, the Vice President and Corporate Secretary was granted 23,670 trust unit rights and 3,945 DEUs (2007 — 20,901 trust unit rights and 3,484 DEUs).

A senior officer of the Corporation is a member of the Board of Directors of Monterey, a company that Pengrowth owns approximately 24 percent of the outstanding common shares. As at December 2008, two senior officers of the Corporation directly and indirectly owned a total of 259,200 shares (2007 -230,000 shares) of Monterey. All shares have been purchased either through a new share offering marketed by an independent broker or on the open market.

18. AMOUNTS PER TRUST UNIT

The following reconciles the weighted average number of trust units used in the basic and diluted net income per unit calculations:

	2008			2007
Weighted average number of trust units — basic		250,182			245,470
Dilutive effect of trust unit options, trust unit rights and DEUs		334	��		740
Weighted average number of trust units — diluted		250,516			246,210

In 2008, 6.2 million (2007 — 3.7 million) trust units from trust unit options, rights and the convertible debentures were excluded from the diluted net income per unit calculation as their effect is anti-dilutive.

19. CAPITAL DISCLOSURES

Pengrowth defines its capital as trust unitholders’ equity, long term debt, bank indebtedness, convertible debentures and working capital.

Pengrowth’s goal over longer periods of time is to maximize returns to the unitholders through cash distributions on a per Trust Unit basis and enhancing the value of the Trust Units. Pengrowth’s aim is to maintain sufficient financial flexibility in its capital structure to allow it to finance its capital expenditures to replace produced reserves through operating cash flows and within the company’s debt capacity while maintaining distributions at a level that provides a reasonable return to unitholders. Pengrowth seeks to retain sufficient flexibility with its capital to take advantage of acquisition opportunities that may arise.

Pengrowth must comply with certain financial debt covenants. Compliance with these financial covenants is closely monitored by management as part of Pengrowth’s overall capital management objectives. The covenants are based on specific definitions prescribed in the debt agreements and are different between the credit facility and the term notes. Throughout 2008, Pengrowth was in compliance with all financial covenants.

Pengrowth’s ability to issue trust units and convertible debt is subject to external restrictions as a result of the Specified Investment Flow-Through Entities Legislation (the SIFT tax). Pengrowth is grandfathered for the SIFT tax, however Pengrowth may lose the benefit of the grandfathering period, which ends December 31, 2010, if Pengrowth exceeds the limits on the issuance of new trust units and convertible debt that constitute normal growth during the grandfathering period (subject to certain exceptions). The normal growth limits are calculated as a percentage of Pengrowth’s market capitalization of approximately $4.8 billion on October 31, 2006. The normal growth guidelines have been revised to accelerate the safe harbour amount for each of 2009 and 2010. As of December 31, 2008 Pengrowth may issue an additional $4.22 billion of equity in total for 2009 and 2010 under the safe harbour provisions. The normal growth restriction on trust unit issuance is monitored by management as part of the overall capital management objectives. Pengrowth is in compliance with the normal growth restrictions.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 59

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Management monitors capital using non-GAAP financial metrics, primarily total debt to the trailing twelve months earnings before interest, taxes, depletion, depreciation, amortization, accretion, and other non-cash items (EBITDA) and Total Debt to Total Capitalization. Pengrowth seeks to manage the ratio of total debt to trailing EBITDA and Total Debt to Total Capitalization ratio with the objective of being able to finance its growth strategy while maintaining sufficient flexibility under the debt covenants.

In order to maintain its financial condition or adjust its capital structure, Pengrowth may issue new debt, refinance existing debt, issue additional equity, adjust the level of distributions paid to unitholders, adjust the level of capital spending or dispose of non-core assets to reduce debt levels. However, there may be instances where it would be acceptable for total debt to trailing EBITDA to temporarily fall outside of the normal targets set by management such as in financing an acquisition to take advantage of growth opportunities. This would be a strategic decision made by management and approved by the Board of Directors with steps taken in the subsequent period to restore Pengrowth’s capital structure based on its capital management objectives.

Pengrowth’s objectives, policies and processes for managing capital have remained substantially consistent from the prior year. Management believes that current total debt to trailing EBITDA is within reasonable limits.

The following is a summary of Pengrowth’s capital structure, excluding unitholders’ equity:

($ thousands)	December 31,		December 31,
As at:	2008		2007
Term credit facilities	$	372,000	$	513,998
Senior unsecured notes		1,152,503		689,238
Working capital deficit		70,159		189,603
Convertible debentures		74,915		75,030
Total debt including convertible debentures	$	1,669,577	$	1,467,869

20. FINANCIAL INSTRUMENTS

Pengrowth’s financial instruments are composed of cash and term deposits, accounts receivable, accounts payable and accrued liabilities, fair value of risk management assets and liabilities, remediation trust funds, investments in other entities, due from the manager, distributions payable to unitholders, bank indebtedness, long term debt and convertible debentures.

Details of Pengrowth’s significant accounting policies for recognition and measurement of financial instruments are disclosed in Note 2.

RISK MANAGEMENT OVERVIEW

Pengrowth has exposure to certain market risks related to volatility in commodity prices, interest rates and foreign exchange rates. Derivative instruments are used to manage exposure to these risks. Pengrowth’s policy is not to utilize financial instruments for trading or speculative purposes.

The Board of Directors and management have overall responsibility for the establishment of risk management strategies and objectives. Pengrowth’s risk management policies are established to identify the risks faced by Pengrowth, to set appropriate risk limits, and to monitor adherence to risk limits. Risk management policies are reviewed regularly to reflect changes in market conditions and Pengrowth’s activities.

MARKET RISK

Market risk is the risk that the fair value or future cash flows of financial assets and liabilities will fluctuate due to movements in market prices. Market risk is composed of commodity price risk, foreign currency risk, interest rate risk and equity price risk.

Commodity Price Risk

Pengrowth is exposed to commodity price risk as prices for oil and gas products fluctuate in response to many factors including local and global supply and demand, weather patterns, pipeline transportation and political stability and economic factors. Commodity price fluctuations are an inherent part of the oil and gas business. While Pengrowth does not consider it prudent to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

entirely eliminate this risk, it does mitigate some of the exposure to commodity price risk to protect the return on acquisitions and provide a level of stability to distributions. Pengrowth utilizes financial contracts to fix the commodity price associated with a portion of its future production. The use of forward and futures contracts are governed by formal policies and is subject to limits established by the board of directors. The board of directors and management may re-evaluate these limits as needed in response to specific events such as market activity, additional leverage, acquisitions or other transactions where Pengrowth’s capital structure may be subject to more risk from commodity prices.

As at December 31, 2008, Pengrowth had fixed the price applicable to future production as follows:

Crude Oil:

Remaining term	Volume (bbl/d)		Reference Point		Price per bbl
Financial:
Jan 1, 2009 — Dec 31, 2009		13,000	WTI	(1)	$86.34 Cdn
Jan 1, 2010 — Dec 31, 2010		6,500	WTI	(1)	$93.19 Cdn
Jan 1, 2011 — Nov 30, 2011		500	WTI	(1)	$82.30 Cdn

⁽¹⁾ Associated Cdn $/U.S.$ foreign exchange rate has been fixed

Natural Gas:

	Volume		Reference		Price per
Remaining term	(mmbtu/d)		Point		mmbtu
Financial:
Jan 1, 2009 — Dec 31, 2009		10,000	NYMEX	(1)	$8.50 Cdn
Jan 1, 2009 — Dec 31, 2009		49,760	AECO		$7.76 Cdn
Jan 1, 2009 — Dec 31, 2009		15,000	Chicago MI	(1)	$8.45 Cdn
Jan 1, 2010 — Dec 31, 2010		16,587	AECO		$8.64 Cdn

⁽¹⁾ Associated Cdn $/U.S. $ foreign exchange rate has been fixed

Pengrowth has designated the above commodity risk management contracts as held for trading and recorded the contracts on the balance sheet at fair value.

The fair value of the commodity risk management contracts are allocated to current and non-current assets and liabilities on a contract by contract basis. The change in the fair value of the commodity risk management contracts during the period is recognized as an unrealized gain or loss on the income statement as follows:

Commodity Risk Management Contracts	2008		2007
Current portion of unrealized risk management assets	$	122,841	$	8,034
Non-current portion of unrealized risk management assets		41,851		66
Current portion of unrealized risk management (liabilities)		—		(70,694	)
Non-current portion of unrealized risk management (liabilities)		—		(22,613	)
Total unrealized risk management (liabilities) assets at year end	$	164,692	$	(85,207	)

	2008			2007
Total unrealized risk management (liabilities) assets at year end	$	164,692		$	(85,207	)
Less: Unrealized risk management (liabilities) assets at beginning of year		(85,207	)		37,100
Unrealized (loss) gain on risk management contracts for the year	$	249,899		$	(122,307	)

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 61

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Natural Gas Fixed Price Sales Contract

Pengrowth assumed a natural gas fixed price physical sales contract in conjunction with an acquisition. At December 31, 2008, the amount Pengrowth would pay to terminate the fixed price sales contract would be $1.8 million. Details of the physical fixed price sales contract are provided below:

Remaining Term	Volume (mmbtu/d)		Price per mmbtu
Jan 1, 2009 — Apr 30, 2009		3,886	$2.40 Cdn

Commodity Price Sensitivity

Each Cdn $1 per barrel change in future oil prices would result in approximately Cdn $7.3 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts. Similarly, each Cdn $0.50 per mcf change in future natural gas prices would result in approximately Cdn $16.7 million pre-tax change in the unrealized gain (loss) on commodity risk management contracts.

As of close December 31, 2008, the AECO spot price gas price was $6.0164/GJ and the WTI prompt month price was US$44.60 per barrel.

Foreign Exchange Risk

Pengrowth is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices. Pengrowth has mitigated some of this exchange risk by entering into fixed Canadian dollar crude oil and natural gas price swaps as outlined in the commodity price risk section above.

Pengrowth is exposed to foreign currency fluctuation on the U.S. dollar denominated notes for both interest and principal payments. Pengrowth has not entered into any contracts to mitigate the foreign exchange risk associated with the U.S. dollar denominated term notes as the U.S. dollar denominated interest payments partially offset U.S. dollar denominated revenues.

Pengrowth entered into foreign exchange risk management contracts in conjunction with issuing U.K. Pounds Sterling 50 million ten year term notes which fixed the Canadian dollar to U.K. Pound Sterling exchange rate on the interest and principal of the U.K. Pound Sterling denominated debt at approximately 0.4976 U.K. Pounds Sterling per Canadian dollar. The estimated fair value of the foreign exchange risk management contracts have been determined based on the amount Pengrowth would receive or pay to terminate the contracts at period end. As at December 31, 2008, the amount Pengrowth would pay to terminate the foreign exchange risk management contracts would be approximately $18.7 million.

Pengrowth has designated the foreign exchange risk management contracts as held for trading and are recorded on the balance sheet at fair value. The fair value of the foreign exchange risk management contracts are allocated to current and non-current assets and liabilities on a contract by contract basis. The change in the fair value of the foreign exchange risk management contracts during the period is recognized as an unrealized gain or loss on the income statement as follows:

Foreign Exchange Risk Management Contracts	2008			2007
Current portion of unrealized risk management liabilities		(2,706	)		(152	)
Non-current portion of unrealized risk management (liabilities) assets		(16,021	)		5,958
Total unrealized risk management (liabilities) assets at year end	$	(18,727	)	$	5,806
		2008			2007
Total unrealized risk management (liabilities) assets at year end	$	(18,727	)	$	5,806
Less: Unrealized risk management assets at beginning of year		5,806			13,873
Unrealized loss on risk management contracts for the year	$	(24,533	)	$	(8,067	)

62 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Foreign Exchange Rate Sensitivity

The following summarizes the sensitivity on pre-tax income of a change in the foreign exchange rate on unrealized foreign exchange gains (losses) related to the translation of the foreign denominated term debt and on unrealized gains (losses) related to the change in the fair value of the foreign exchange risk management contracts, holding all other variables constant:

	Cdn $0.01 Exchange Rate Change
Foreign Exchange Sensitivity	Cdn - U.S.		Cdn - U.K.
Unrealized foreign exchange gain or loss	$	8,650	$	500	��
Unrealized foreign exchange risk management gain or loss		—		577

Interest Rate Risk

Pengrowth is exposed to interest rate risk on the Canadian dollar revolving credit facility as the interest is based on floating interest rates. Pengrowth has mitigated some of its exposure to interest rate risk by issuing fixed rate term notes.

Interest Rate Sensitivity

As at December 31, 2008, Pengrowth has approximately $1.5 billion of long term debt of which $372 million is based on floating interest rates. A one percent increase in interest rates would increase pre-tax interest expense by approximately $3.7 million for the year ended December 31, 2008.

Equity Price Risk

Pengrowth has exposure to equity price risk on investments in an exchange traded bond fund related to a portion of the remediation trust fund and on its investment in Result, a publicly traded entity. Pengrowth’s exposure to equity price risk is not significant.

FAIR VALUE

The fair value of cash and term deposits, accounts receivable, accounts payable and accrued liabilities, due from manager, bank indebtedness, and distributions payable approximate their carrying amount due to the short-term nature of those instruments.

Risk management assets and liabilities are recorded at their estimated fair value based on the mark-to-market method of accounting, using publicly quoted market prices or, in their absence, third-party market indications and forecasts priced on the last trading day of the applicable period. Investments in the SOEP remediation trust fund and Result have been designated as held for trading and are recorded at fair value which is based on the market value of the underlying investments at the balance sheet date. The Judy Creek remediation trust fund is classified as held to maturity. Fair value approximates the carrying value of the underlying investments plus the related accrued interest.

The fair value of the fixed rate term notes is determined based on the trading price of risk free government debt instruments of similar maturities, adjusted for credit risk premium. The fair value of the convertible debentures has been determined using the closing trading price of the debentures on the balance sheet date. The fair value of the Canadian dollar revolving credit facility is equal to its carrying amount as the facility bears interest at floating rates.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 63

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of financial instruments that differ from their carrying value are as follows:

	2008				2007
As at December 31, 2008	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial Assets
Remediation Trust Funds	$	27,122	$	26,948	$	18,094	$	18,107
Financial Liabilities
U.S. dollar denominated senior unsecured notes	$	1,049,218	$	1,213,723	$	591,794	$	627,674
Cdn dollar senior unsecured notes	$	15,000	$	16,075		—		—
U.K. Pound Sterling denominated unsecured notes	$	88,285	$	95,495	$	97,444	$	96,181
Convertible debentures	$	74,915	$	68,014	$	75,030	$	74,741

CREDIT RISK

Credit risk is the risk of financial loss to Pengrowth if counterparty to a financial instrument fails to meet its contractual obligations. A significant portion of Pengrowth’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. Continued uncertainty in the credit markets may restrict the ability of Pengrowth’s normal business counterparties to meet their obligations to Pengrowth. Additional credit risk could exist where little or none previously existed. However, given the current state of global credit markets, oil and gas companies including Pengrowth may be exposed to an increased risk of a general decline in counterparty credit worthiness. Pengrowth manages its credit risk by performing a credit review on each marketing counterparty and following a credit practice that limits transactions according to the counterparty’s credit rating as assessed by Pengrowth. In addition, Pengrowth may require letters of credit or parental guarantees from certain counterparties to mitigate some of the credit risk associated with the amounts owing by the counterparty. The use of financial swap agreements involves a degree of credit risk that Pengrowth manages through its credit policies which are designed to limit eligible counterparties to those with investment grade credit ratings or better. The carrying value of accounts receivable and risk management assets represents Pengrowth’s maximum credit exposure.

Pengrowth sells a significant portion of its oil and gas to a limited number of counterparties. Pengrowth has two counterparties that individually account for more than ten percent of monthly revenues. Both counterparties are large, well-established companies supported by investment grade credit ratings.

Pengrowth considers amounts over 90 days as past due. As at December 31, 2008, the amount of accounts receivable that were past due was not significant. Pengrowth has not recorded a significant allowance for doubtful accounts. Management has assessed that no significant impairment issues exist. Pengrowth’s objectives, processes and policies for managing credit risk have not changed from the previous year.

LIQUIDITY RISK

Liquidity risk is the risk that Pengrowth will not be able to meet its financial obligations as they fall due. Pengrowth’s approach to managing liquidity is to ensure, as much as possible, that it will always have sufficient liquidity to meet its liabilities when due, under normal and stressed conditions. Management closely monitors cash flow requirements to ensure that it has sufficient cash on demand or borrowing capacity to meet operational and financial obligations over the next three years. Pengrowth maintains a committed $1.2 billion term credit facility with a syndicate of seven Canadian and four foreign banks and a $50 million demand operating line of credit. Pengrowth’s long term notes and bank credit facilities are unsecured and equally ranked.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All of Pengrowth’s financial liabilities are current and due within one year, except as follows:

	Carrying		Contractual		within						More than
December 31, 2008	Amount		Cash Flows		1 year		1-2 years		2-5 years		5 years
Cdn dollar revolving credit facility(1)	$	372,000	$	393,919	$	8,630	$	8,630	$	376,658	$	—
Cdn dollar senior unsecured notes(1)		15,000		24,556		992		992		2,975		19,599
U.S. dollar denominated senior unsecured notes(1)		1,049,218		1,570,918		65,805		65,805		414,482		1,024,826
U.K. Pound Sterling denominated unsecured notes(1)		88,285		122,286		4,847		4,847		14,541		98,052
Convertible debentures(1)		74,915		84,457		4,858		79,599		—		—
Remediation trust fund payments		—		12,500		250		250		750		11,250
Foreign Exchange Risk Management Contracts Cash Outflow (Inflow)		18,727		210		30		30		90		60

(1) Contractual cash flows include future interest payments calculated at period end exchange rates and interest rates.

21. COMMITMENTS

	2009		2010		2011		2012		2013		Thereafter		Total
Operating leases	$	11,098	$	10,750	$	9,907	$	8,157	$	8,176	$	31,735	$	79,823

Operating leases include office rent and vehicle leases

22. CONTINGENCIES

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

23. SUBSEQUENT EVENTS

Subsequent to December 31, 2008, Pengrowth has entered into a series of fixed price commodity sales contracts with third parties as follows:

Crude Oil:

Remaining term	Volume (bbl/d)		Reference Point		Price per bbl
Financial:
Mar 1, 2009 — Dec 31, 2009		500	WTI	(1)	$58.00 Cdn
April 1, 2009 — Dec 31, 2009		1,000	WTI	(1)	$57.78 Cdn
Jan 1, 2010 — Dec 31, 2010		5,000	WTI	(1)	$69.06 Cdn

(1) Associated Cdn $/U.S. $ foreign exchange rate has been fixed

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 65

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

24. RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The significant differences between Canadian generally accepted accounting principles (Canadian GAAP) which, in most respects, conforms to United States generally accepted accounting principles (U.S. GAAP), as they apply to Pengrowth, are as follows:

(a) As required annually under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at ten percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. At December 31, 2008, the application of the full cost ceiling test under U.S. GAAP resulted in an before-tax write-down of capitalized costs of $1,529.9 million. At December 31, 2007, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs.

Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion will differ in subsequent years. In addition to the write-down of capitalized costs in 2008, Pengrowth had write-downs of capitalized costs in 2006, 1998 and 1997 of $114.2 million, $328.6 million and $49.8 million, respectively. In addition, under U.S. GAAP depletion is calculated based on constant dollar reserves as opposed to escalated dollar reserves required under Canadian GAAP. As such, the depletion rate under U.S. GAAP differs from Canadian GAAP. The effect of ceiling test impairments and a different depletion rate under U.S. GAAP has reduced the 2008 depletion charge by $24.7 million (2007 — $35.8 million). Depletion on a per unit of production was $20.21 per BOE (2007 — $19.83).

(b) Other comprehensive income under U.S. GAAP differs from that presented under Canadian GAAP as a result of designating a cash flow hedge at different dates under U.S. GAAP as compared to Canadian GAAP. Effective January 1, 2007, Pengrowth ceased to designate its foreign exchange swaps as a cash flow hedge of the U.K. term debt. The amount deferred in accumulated other comprehensive income pertaining to this hedging relationship when the hedge was de-designated of $2.4 million is being amortized to income over the remaining life of the foreign exchange swap of approximately nine years at the time it ceased to be designated as a hedge. The accounting treatment for this foreign exchange swap subsequent to January 1, 2007 under U.S. GAAP is consistent with the accounting treatment under Canadian GAAP.

(c) Under U.S. GAAP, securities which are subject to mandatory redemption requirements or whose redemption is outside the control of the issuer must be classified outside of permanent equity and are to be recorded at their redemption amount at each balance sheet date with changes in redemption amount being charged to the deficit. The amount charged to the deficit representing the change in the redemption amount between balance sheet dates for the periods presented must also be disclosed. Furthermore, the balance sheet disclosure of “trust unitholders’ capital” would not be permitted and trust unitholders’ capital would be reclassified to mezzanine equity, a liability.

The trust units are redeemable at the option of the holder at a redemption price equal to the lesser of 95% of the average closing price of the trust units for the 10 trading days after the trust units have been surrendered for redemption and the closing price on the date the trust units have been surrendered for redemption. However, the total amount payable by the Trust in cash in any one calendar month is limited to a maximum of $25,000. Redemptions in excess of the cash limit must be satisfied by way of a distribution in specie of a pro rata share of royalty units and other assets, excluding facilities, pipelines or other assets associated with oil and gas production, which are held by the Trust at the time the trust units are to be redeemed. As a result of the significant limitation on the cash amount payable by the Trust in respect of redemptions, and that any royalty units issued would have similar characteristics of the trust units and be convertible back into trust units, the trust units have not been classified as redeemable equity for the purposes of U.S. GAAP.

(d) Under U.S. GAAP, an entity that is subject to income tax in multiple jurisdictions is required to disclose income tax expense in each jurisdiction. Pengrowth is subject to tax at the federal and provincial level. The portion of the income tax reduction taxed at the federal level for the year ended December 31, 2008 is $319.5 million (2007 — $219.0 million). The portion of income tax reduction taxed at the provincial level is $173.8 million (2007 – $114.7 million).

As a result of changes to income trust tax legislation in 2007 that modify the taxation of certain flow-through entities including mutual fund trusts and their unitholders, Pengrowth has recognized future income taxes on temporary differences in the trust legal entity during the period. Previously, future income taxes were recorded only on temporary differences in the corporate subsidiaries of the Trust. An additional $138.5 million future income tax reduction was recorded under U.S. GAAP in the second quarter of 2007 resulting from the tax basis of the assets in the Trust further exceeding their book basis under U.S. GAAP due to write downs of petroleum and natural gas properties and differences in the future income tax rate applicable under U.S. GAAP.

66 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(e) Additional disclosures required by SFAS 123 (revised 2004) with respect to Pengrowth’s equity incentive plans is provided below.

The intrinsic value of the DEUs, trust unit rights and trust unit options exercised was as follows:

	2008				2007
	Number		Intrinsic		Number		Intrinsic
	Exercised		Value		Exercised		Value
DEUs		202,020	$	4,511		2,931	$	58
Trust Unit Rights		263,857		1,271		343,925		2,837
Trust Unit Options		26,506		64		6,690		32
Total		492,383	$	5,846		353,546	$	2,927

The following table summarizes information about trust unit options, trust unit rights and DEUs vested and expected to vest:

	Trust Units		Trust Unit
At December 31, 2008	Options		Rights		DEUs
Number vested and expected to vest		1,700		3,158,397		1,117,550
Weighted average exercise price per unit(1)	$	14.95	$	16.76	$	—
Aggregate intrinsic value(2)	$	—	$	—	$	10,449
Weighted average remaining life (years)		0.5		3.20		1.4

	Trust Units		Trust Unit
At December 31, 2007	Options		Rights		DEUs
Number vested and expected to vest		66,318		2,088,505		921,480
Weighted average exercise price per unit(1)	$	15.25	$	17.26	$	—
Aggregate intrinsic value(2)	$	157	$	756	$	16,236
Weighted average remaining life (years)		0.8		3.3		1.5

(1)	No proceeds are received upon exercise of DEUs
(2)	Based on December 31 closing trust unit price.

The following table summarizes information about trust unit options and trust unit rights outstanding:

	Trust Units		Trust Unit
At December 31, 2008	Options		Rights		DEUs
Number exercisable(1)		1,700		1,950,375		2,209
Weighted average exercise price per unit(2)	$	14.95	$	16.52	$	—
Aggregate intrinsic value(3)	$	—	$	—	$	25
Weighted average remaining life (years)		0.5		2.70		—

	Trust Units		Trust Unit
At December 31, 2007	Options		Rights		DEUs
Number exercisable		66,318		1,317,296		—
Weighted average exercise price per unit(1)	$	15.25	$	16.30	$	—
Aggregate intrinsic value(2)	$	157	$	1,743	$	—
Weighted average remaining life (years)		0.8		3.3		—

(1)	DEUs exercisable at December 31, 2008 were granted to employees on long-term leave on vesting date. DEUs will be exercised upon return from long-term leave or termination from the plan. No DEUs were exercisable at December 31, 2007
(2)	No proceeds are received upon exercise of DEUs.
(3)	Based on December 31 closing price.

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 67

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(f) Under Canadian GAAP, the convertible debentures are classified as debt with a portion, representing the estimated fair value of the conversion feature at the date of issue, being allocated to equity. In addition, under Canadian GAAP a non-cash interest expense or income representing the effective yield of the debt component is recorded in the consolidated statements of income with a corresponding credit or debit to the convertible debenture liability balance to accrete the balance to the principal due on maturity as a result of the portion allocated to equity.

Under U.S. GAAP, the convertible debentures, in their entirety, are classified as debt. The non-cash interest expense recorded under Canadian GAAP related to the equity portion of the debenture would not be recorded under U.S. GAAP.

(g) In July 2006, FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) was issued. FIN 48 is an interpretation of FASB Statement No 109, “Accounting for Income Taxes,” and it seeks to reduce the diversity in practice associated with certain aspects of measurement and recognition in accounting for income taxes. In addition, FIN 48 provides guidance on derecognition, classification, interest and penalties, and accounting in interim periods and requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 was effective as of the beginning of Pengrowth’s 2007 fiscal year. The cumulative effect, if any, of applying FIN 48 was to be reported as an adjustment to the opening deficit in the year of adoption. Adoption of FIN 48 on January 1, 2007 did not have a material effect on Pengrowth’s financial statements. Interest and penalties related to uncertain tax positions, which are included in income tax expense, were not material for the years ended December 31, 2008 and December 31, 2007.

The following table summarizes the unrecognized tax benefits under FIN 48:

	2008			2007
Balance, January 1	$	17,810		$	—
Additions based on tax positions in the year		3,859			17,810
Decrease due to change in tax rates		(430	)		—
Balance, December 31	$	21,239		$	17,810

The following table summarizes open taxation years, by jurisdiction:

Jurisdiction	Years
Federal		2004 — 2008
Alberta, British Columbia, Saskatchewan, and Nova Scotia		2004 — 2008

The 2004 tax examination by federal authorities is currently in progress.

Under FIN 48, unrecognized tax benefits are classified as current or long-term liabilities as opposed to future income tax liabilities. It is anticipated that no amount of the current or prior year unrecognized tax benefit will be realized in the next year. The unrecognized tax benefit, if recognized, would have a favourable impact on Pengrowth’s effective income tax rate in future periods.

(h) Fair Value Measurements In September 2006, FASB issued Statement of Financial Accounting Standard No. 157 (“SFAS 157”). FAS 157 defines fair value and establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measurements. In February 2008, FASB issued Staff Position No 157-2 (“FSP 157-2”) which allows for a one year deferral on the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequently than annually).

Effective January 1, 2008, Pengrowth adopted SFAS 157 (as amended) for assets and liabilities measured or disclosed at fair value, with the one year deferral for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis. There was no impact on the financial position, results of operations or cash flows as a result of the adoption of SFAS 157 for financial assets and liabilities. Pengrowth has not assessed the impact of SFAS 157 on non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis.

68 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SFAS 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are unadjusted quoted prices, in active markets for identical assets or liabilities at the measurement date. Level 2 inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date with consideration given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

The following tables provide fair value measurement information for financial assets and liabilities as of December 31, 2008 and December 31, 2007. The carrying value of cash equivalents, accounts receivable, accounts payable and accrued liabilities, bank indebtedness, due from manager and distributions payable included in the consolidated balance sheet approximate fair value due to the short term nature of those instruments. The fair value of the Canadian dollar revolving credit facility is equal to its carrying amount as the facility bears interest at floating rates. These assets and liabilities are not included in the following tables.

					Fair Value Measurements Using:
					Quoted Prices in		Significant		Significant
	Carrying				Active Markets		Other Observable		Unobservable
As at December 31, 2008	Amount		Fair Value		(Level 1)		Inputs (Level 2)		Inputs (Level 3)
Financial Assets
Remediation trust funds	$	27,122	$	26,948	$	26,948	$	—	$	—
Fair value of risk management contracts		164,692		164,692		—		164,692		—
Other Assets
- Investment in Result Energy Inc		624		624		624		—		—
Financial Liabilities
U.S. dollar denominated debt		1,049,218		1,213,723		—		1,213,723		—
U.K. Pound
Sterling denominated debt		88,285		95,495		—		95,495		—
Canadian dollar denominated debt		15,000		16,074		—		16,074		—
Convertible debentures		74,915		68,014		68,014		—		—
Fair value of risk management contracts		18,727		18,727		—		18,727		—

					Fair Value Measurements Using:
					Quoted Prices in		Significant		Significant
	Carrying				Active Markets		Other Observable		Unobservable
As at December 31, 2007	Amount		Fair Value		(Level 1)		Inputs (Level 2)		Inputs (Level 3)
Financial Assets Remediation trust funds	$	18,094	$	18,107	$	18,107	$	—	$	—
Fair value of risk management contracts		14,058		14,058		—		14,058		—
Financial Liabilities
U.S. dollar denominated debt		591,794		627,674		—		627,674		—
U.K. Pound Sterling denominated debt		97,444		96,181		—		96,181		—
Convertible debentures		75,030		74,741		74,741		—		—
Fair value of risk management contracts		93,459		93,459		—		93,459		—

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 69

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

LEVEL 1 FAIR VALUE MEASUREMENTS

Remediation trust funds — Investments in the SOEP remediation trust fund are recorded at fair value which is based on the market value of the underlying investments in the fund at the balance sheet date. The fair value of the Judy Creek remediation trust fund is based on the market value of the underlying investments in the fund at the balance sheet date.

Convertible debentures — The fair value of the convertible debentures has been determined using the closing trading price of the debentures on the balance sheet date.

Investment in Result Energy Inc. — The fair value of the investment in Result Energy Inc. (Result) has been determined using the closing trading price of the Result’s common shares on the balance sheet date.

LEVEL 2 FAIR VALUE MEASUREMENTS

Risk management contracts – The fair value of the risk management contracts are estimated based on the mark-to-market method of accounting, using publicly quoted market prices or, in their absence, third-party market indications and forecasts priced on the last trading day of the applicable period.

Foreign and Canadian dollar denominated debt — The fair value of the foreign and Canadian dollar denominated term notes is determined based on the risk free interest rate on government debt instruments of similar maturities, adjusted for estimated credit risk, industry risk and market risk premiums.

(i) Under U.S. GAAP, unrealized gains or losses on commodity risk management would be included with oil and gas sales.

(j) New Accounting Pronouncements

In March 2008, FASB issued SFAS No. 161, ‘Disclosures about Derivative Instruments and Hedging activities’ (“SFAS 161”). SFAS 161 requires entities to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This statement is effective for years beginning on or after November 15, 2008. Pengrowth has not yet determined the impact of SFAS 161 on the financial statement disclosures.

In December 2007, FASB revised SFAS No. 141, ‘Business Combinations’ (“SFAS 141R”). SFAS 141R requires an acquirer to be identified for all business combinations and applies the same method of accounting for business combinations – the acquisition method – to all transactions. In addition, transaction costs associated with acquisitions are required to be expensed. The revised statement is effective to business combinations in years beginning on or after December 31, 2008. Pengrowth expects that SFAS 141R will have a significant impact on the purchase price allocations completed after the effective date of SFAS 141R.

In December 2008, the Securities and Exchange Commission published final updated rules for disclosure of oil and gas reserves by public companies. The new rules include using the average of the commodity prices on the first day of each month of the year rather than year end pricing for impairment testing, in addition to a number of changes to reserve reporting. These changes are effective for reporting on or after January 1, 2010. For Pengrowth, these changes will take effect for the December 31, 2009 year end. Pengrowth anticipates a significant impact on the future write-downs of capitalized costs. Under the new rules, it is unlikely Pengrowth would have recorded an impairment of capitalized costs in the year ended December 31, 2008.

70 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | PENGROWTH 2008

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

The application of U.S. GAAP would have the following effect on net income as reported:

(Stated in thousands of Canadian Dollars, except per trust unit amounts)

Years ended December 31	2008			2007
Net income for the period, as reported	$	395,850		$	359,652
Adjustments:
Depletion and depreciation (a)		24,735			35,761
Ceiling test write-down (a)		(1,529,935	)		—
Deferred foreign exchange loss		—			(242	)
Amortization of discontinued hedge (b)		272			272
Non-cash interest on convertible debentures (f)		40			69
Future tax adjustments		421,369			69,040
Net (loss) income — U. S. GAAP	$	(687,669	)	$	464,552
Other comprehensive (loss) income:
Amortization of discontinued hedge (b)		(272	)		(272	)
Comprehensive (loss) income — U. S. GAAP	$	(687,941	)	$	464,280
Net (Loss) Income — U. S. GAAP — basic and diluted	$	(2.75	)	$	1.89

CONSOLIDATED BALANCE SHEETS

The application of U.S. GAAP would have the following effect on the balance sheets as reported:

(Stated in thousands of Canadian Dollars)

			Increase
As at December 31, 2008	As Reported		(Decrease)			U. S. GAAP
Assets
Property, plant and equipment (a)	$	4,251,381	$	(1,751,873	)	$	2,499,508
Future income taxes (d)(g)		—		183,366			183,366
			$	(1,568,507	)
Liabilities
Convertible debentures (f)	$	74,915	$	80		$	74,995
Future income taxes (d) (g)		328,282		(328,282	)		—
Other long term liabilities (g)		—		21,239			21,239
Unitholders’ equity (c):
Accumulated other comprehensive income (b)	$	—	$	1,902		$	1,902
Trust unitholders’ equity (a)		2,663,805		(1,263,446	)		1,400,359
			$	(1,568,507	)

PENGROWTH 2008 | NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 71

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			Increase
As at December 31, 2007	As Reported		(Decrease)			U. S. GAAP
Assets
Property, plant and equipment (a)	$	4,306,682	$	(246,673	)	$	4,060,009
			$	(246,673	)
Liabilities
Convertible debentures (f)	$	75,030	$	120		$	75,150
Future income taxes (d)(g)		387,100		(86,850	)		300,250
Other long term liabilities (g)		—		17,810			17,810
Unitholders’ equity (c):
Accumulated other comprehensive income (b)	$	—	$	2,174		$	2,174
Trust unitholders’ equity (a)		2,756,220		(179,927	)		2,576,293
			$	(246,673	)

ADDITIONAL DISCLOSURES REQUIRED UNDER U.S. GAAP

The components of accounts receivable are as follows:

As at December 31	2008		2007
Trade	$	159,274	$	179,253
Prepaid		37,857		27,330
	$	197,131	$	206,583

The components of accounts payable and accrued liabilities are as follows:

As at December 31	2008		2007
Accounts payable	$	94,799	$	93,180
Accrued liabilities		166,029		145,911
	$	260,828	$	239,091

72 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | PENGROWTH 2008

APPENDIX D

OIL AND GAS PRODUCING ACTIVITIES PREPARED IN ACCORDANCE WITH SFAS NO. 69 – “DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES”

SUPPLEMENTAL INFORMATION — OIL AND GAS PRODUCING ACTIVITIES (unaudited)

The following disclosures have been prepared in accordance with SFAS No. 69 — “disclosures about Oil and Gas Producing Activities.”:

OIL AND GAS RESERVES

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Trust’s estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Trust’s share of future production from Canadian reserves to be materially different from that presented.

Subsequent to December 31, 2008 no major discovery or other favorable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES

The following table sets forth revenue and direct cost information relating to the Trust’s oil and gas producing activities for the years ended December 31.

	2008			2007
Revenue
Sales	$	1,500,604		$	1,422,148
Deduct
Production costs		(394,532	)		(378,216	)
Transportation costs		(12,519	)		(12,672	)
Amortization of injectant costs		(25,876	)		(34,063	)
Technical support and other		(23,965	)		(28,306	)
Depletion, depreciation and amortization		(596,176	)		(603,323	)
Results of operations from producing activities	$	447,536		$	365,568

1. The costs in this schedule exclude corporate overhead, interest expense and other operating costs which are not directly related to producing activities.

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

Costs incurred in oil and gas producing activities for the years ended December 31 are as follows:

	2008		2007
Property acquisition costs
Proved	$	182,401	$	986,148
Unproved		—		383,355
Exploration costs		22,012		21,192
Development costs		365,304		261,866
Injectants costs		21,009		26,052
	$	590,726	$	1,678,613

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

Development and exploration costs include the costs for drilling and equipping development and exploratory wells and constructing facilities to extract, treat and gather and store oil and gas and additions to asset retirement obligations.

Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated to be 24 months.

Pengrowth capitalizes a portion of general and administrative costs associated with exploration and development activities. Transaction costs directly attributable to successful acquisitions are also capitalized.

Approximately $45.4 million (2007 — nil) of costs to acquire and evaluate unproven properties has been excluded from depletion.

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

The capitalized costs and related accumulated depreciation, depletion and amortization, including impairments, relating to the Trust’s oil and gas exploration, development and producing activities at December 31 consist of:

	2008			2007
Oil and gas properties	$	7,079,703		$	6,534,343
Less accumulated depletion, depreciation and amortization		(4,635,531	)		(2,529,218	)
Net capitalized costs	$	2,444,172		$	4,005,125
Unproved oil and gas properties	$	484,426		$	1,056,851
Proven oil and gas properties		1,959,746			2,948,274
Net capitalized costs	$	2,444,172		$	4,005,125

OIL AND GAS RESERVE INFORMATION

All of the Trust’s proved oil, natural gas liquids, and natural gas reserves are located in Canada, primarily in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia. The Trust’s proved developed and undeveloped reserves after deductions of royalties are summarized below:

NET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIES

	Crude Oil		Natural
	and NGL’s		Gas
	MMbbl		Bcf
End of year 2006		102.2		491.9
Revisions of previous estimates (including infill drilling & improved recovery)		4.5		34.2
Purchase of reserves in place		20.6		133.4
Sale of reserves in place		-4.3		-79.9
Discoveries and extensions		1.1		27.1
Production		-12.6		-78.0
End of year 2007		111.5		528.7
Revisions of previous estimates (including infill drilling & improved recovery)		3.6		40.3
Purchase of reserves in place		2.6		16.1
Sale of reserves in place		0.0		-1.0
Discoveries and extensions		1.3		12.3
Production		-12.3		-71.5
End of year 2008		106.7		524.9

NET PROVED DEVELOPED RESERVES AFTER ROYALTIES

	Crude Oil		Natural
	and NGL’s		Gas
	MMbbl		Bcf
End of year 2006		84.1		453.1
End of year 2007		93.0		474.9
End of year 2008		87.9		474.4

Notes:
1.	Net after royalty reserves are the Trust’s lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Crown royalties are subject to change by legislation or regulation and vary depending on production rates, selling prices and potentially timing of initial production.
2.	Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations, from a given date forward, by known technology, under existing operating conditions and prices in effect at year end.
3.	Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
4.	Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

The following information has been developed utilizing procedures described by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the independent engineering consultants of the Trust. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Trust or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Trust’s reserves.

The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2008 was based on the following benchmark prices; Edmonton par crude oil price of $44.27/bbl and AECO natural gas price of $6.22/MMBtu. The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2007 was based on the following benchmark prices; Edmonton par crude oil price of $93.39/bbl and AECO natural gas price of $6.63/MMBtu.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES

The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Trust’s crude oil and natural gas reserves at December 31, for the years presented.

	2008			2007
Future cash inflows	$	8,843		$	12,796
Future costs
Future production and development costs		(5,409	)		(4,957	)
Future income taxes		(635	)		(2,000	)
Future net cash flows		2,799			5,839
Deduct: 10% annual discount factor		(1,012	)		(2,149	)
Standardized measure of discounted future net cash flows	$	1,787		$	3,690

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES

The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented.

	2008			2007
	$MM			$MM
Future discounted net cash flow at beginning of year		3,690			3,166
Sales & transfer, net of production costs		(1,044	)		(970	)
Net change in sales & transfer prices		(2,406	)		1,111
Development costs incurred during the period		362			271
Change in future development costs		(371	)		(346	)
Change due to extensions, discoveries and improved recovery		33			130
Change due to revisions (including infill drilling)		111			234
Accretion of discount		459			317
Sales of reserves in place		(4	)		(303	)
Purchase of reserves in place		56			983
Net change in Income Taxes		616			(895	)
Changes in timing of future net cash flow and other		285			(8	)
Future discounted net cash flow at end of year		1,787			3,690

Note:
1.	The schedules above are calculated using year-end prices, costs, statutory tax rates and proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.

APPENDIX E

PENGROWTH ENERGY TRUST CODE OF BUSINESS CONDUCT AND ETHICS
DATED FEBRUARY 17, 2009

Pengrowth Energy Trust

CODE OF BUSINESS CONDUCT
AND ETHICS

February 17, 2009

TABLE OF CONTENTS

	Page
Application		1
Purpose		1
Policy		1
Compliance with the Law		2
Health, Safety and the Environment		3
Public Reporting		3
Conflict of Interest		4
Private Business		5
Payments		5
Political Contributions		6
Involvement with Not-for-Profit Organizations		6
Outside Employment		6
Directorships		7
Government Relations		7
Confidential Information		7
Company Information		7
Inside Information		8
Books of Account		9
Patents and Inventions		9
Community Relations		9
Company Property and Opportunities		10
Accounting and Financial Reporting		10
Employee Relations and Reporting		10
Policies, Procedures and Internal Controls		10
Acknowledgement		11
Exceptions and Changes		11
Appendix “A” Complaint Procedures For Accounting, Financial Reporting and Auditing Matters and Violations of the Code of Business Conduct and Ethics		12
Appendix “B” Awareness Statement on Code of Business Conduct and Ethics		15

Application

Unless expressly provided herein to the contrary, this Code of Business Conduct and Ethics (the “Code”) applies to all directors, officers, employees, consultants and contractors (each, a, “Member”) of Pengrowth Corporation, Pengrowth Management Limited, Pengrowth Energy Trust and their respective subsidiaries and affiliates (collectively, referred to herein as “Pengrowth”).

Purpose

Pengrowth’s reputation for honesty and integrity has been earned by maintaining the highest standards of business ethics in all our interactions with our co-workers, governments, local communities, shareholders, customers, suppliers, competitors and the public. The commitment of every Member to preserve and perpetuate the letter and spirit of this Code is essential to our continued success.

This Code affirms the policy of Pengrowth and is a guideline to:

• assure compliance with laws and regulations that govern the business activities of Pengrowth;

• maintain a corporate climate in which the integrity and dignity of each individual is valued;

• foster a standard of conduct that reflects positively on Pengrowth; and

• protect Pengrowth from unnecessary exposure to financial loss.

This Code does not specifically address every potential form of unacceptable conduct, and it is expected that Members will exercise good judgment in compliance with the principles set out in this Code. Each Member has a duty to avoid any circumstance that would violate the letter or spirit of this Code. Unscrupulous dealings, non-compliance with this Code or the law or other dishonest or unethical business practices are forbidden and may result in disciplinary action, including termination from employment or termination of contractual relations.

It is important that Pengrowth be made aware of circumstances that may indicate possible violations of law or this Code. Pengrowth and applicable law prohibit any form of retaliation for raising concerns or reporting possible misconduct in good faith or for assisting in the investigation of possible misconduct. Any violations of this Code must be promptly reported to an appropriate person as outlined in Appendix “A”. Any Member may submit a complaint regarding a suspected violation of the Code without fear of dismissal or retaliation.

Policy

Pengrowth and all of its Members will adhere to the highest ethical standards in all our business activities. Any situation, decision or response should first consider what is right and how it reflects on Pengrowth. Although the various matters described in this Code do not cover the full spectrum of employee and contractor activities, they are indicative of the type of behaviour expected from employees and contractors in all circumstances.

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Members are expected to comply with all aspects of this Code.

If a director or officer has any question of appropriateness in a particular situation, areas of conflict or disagreement with any aspect of this policy, the matter should be discussed with the Chief Financial Officer, Lead Director or the Chairman of the Board of Directors of Pengrowth Corporation.

If an employee has any question of appropriateness in a particular situation, areas of conflict or disagreement with any aspect of this policy, the matter should be discussed with the employee’s manager. It is recognized that there may be situations in which it is impractical or inappropriate for an employee to bring the matter to his or her manager. In these instances, employees should seek the advice of the Director, Human Resources or Pengrowth’s legal counsel.

If a consultant or contractor has any question of appropriateness in a particular situation, areas of conflict or disagreement with any aspect of this policy, the matter should be discussed with the consultant’s or contractor’s supervisor.

Compliance with the Law

A concern for what is right underlies all business decisions. An issuer may be held liable for the wrongful actions of its directors, officers, employees, consultants or contractors. Accordingly, each Member must ensure that his or her dealings and actions on behalf of Pengrowth comply with the spirit and intent of all relevant legislation and regulations including those set by a self regulatory body or professional organization. Particular attention is directed to the laws and regulations relating to discrimination, privacy, securities, labour, safety and the environment.

In addition to the laws imposed by statute, the law also imposes a duty upon a company to honour agreements, whether in writing or not, and to act reasonably and in a manner that will not cause harm to others. Members must diligently ensure that their conduct is not and cannot be interpreted as being a contravention of laws governing the affairs of Pengrowth in any jurisdiction where it carries on business.

Ignorance of the law will not usually excuse a party who contravenes a law. Members are responsible to keep informed of laws which may affect those affairs of Pengrowth which are under his or her control.

Whenever a Member is in doubt about the application or interpretation of any legal requirement or has questions about whether particular circumstances may involve illegal conduct, the individual should immediately seek the advice of his or her manager or consult Pengrowth’s legal counsel.

Pengrowth is subject to legislation in Canada, the United States and other jurisdictions that prohibits corrupt practices in dealing with foreign governments. These laws make it an offence to make or offer a payment, gift or other benefit to a foreign public official in order to induce favourable business treatment, such as obtaining or retaining business or some other advantage in the course of business. Violation of this legislation may result in substantial penalties to Pengrowth and to

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individuals. Foreign public officials include all people who perform public duties or functions for a foreign state. This can include anyone “acting in an official capacity” or under a delegation of authority from the government to carry out government ownership or control, such as national oil companies, regardless of whether the government in question has majority ownership or control.

Pengrowth, as well as each Member, must take all responsible steps to ensure that the requirements of this legislation are strictly met. No payments, gifts or other benefits are to be given, directly or indirectly, to foreign public officials, political parties or political candidates for the purpose of influencing government decisions in Pengrowth’s favour or for securing other improper advantages. Furthermore, no such payments are to be made to agents or other third parties in circumstances where it is likely that part or all of the payment will be passed on to a foreign public official, political party or political candidate.

There are certain types of payments to foreign public officials that are allowed under both the Canadian and U.S. legislation called “facilitation” or “facilitating” payments. These are small payments or tips requested in the context of having routine administrative actions performed by foreign public officials. Members should be aware that such payments are permissible only under very limited circumstances. Advice should be sought from Pengrowth’s legal counsel with respect to the amount and advisability of making a facilitation payment. Moreover, we must ensure that any such payments are properly recorded in accordance with Pengrowth’s accounting procedures.

Health, Safety and the Environment

Pengrowth is committed to safe and healthful working conditions for all Members and third parties, and to conducting its activities in an environmentally responsible manner consistent with the principles of sustainable development.

Members are expected to read and to understand Pengrowth’s Environmental and Safety Policies and Procedures and participate fully in this effort by improving operations to avoid injury or sickness to persons, and damage to property and the environment and by giving due regard to all applicable safety standards, regulatory requirements, technical and conventional standards and restraints.

All conditions, situations or accidents which give rise to health, safety or environmental concerns must be immediately reported to the Manager, Safety and Training or the Manager, Environment.

Pengrowth authorizes each of its Members to take any emergency actions that are necessary or desirable to minimize any critical health, safety or environmental problems provided those actions are consistent with Pengrowth’s philosophy and practices regarding health, safety and environmental protection.

Public Reporting

Full, fair, accurate, timely and understandable disclosure in the reports and other documents that Pengrowth files with, or submits to, the securities commissions and in its other public communications is critical for Pengrowth to maintain its good reputation, to comply with its obligations under the securities laws and to meet the expectations of its securityholders and other members of the investment community.

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Persons responsible for the preparation of such documents and reports and other public communications are to exercise the highest standard of care in their preparation in accordance with the following guidelines:

• all accounting records, and the reports produced from such records, must be in accordance with all applicable laws;

• all accounting records must fairly and accurately reflect the transactions or occurrences to which they relate;

• all accounting records must fairly and accurately reflect in reasonable detail Pengrowth’s assets, liabilities, revenues and expenses;

• no accounting records should contain any false or intentionally misleading entries;

• no transactions should be intentionally misclassified as to accounts, departments or accounting periods;

• all transactions must be supported by accurate documentation in reasonable detail and recorded in the proper account and in the proper accounting period;

• no information should be concealed from the internal auditors or the independent auditors; and

• compliance with Pengrowth’s system of internal controls is required.

Conflict of Interest

Members must avoid interests or relationships where their personal interests may affect their judgement in acting in the best interests of Pengrowth. This requires that each Member act in such a manner that his or her conduct will bear the closest scrutiny should circumstances demand that it be examined.

Where a conflict of interest situation may exist or be perceived to exist, the Member may be put in a compromising position or his or her judgement may be questioned. Pengrowth wants to ensure that all Members are, and are perceived to be, free to act in the best interests of Pengrowth. Disclosure of areas of potential conflict of interest will allow appropriate steps to be taken to protect the individual from these situations.

Each director and officer who is a party to a material contract or proposed material contract with Pengrowth or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with Pengrowth of which he has knowledge is required to disclose in writing to the Chairman of the Board of Directors the nature and extent of the director’s or officer’s interest. The Chairman shall make any such disclosure concerning himself to the Lead Director.

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Officers, employees, consultants and contractors are required to disclose to the appropriate Vice President in writing all business, commercial or financial interests and activities which might reasonably be regarded as creating an actual or potential conflict with their duties of employment. Senior management will determine whether a conflict of interest does or could exist and, if necessary, advise the person of what steps should be taken. Directors are required to disclose to the chairman of the Corporate Governance Committee (or, in the case of the chairman of the Corporate Governance Committee, to another member of the Committee) all business, commercial or financial interests and activities which might reasonably be regarded as creating an actual or potential conflict with their duties as directors.

There are many situations which can be classified as conflicts of interest, but the following examples illustrate those that are most common.

     Private Business

Unless otherwise consented to by his or her immediate superior, a Member, either directly or indirectly through his or her immediate family or by any other means, must not have a personal financial interest in, or place himself or herself in a position where he or she could derive a benefit or interest from, a business transaction with Pengrowth, which financial interest or benefit is of such a nature that it would reasonably be expected to create a conflict of interest for the Member.

This, however, does not prevent a Member and his or her family from having ownership in publicly traded shares or equity in companies which may do business with Pengrowth or prevent a consultant or contractor from providing his or her services to Pengrowth through a third party corporation.

     Payments

It is Pengrowth’s policy to deal fairly and lawfully with all customers, suppliers and independent contractors purchasing or furnishing goods or services. All goods and services shall be obtained on a competitive basis at the best value considering price, quality, reliability, availability and delivery.

Members shall not accept gratuities or favours of any sort having more than a nominal value from any person, organization or group that does, or is seeking to do, business with Pengrowth or any of its affiliates or from a competitor of Pengrowth or any of its affiliates. Members should neither seek nor accept gifts, payments, services, fees, trips or accommodations, special privileges of value or loans from any person, organization or group that does, or is seeking to do, business with Pengrowth or any of its affiliates (unless they are in the business of lending, and then only on conventional terms) or from a competitor of Pengrowth or any of its affiliates. Gifts of nominal value (advertising mementos, desk calendars or pens), acceptance of hospitality or entertainment (lunch, dinner or tickets to a local sporting event) and attendance at transaction closing celebrations are acceptable, provided that acceptance of such gifts, hospitality or entertainment and closing celebrations would not reasonably be expected to create a conflict of interest. Directors should report gifts of a questionable nature to the Lead Director or Chairman of the Board of Directors and officers, employees, consultants and contractors should report gifts of a questionable nature to their superior.

Except as contemplated herein, no Member shall offer or provide, either personally or on behalf of Pengrowth, any expensive gifts, excessive entertainment or payments of any amount of money to

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any supplier, customer, sub-contractor, or competitor of Pengrowth’s, or to any public official or their representatives, nor pay to them, either directly or indirectly, any commissions or fees which are excessive in relation to the services rendered. Modest gifts, favours and entertainment may be furnished by Members whose duties permit them to do so, provided all of the following tests are met:

Ø	they are not in cash or securities and are of nominal value;
Ø	they do not contravene any law and are made as a matter of general and accepted practice or in accordance with corporate policy; and
Ø	if subsequently disclosed to the public, they would not in any way embarrass Pengrowth or their recipients.

It is acknowledged that, from time to time, Pengrowth holds investor conferences, the purpose of which is to educate investors and brokers about the oil and gas business generally and Pengrowth’s business specifically. A portion of the costs incurred by attendees of the conferences is paid by Pengrowth.

     Political Contributions

Any political contribution made on behalf of Pengrowth shall comply with the following requirements:

(a)	any such contribution may only be made to a political party and not to an individual candidate for election to public office;
(b)	any such contribution requires the approval of the Chief Executive Officer; and
(c)	any such contribution must be within the approved operating budget of Pengrowth.

Contributions are deemed to include money, anything of value (e.g., loans, services or the use of Pengrowth facilities or assets) and time spent by employees during normal work hours away from work responsibilities. Individual Members are free to make political contributions in their personal capacity.

     Involvement with Not-for-Profit Organizations

As a responsible community citizen, Pengrowth encourages and supports employee participation in charitable, educational, cultural, political and not-for-profit organizations. Employees are reminded that such participation should not be of a nature or extent that it adversely affects an employee’s job performance or puts the employee in a conflict of interest position (see “Conflict of Interest” above).

     Outside Employment

Pengrowth recognizes that some employees may, from time to time, hold additional part-time employment outside their employment relationship with Pengrowth. Employees are reminded that any such outside employments should not be of a nature or extent that it adversely affects the

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employee’s job performance at Pengrowth or puts the employee in a conflict of interest position (see “Conflict of Interest” above). All employees who hold management positions with Pengrowth shall obtain the approval of their supervisor before accepting any such outside employment.

     Directorships

Any officer or employee shall obtain the approval of the Chief Executive Officer prior to accepting a position as a director of a for-profit company or business organization. The Chief Executive Officer shall obtain the approval of the Board of Directors prior to accepting a position as a director of a for-profit company or business organization. A director shall advise the Lead Director and the Chairman of the Board of Directors prior to accepting a position as a director of a for-profit company or business organization.

     Government Relations

Pengrowth, as a company offering services to a regulated industry and providing services which relate directly to regulations, must be especially sensitive to the interaction with public officials. All interaction and communications between Members and public officials are to be conducted in the highest ethical manner and must not compromise the integrity or reputation of any public official, Pengrowth, its affiliates or its employees.

Confidential Information

In the course of their work, Members may have access to information that is confidential, privileged, of value to competitors of Pengrowth or might be damaging to Pengrowth if improperly disclosed. Pengrowth respects privileged customer and employee related information, and therefore all Members must protect the confidentiality of such information.

The use or disclosure of confidential information must be for company purposes only and not for personal benefit or the benefit of others. This applies to disclosure of confidential information concerning Pengrowth or its business activities as well as information with respect to companies having business dealings with Pengrowth. To preserve confidentiality, disclosure and discussion of confidential information should be limited to those individuals who need to know the information.

     Company Information

Members must guard against improper disclosure of information that may be of competitive value to Pengrowth.

Pengrowth is in a competitive environment with other companies offering similar services. Certain records, reports, papers, devices, processes, plans, methods and apparatus of Pengrowth, including methods of doing business, strategies and information on costs, prices, sales, profits, markets and customers are the property of Pengrowth and are considered to be confidential and proprietary. Members must not reveal such confidential information without consent from their superiors.

Confidential information does not include information which is already in the public domain. Certain information may be released by Pengrowth (to comply with securities regulations, for

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example), however the release of such information is a decision of the Board of Directors and senior management. If there is any doubt as to what can or cannot be discussed outside of Pengrowth, Members should err on the side of discretion and not communicate any information. For more specific advice, your immediate manager or the Chief Financial Officer should be consulted.

These obligations regarding confidential information continue to apply to all Members following cessation of their employment or contractual relations with Pengrowth.

     Inside Information

Certain information, which Pengrowth treats as confidential, may influence the price or trading of Pengrowth’s trust units or other securities if it is disclosed to members of the public. Inside information would include information concerning major contracts, proposed acquisitions or mergers, and sales or earnings figures. Members shall not use such inside information for their own financial gain or for that of their associates.

Inside information is information which (1) has not been publicly released, (2) is intended for use solely by Pengrowth and not for personal use, or (3) is the type usually not disclosed by Pengrowth. All individuals who come into possession of material inside information, before it is publicly disclosed, are considered to be in a special relationship with Pengrowth for the purposes of securities laws. The husbands, wives, immediate families and those under control of insiders may also be regarded as being in a special relationship with Pengrowth. Included in the concept of insider trading is “tipping” or revealing inside information to individuals to enable such individuals to trade in a company’s securities on the basis of undisclosed information.

Members are responsible for being familiar with and abiding by all laws, regulations and rules respecting “insiders” and “insider trading”. The various provincial securities legislation and business corporations acts impose certain liabilities upon every Member of Pengrowth, and any associate of such person, from using for their own benefit in connection with a trade in securities of Pengrowth any inside information, including that which, if generally known, might reasonably be expected to affect materially the market price of shares or other securities.

Pengrowth’s policy parallels the law in that all Members who receive inside information about Pengrowth, its associates, affiliated companies and other companies in which it has an interest are in a position of trust and they must not trade in trust units or other securities on the basis of the information they possess, or otherwise make use of the information for their own benefit or advantage until at such time as the information has been fully disclosed and a reasonable period of time has passed for the information to be disseminated.

Pengrowth has adopted the following rule in respect of trading in securities of Pengrowth by its Members:

If you have knowledge of a material fact, pending change of fact, or material change related to the affairs of Pengrowth or any public issuer involved in a transaction with Pengrowth which is not generally known, no purchase or sale may be made until the knowledge has been made public. In addition, this knowledge must not be conveyed to any other person for the purpose of assisting that person in trading securities.

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For purposes of this rule, public issuer includes any issuer, whether a corporation or otherwise, whose securities are traded in a public market, whether on a stock exchange or “over the counter”. Material change or material fact is one which would be expected to have a significant effect on the market price or value of any securities of a public issuer.

Pengrowth encourages Members to be securityholders in Pengrowth as one way to more tangibly link shareholder interests with those of the Members. However, Members possessing inside information are expected to show integrity and use proper judgement in timing their investments. If in doubt as to the propriety of actions, the Member should seek the advice of the Chief Financial Officer. Reference should be made to thePolicy on Trading in Securitiesof Pengrowth Energy Trust.

     Books of Account

Accurate, timely and reliable books of account and records are essential for effective management to ensure Pengrowth meets its business, legal and financial obligations. As a result, Members should ensure all transactions with which they are involved are authorized and executed in accordance with Pengrowth’s procedures and that all transactions are completely and accurately accounted for and recorded.

     Patents and Inventions

All inventions, discoveries and copyrights made by Members during or as a result of their employment or contractual relations with Pengrowth (where company time, equipment, resources or pertinent information has been used for personal gain) are the property of Pengrowth unless a written release is obtained from the Chief Executive Officer.

Pengrowth and its Members honour the proprietary rights of others as expressed in patents, copyrights, trademarks and industrial design.

     Community Relations

In its business, Pengrowth and its Members come in contact with many members of the business and investment community, including individuals, community groups, public officials and members of the media. Pengrowth strives to maintain its good reputation in the community and therefore needs to ensure that individuals speaking on behalf of Pengrowth recognize and deal with sensitive issues in an appropriate manner. Enquiries from members of the community related to matters of a sensitive nature should be directed to the Director of Government and Public Affairs or a member of senior management. The Director of Government and Public Affairs is then required to refer the matter to either the Chief Executive Officer or Chief Financial Officer whereby such senior officers will respond on behalf of Pengrowth. Reference should also be made to theCorporate Disclosure Policyof Pengrowth Energy Trust.

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Company Property and Opportunities

All Members are responsible for protecting Pengrowth’s assets. Personal use of Pengrowth’s property, including investment and other business opportunities, is not permitted without specific authorization.

Accounting and Financial Reporting

Pengrowth is committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. Every Member is required to follow prescribed accounting and financial reporting procedures. All accounting records should accurately reflect and describe corporate transactions. The recording of such data must not be falsified or altered in any way to conceal or distort assets, liabilities, revenues, expenses or the nature of the activity.

Any suspected violation relating to accounting or financial reporting matters should be reported directly to Grant Thornton LLP pursuant to Appendix “A” to this document.

Employee Relations and Reporting

The continued success of Pengrowth is dependent on our employees, the work they perform, the ideas they contribute, and the ability, creativity and initiative they bring to the organization.

In working together, Pengrowth Members must ensure they treat each other with respect, dignity, honesty and fairness. Pengrowth is committed to providing opportunity for employees to be fully challenged, to develop their skills and abilities, and to reach their career goals.

In all matters related to the supervision and development of Members, including hiring, supervision, compensation, promotion and termination, no person will be discriminated against because of race, religious beliefs, gender (including sexual harassment and pregnancy), sexual orientation, physical or mental disability, ancestry or place of origin.

All Members are encouraged to report any behaviour of other Members which they reasonably believe is illegal or unethical to the Director, Human Resources. Any suspected violation of this Code should be reported directly to the chairman of the Corporate Governance Committee or to Grant Thornton LLP pursuant to Appendix “A”. Reporting can be done on an anonymous basis if the person wishes to do so. No adverse action will be taken against any individual for making a complaint or disclosing information in good faith, and any Member who retaliates in any way against an individual who in good faith reports any violation or suspected violation of this Code will be subject to disciplinary action.

Policies, Procedures and Internal Controls

It is essential that all Members follow established policies, procedures and internal controls. Any exception to established policies, procedures and internal controls is prohibited, unless appropriately authorized in advance by any two officers of Pengrowth who shall report all such approved exceptions to the Audit Committee. Exceptions to this Code are dealt with below under “Exceptions and Changes”.

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Acknowledgement

It is essential that all Members of Pengrowth understand and adhere to this Code.

All Members of Pengrowth will be asked to acknowledge, in writing, their review of and agreement to be bound by this Code as a condition of their new or continuing employment or contractual relations, as the case may be. This acknowledgment must be made: (i) in the case of directors, upon election to the board of directors of the Corporation and annually thereafter; (ii) in the case of officers and employees, upon the commencement of employment and annually thereafter, (iii) in the case of consultants and contractors, upon commencement of this contractual relation and annually thereafter, and such acknowledgement may be provided in electronic format.

The form of certification attached as Appendix “B” is to be used by each Member to disclose anypersonalfacts or dealings that are non-compliant with this Code.

Exceptions and Changes

In very limited circumstances, exceptions may be made by Pengrowth under this Code. Any exception proposed to be made under this Code shall be presented by the Chief Executive Officer to the Corporate Governance Committee for its approval.

Any change to this Code must be in writing, approved by the Board of Directors and signed by the Chief Executive Officer of Pengrowth Corporation and will be disclosed as required by applicable laws and regulations and listing standards.

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Appendix “A”
Complaint Procedures
For Accounting, Financial Reporting and Auditing Matters
and Violations of the Code of Business Conduct and Ethics

Any director, officer or employee of Pengrowth Corporation and its subsidiaries (collectively, referred to herein as “Pengrowth”) may submit a complaint regarding accounting or auditing matters to the management of Pengrowth without fear of dismissal or retaliation of any kind. Pengrowth is committed to achieving compliance with all applicable securities laws and regulations, accounting standards, accounting controls and audit practices. The Audit Committee of Pengrowth will oversee treatment of employee concerns in this area.

Any director, officer, employee, consultant or contractor of Pengrowth may submit a complaint regarding a suspected violation of the Code of Business Conduct and Ethics to the management of Pengrowth without fear of dismissal or retaliation. The Governance Committee of Pengrowth will oversee treatment of employee concerns in this area.

In order to facilitate the reporting of complaints, the Board of Directors of Pengrowth has established the following procedures for (i) the receipt, retention and treatment of complaints regarding accounting, internal accounting controls, financial reporting or auditing matters (“Accounting Matters”); (ii) the receipt, retention and treatment of complaints regarding suspected violations of the Code of Business Conduct and Ethics (“Conduct Matters”); and (iii) the confidential, anonymous submission by directors, officers and employees of concerns regarding questionable Accounting Matters and Conduct Matters.

Receipt of Complaints

• Directors, officers and employees with concerns regarding an Accounting Matter may report their concerns to the chairman of the Audit Committee.

• Directors, officers, employees, consultants or contractors with concerns regarding a Conduct Matter may report their concerns to the chairman of the Corporate Governance Committee.

• Directors, officers and employees may report concerns regarding an Accounting Matter or a Conduct Matter on a confidential or anonymous basis to Grant Thornton LLP, at 1-888-747-7171 or usecare@GrantThornton.ca.

• A director, officer or employee who makes an anonymous submission must be sure to provide sufficient detail to identify the concern being raised. Because the submission is made anonymously, the Audit Committee or the Corporate Governance Committee, as the case may be, will be unable to follow up if there are additional questions. The complaint should, at a minimum, contain dates, places, persons involved and witnesses such that a reasonable investigation or assessment can be conducted.

Scope of Accounting Matters Covered by These Procedures

These procedures relate to director, officer or employee complaints relating to any questionable Accounting Matters, including, without limitation, the following:

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• fraud or deliberate error in the preparation, evaluation, review or audit of any financial statement of Pengrowth;

• fraud or deliberate error in the recording and maintaining of financial records of Pengrowth;

• deficiencies in or non-compliance with Pengrowth’s internal accounting controls;

• misrepresentation or false statement to or by a director, officer, employee or external accountant regarding a matter contained in the financial records, financial reports or audit reports of Pengrowth; or

• deviation from full and fair reporting of Pengrowth’s financial condition.

Treatment of Complaints

• Grant Thornton LLP shall inform (i) the chairman of the Audit Committee of all complaints and concerns provided to it in respect of Accounting Matters; and (ii) the chairman of the Corporate Governance Committee of all complaints provided to it in respect of Conduct Matters.

• Upon receipt of a complaint or concern, the chairman of the Audit Committee or chairman of the Corporate Governance Committee, as the case may be, will (i) determine whether or not the complaint actually pertains to an Accounting Matter or a Conduct Matter and (ii) when possible, acknowledge receipt of the complaint to the sender.

• Complaints relating to an Accounting Matter will be reviewed by the Audit Committee, outside legal counsel or such other persons as the Audit Committee determines to be appropriate. Complaints relating to a Conduct Matter will be reviewed by the Corporate Governance Committee, outside legal counsel and such and the persons as the Corporate Governance Committee determines to be appropriate. In any case, confidentiality will be maintained to the fullest extent possible, consistent with the need to conduct an adequate review.

• Prompt and appropriate corrective action will be taken when and as warranted in the judgment of the Audit Committee or the Corporate Governance Committee, as the case may be.

• Pengrowth will not discharge, demote, suspend, threaten, harass or in any manner discriminate against any individual in the terms and conditions of employment based upon any lawful actions of such individual with respect to reporting of complaints in good faith regarding any Accounting Matter or any Conduct Matter.

• Pengrowth will regard the making of any deliberately false or malicious allegations by an employee as a serious offence which may result in recommendations to the Board of Directors or to senior management of Pengrowth for disciplinary action including dismissal for cause and, if warranted, legal proceedings.

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Reporting and Retention of Complaints and Investigations

• The chairman of the Audit Committee and the chairman of the Corporate Governance Committee will maintain a log of all complaints, tracking their receipt, investigation and resolution and shall prepare a periodic summary report thereof for the Audit Committee or the Corporate Governance Committee, as the case may be.

Adopted by the Board of Directors of Pengrowth Corporation, as administrator of Pengrowth Energy Trust, on February 17, 2009.

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Appendix “B”
Awareness Statement on Code of Business Conduct and Ethics

To be completed by all directors, officers, employees, consultants and contractors
of Pengrowth Energy Trust and its subsidiaries (“Pengrowth”)

I have recently read the Code of Business Conduct and Ethics of Pengrowth (the “Code”), and I can certify that, except as specifically noted below:

1.	I understand the content and consequences of contravening the Code and agree to abide by the Code.
2.	I am in compliance with the Code.
3.	All facts and dealings which I believe to be non-compliant with the Code have been communicated to the appropriate representative of Pengrowth and are detailed below.
4.	(If applicable) After due inquiry and to my best knowledge and belief, no employee, consultant or contractor under my direct supervision is in violation of the Code.
5.	I have and will continue to exercise my best efforts to assure full compliance with the Code by myself and (if applicable) all employees, consultants and contractors under my direct supervision.

Print or type name:

Signature:

Title and location:

Date:

Facts and dealings that I believe to be non-compliant with the Code

(Including potential conflict of interest situations)

1.

2.

(If required, provide additional details on separate sheet).

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