Pengrowth Energy (PGH) 40-F 2007 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, 2007       Commission File Number: 1-31253

PENGROWTH ENERGY TRUST

(Exact name of Registrant as specified in its charter)

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

1311	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
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 246,844,532 Trust Units, of no par value, outstanding as of December 31, 2007.

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

Yeso Noþ

     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.

Yesþ Noo

     This report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the registrant’s Registration Statements on Form F-10 and F-3 (File Nos. 333-146928 and 333-143810, respectively) under the Securities Act of 1933, as amended.

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

CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES

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

Disclosure Controls and Procedures. The required disclosure is included in the section entitled “Disclosure Controls and Procedures” contained in the Registrant’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2007, 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, 2007, 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, 2007, 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, 2007, there were no changes in the Registrant’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant’s internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

None.

IDENTIFICATION OF THE AUDIT COMMITTEE

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

AUDIT COMMITTEE FINANCIAL EXPERT

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

ADDITIONAL DISCLOSURE

Certain disclosure regarding the corporate governance practices of the Registrant, including disclosure of the Registrant’s code of ethics, principal accountant fees and services, pre-approval policies and procedures and off-balance sheet arrangements, is included on pages  98 through  99 and 101 of the Annual Information Form contained in Appendix A. Disclosures regarding the Registrant’s contractual obligations is included on page 76 of Management’s Discussion and Analysis contained in Appendix B.

UNDERTAKING

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

SIGNATURES

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

Date: March 19, 2008	PENGROWTH ENERGY TRUST by its Administrator PENGROWTH CORPORATION
	By:	/s/ James S. Kinnear
		James S. Kinnear
		Chairman, President and Chief Executive Officer

APPENDIX A

PENGROWTH ENERGY TRUST ANNUAL INFORMATION FORM FOR THE YEAR
ENDED DECEMBER 31, 2007

PENGROWTH ENERGY TRUST

ANNUAL INFORMATION FORM
For the year ended December 31, 2007

March 19, 2008

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
Corporate	1
Engineering	2
Abbreviations	3
CONVERSION	4
PRESENTATION OF OUR FINANCIAL INFORMATION	5
PRESENTATION OF OUR RESERVE INFORMATION	5
FORWARD-LOOKING STATEMENTS	5
PENGROWTH ENERGY TRUST	7
Introduction	7
The Trust	7
The Corporation	7
The Trust’s Subsidiaries	7
The Corporation’s Subsidiaries	8
The Manager	8
Intercorporate Relationships	8
Business Strategy and Strengths	9
SIFT Legislation Considerations	11
GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST	12
Recent Developments	12
Historical Developments	16
Trends	19
PENGROWTH MANAGEMENT LIMITED	20
Business	20
Management Agreement	20
Bonus Pool	21
Management Agreement Second Term	22
PENGROWTH – OPERATIONAL INFORMATION	23
Principle Properties	23
Light Oil Properties	24
Heavy Oil Properties	27
Conventional Gas Properties	28
Shallow Gas Properties	31
Offshore Gas Properties	33
Statement of Oil and Gas Reserves and Reserves Data	35
Additional Information Relating to Reserves Data	45
Future Development Costs	47
Finding, Development and Acquisition Costs	47
Future Development Capital	48
Other Oil and Gas Information	49
Additional Information Concerning Abandonment & Reclamation Costs	50
Costs Incurred	51
Exploration and Development Activities	51
Production Estimates	51
Production History (Netback)	52
Replacement of Properties	52
TRUST UNITS	53
The Trust Indenture	53
The Trustee	54
Stock Exchange Listings	54
Ownership Restrictions	54
Redemption Right	54

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

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

Appendix A — Report on Reserves Data by Independent Qualified Reserves Evaluator on Form 51-102F2
Appendix B — Report on Management and Directors on Oil and Gas Disclosure on Form 51-101F3
Appendix C — Audit Committee Terms of Reference

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

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GLOSSARY OF TERMS AND ABBREVIATIONS

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

Corporate

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

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

“Computershare” refers to Computershare Trust Company of Canada;

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

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

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

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

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

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

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

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

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

“Royalty Unitholder” refers to holders of Royalty Units;

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

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

“Trust” refers to Pengrowth Energy Trust;

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

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

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

Engineering

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“Total Proved Plus Probable Reserves” means the aggregate of Proved Reserves and Probable Reserves before the deduction of royalties;

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

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

Abbreviations

“API” refers to the American Petroleum Institute;

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

“bbl”, “bbls”, “Mbbls”, and “MMbbls” refers to barrel, barrels, thousands of barrels and millions of barrels, respectively;

“bblpd” refers to barrels per day;

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

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

“CBM” refers to coal bed methane;

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

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

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

“MMBtu” and “MMBtupd” refers to million British thermal units and million British thermal units per day, respectively;

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

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

“NGLs” refers to natural gas liquids;

“NYSE” refers to the New York Stock Exchange;

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

“SAGD” refers to steam assisted gravity drainage;

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

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

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

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

“TSX” refers to the Toronto Stock Exchange; and

“WTI” refers to West Texas Intermediate.

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

CONVERSION

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

To Convert From	To	Multiply by
Mcf	cubic metre		28.174
cubic metre	cubic feet		35.494
bbls	cubic metre		0.159
cubic metre	bbls		6.29
feet	metre		0.305
metre	feet		3.281
miles	kilometre		1.609
kilometre	miles		0.621
acres	hectares		0.405
hectares	acres		2.471

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

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PRESENTATION OF OUR FINANCIAL INFORMATION

Financial information in this Annual Information Form has been prepared in accordance with Canadian GAAP. Canadian GAAP differs in some significant respects from U.S. GAAP and thus our financial statements may not be comparable to the financial statements of U.S. companies. The principal differences as they apply to us are summarized in note 23 to our audited annual consolidated financial statements for the year ended December 31, 2007, which are available on the SEDAR website at www.sedar.com and in our current Form 40-F, which is available through EDGAR at the SEC’s website at www.sec.gov.

PRESENTATION OF OUR RESERVE INFORMATION

The SEC generally permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and interests of others, which are those reserves that a company has demonstrated by actual production or conclusive formation tests to be economically producible under existing economic and operating conditions. National Instrument 51-101Standards of Disclosure for Oil and Gas Activities(“NI 51-101”) of the Canadian Securities Administrators permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable Reserves are of a higher risk and are less likely to be accurately estimated or recovered than Proved Reserves. Because we are permitted to prepare this Annual Information Form in accordance with Canadian disclosure requirements, we have disclosed in this Annual Information Form reserves designated as “probable”. If this Annual Information Form was required to be prepared in accordance with U.S. disclosure requirements, the SEC’s guidelines would prohibit reserves in these categories from being included. Moreover, in accordance with Canadian practice, we have determined and disclosed reserves and estimated future net cash flow therefrom using both escalated and constant prices and costs; for the constant prices and costs case, prices and costs in effect as of December 31, 2007 were held constant for the economic life of the reserves. The SEC does not permit the disclosure of reserves and estimated future net cash flow therefrom based on escalating prices and costs and generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. For a description of these and additional differences between Canadian and U.S. standards of reporting reserves, see “Risk Factors — Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States”. Additional information prepared in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities” relating to our oil and gas reserves is set forth in our current Form 40-F, which is available through EDGAR at the SEC’s website at www.sec.gov.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of Canadian securities legislation and the United StatesPrivate Securities Litigation Reform Act of 1995. Forward-looking information is often, but not always, identified by the use of words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “guidance”, “may”, “will”, “should”, “could”, “estimate”, “predict” or similar words suggesting future outcomes or language suggesting an outlook. Forward-looking statements in this Annual Information Form include, but are not limited to, statements with respect to: benefits and synergies resulting from Pengrowth’s corporate and asset acquisitions, business strategy and strengths, goals, focus and the effects thereof, acquisition criteria, capital expenditures, reserves, reserve life indices, estimated production, production additions from Pengrowth’s 2008 development program, remaining producing reserves lives, operating expenses, royalty rates, net present values of future net revenue from reserves, commodity prices and costs, exchange rates, the impact of contracts for commodities, development plans and programs, tax horizon, future income taxes, taxability of distributions, the impact of proposed changes to Canadian tax legislation or U.S. tax legislation, abandonment and reclamation costs, government royalty rates (including estimated increase in royalties paid and estimated decline in net present value of reserves and 2009 cash flows) and expiring acreage. Statements relating to “reserves” are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

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

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth’s ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax and royalty laws; the failure to qualify as a mutual fund trust; and Pengrowth’s ability to access external sources of debt and equity capital. Further information regarding these factors may be found under the heading“Risk Factors”in this Annual Information Form, under the heading“Business Risks”in our Management’s Discussion and Analysis for the year ended December 31, 2007, and in Pengrowth’s most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases.

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

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PENGROWTH ENERGY TRUST

Introduction

The Trust is an energy investment trust that was created under the laws of the Province of Alberta on December 2, 1988. The purpose of the Trust is to pay distributions to our unitholders and to purchase and hold Royalty Units and other securities issued by the Corporation, its majority-owned subsidiary, as well as other investments and to issue Trust Units to members of the public. The Corporation directly and indirectly acquires, owns and manages working interests and royalty interests in oil and natural gas properties. The Trust and the Corporation are managed by the Manager.

The Trust

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

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

The Corporation

The Corporation was created under the laws of the Province of Alberta on December 30, 1987. The name of the Corporation was changed from “Pengrowth Gas Corporation” to “Pengrowth Corporation” in 1998. The Corporation has 1,100 common shares presently outstanding, 1,000 of which are owned by the Trust and 100 of which are owned by the Manager.

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

The authorized capital of the Corporation includes exchangeable shares. There are presently no exchangeable shares outstanding. See “Exchangeable Shares” in this Annual Information Form.

The Trust’s Subsidiaries

In addition to its interest in the Corporation, the Trust owns all of the issued and outstanding shares of Esprit Exploration Ltd. The Trust receives interest on the principal amount of Esprit Exploration Ltd.’s unsecured, subordinated promissory notes and payments from the net profits interest of Esprit Exploration Ltd. held by the Trust. The Corporation entered into an agency agreement dated October 2, 2006 with Esprit Energy Trust, Esprit Exploration Ltd. and all of its subsidiaries whereby the Corporation would provide certain services to Esprit Energy Trust, Esprit Exploration Ltd. and all of its subsidiaries. Services generally include, but are not limited to, the provision of all operating, financial, strategic, legal, regulatory, human resource, technology, record keeping, record management and general and administrative services.

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

The Corporation’s Subsidiaries

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

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

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

The Manager

The Manager was created under the laws of the Province of Alberta on December 16, 1982. The principal business of the Manager is that of a specialty fund manager. The Manager currently provides advisory, management, and administrative services to the Trust and the Corporation. The Manager also attends to the acquisition, development, operation and disposition of oil and natural gas properties and other related assets on behalf of the Corporation.

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

Intercorporate Relationships

The following diagram illustrates the organizational structure of Pengrowth as at the date hereof:

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Business Strategy and Strengths

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

Our ability to pay out distributions, while enhancing Unitholder value over time, is dependent upon our ability to make acquisitions that yield returns that exceed our cost of capital as well as effective operations and investments

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in our existing properties. We evaluate acquisition and development opportunities based upon the following acquisition criteria:

Acquisitions

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

• The undiscounted aggregate projected future net cash flow from the properties should exceed the aggregate purchase price of the properties and provide a reasonable rate of return.

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

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

o relatively low operating costs or high netbacks;

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

o favourable production history;

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

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

o low environmental and site remediation risk.

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

Development

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

o rate of return;

o timing of production;

o potential for continued development; and

o those investments necessary to maintain existing facilities and wells.

Our structure, ability to access capital and cost of capital allow us to bid competitively for oil and natural gas properties. However, our cost of capital has been significantly increased by the announcement of the SIFT Legislation. For a discussion of the consequences of the SIFT Legislation, see “Certain Canadian Federal

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Income Tax Considerations”and “Risk Factors – SIFT Legislation is expected to materially and adversely affect the Trust, the Unitholders and the value of the Trust Units”.

Opportunities to acquire oil and gas properties generally arise from sellers looking to reduce indebtedness, seeking funds for higher risk exploration and development activities, exiting the business, or fulfilling other strategic objectives.

SIFT Legislation Considerations

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

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

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

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

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GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST

Recent Developments

2008 Forecast Capital, Production and Operating Costs

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

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

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

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

Notes:

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

Asset Rationalization Program

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

At-the-Market Equity Distribution Program

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

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

Changes to Royalty Legislation Affecting Pengrowth and its Unitholders

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

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

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

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

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

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

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

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

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

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

Taxability of Distributions Paid to U.S. Residents

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

Senior Unsecured Notes

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

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

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

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U.S. DRIP

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

Changes to Tax Legislation Affecting Pengrowth and its Unitholders and Debentureholders

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

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

Greenhouse Gas Emissions

Greenhouse gas (“GHG”) emission limitations are expected to impact the oil and gas business, including Pengrowth. Provincial (Alberta) rules were released in 2007 with the Federal rules proposed to be released in 2008. The exact impact of the Federal rules is unknown at this time, but there may be a financial impact on Pengrowth in connection with its efforts to meet these emission reduction requirements. The Alberta system requires facilities that emit more than 100,000 tonnes of GHG’s per year to reduce their emission intensity by 12 percent over the 2005-2007 three year average. Pengrowth currently operates two facilities that exceed the 100,000 tonne limit. Under the Alberta regulations, if the emissions remain at current levels, Pengrowth is required to contribute approximately $500,000 to the fund annually.

Borrowing

On June 15, 2007, the Corporation entered into a new $1.2 billion extendible revolving term credit facility syndicated among eleven financial institutions (the “Credit Facility”). The Credit Facility is unsecured, covenant

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based and has a three-year term. The Corporation has the option to extend the Credit Facility each year, subject to the approval of the lenders, or repay the entire balance at the end of the three-year term. Various borrowing options are available under the Credit Facility, including prime rate based advances and bankers’ acceptance loans. The Credit Facility carries floating interest rates that are expected to range between 0.60  and 1.15 percent over bankers acceptance rates, depending on Pengrowth’s consolidated ratio of senior debt to earnings before interest, taxes and non-cash items. In addition, Pengrowth has a $35 million demand operating line of credit for working capital purposes. As at December 31, 2007, availability under the Credit Facility and the demand operating line of credit were reduced by drawings of $514 million and by outstanding letters of credit in the amount of approximately $11 million.

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

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

CP Acquisition

On January 22, 2007 Pengrowth closed the acquisition of entities that held certain properties from ConocoPhillips Canada for a purchase price of $1.0375 billion, prior to adjustments. See the business acquisition report of the Trust, dated March 16, 2007 and available on SEDAR at www.sedar.com.

The acquired properties provided Pengrowth with 64.7 MMboe of Total Proved Plus Probable Reserves at close (Pengrowth Company Interest based on GLJ forecast prices and costs) prior to Pengrowth’s asset rationalization program and were balanced evenly between natural gas and crude oil. The properties provide a wide range of opportunities to add value through active development including potential production from new horizons, infill drilling, continued optimization of existing waterflood programs and new enhanced oil recovery programs. The acquisition also provides synergies in several of Pengrowth’s focus areas including our Judy Creek and Swan Hills focus area. The acquisition added more than 375,000 net acres of undeveloped land and approximately 9,300 kilometres of proprietary 2-D seismic and interests in over 50 3-D seismic surveys.

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

The CP Acquisition was funded through Pengrowth’s December 8, 2006 equity offering of 24,265,000 Trust Units at a price of $19.00 per Trust Unit which yielded total gross proceeds of $461,035,000 and from the proceeds of a $600,000,000 bridge credit facility, which has since been repaid in full.

Historical Developments

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

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

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On September 28, 2006, Pengrowth completed the acquisition from ExxonMobil Canada Energy of all of the issued and outstanding shares of a company which had interests in oil and natural gas assets (the “Carson Creek Assets”) in the Carson Creek area of Alberta and the adjacent Carson Creek Gas Plant for $475 million, prior to adjustments. The Carson Creek Assets consisted of an 87.5 percent operated working interest in Carson Creek North Unit No. 1, a 95.1 percent operated working interest in both Carson Creek Unit No. 1 and the Carson Creek Gas Plant and a firm pipeline transportation contract. The acquisition provided the addition of approximately 19 MMboe of Total Proved Plus Probable Reserves and was funded by a portion of the proceeds from Pengrowth’s September 28, 2006 equity offering of 23,310,000 Trust Units at a price of $22.60 per Trust Unit which yielded total gross proceeds of $526,806,000.

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

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

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

On April 29, 2005, pursuant to a Plan of Arrangement under theBusiness Corporations Act(Alberta), Pengrowth completed the acquisition of Crispin Energy Inc., which held interests in oil and natural gas assets, including CBM assets, mainly in Alberta. Pengrowth issued 3,538,581 class B trust units and 686,732 class A trust units valued at $88 million in exchange for all outstanding shares of Crispin Energy Inc.

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

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

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

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On July 27, 2004, in response to proposed changes in federal income tax legislation that would have impacted Pengrowth’s status as a mutual fund trust, Pengrowth implemented a reclassification of its Trust Units whereby the existing outstanding Trust Units were reclassified into class B trust units and the class B trust units held by non-residents of Canada were converted into class A trust units (with the exception of Trust Units held by holders who did not provide a residency declaration to Computershare which remained unchanged pending receipt of a suitable residency declaration).

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

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

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

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

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

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

Effective June 15, 2001, the Corporation acquired a royalty representing substantially all of the beneficial interest in the natural gas and liquids production from an 8.4 percent working interest in the Sable Offshore Energy Project from Nova Scotia Resources (Ventures) Limited (“NSRVL”) for $265 million (net adjusted price of $228.4 million). On December 24, 2001, the Corporation acquired certain additional petroleum and natural gas rights and other assets from NSRVL for a gross purchase price of $27.5 million. On May 7, 2003, the Corporation acquired an 8.4 percent working interest in the four Sable production facilities downstream of Thebaud Central Platform from Sable co-venturers ExxonMobil Canada Properties, Shell Canada Resources Limited, Imperial Oil Resources Ltd. and Mosbacher Operating Company Ltd. for net consideration of approximately $57 million. In May 2003, Pengrowth entered into an agreement with Nova Scotia Resources Limited (“NSRL”) to purchase varying interests in eleven significant discovery licenses for $4.5 million plus a ten percent net profit interest to NSRL. In December 2003, Pengrowth acquired from Emera Offshore Incorporated (and its subsidiaries, associates and affiliates on a consolidated basis) their 8.4 percent working interest in the Sable offshore production platforms facilities for $65 million. As a result of the foregoing transactions, the Corporation holds an undivided 8.4 percent working interest in Sable Offshore Energy Project.

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

On November 10, 2000, the Trust issued 8,165,000 Trust Units to raise gross proceeds of $155.1 million, which were applied to acquire interests in Goose River, House Mountain, Minnehik Buck Lake, Mitsue and Weyburn

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from Canadian Natural Resources Limited for cash consideration of $128 million and the transfer of certain properties.

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

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

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

Pengrowth’s first acquisition, in December of 1988, was the purchase of a 2.6507 percent working interest in Dunvegan Gas Unit No. 1 located near Fairview in the Peace River Arch area of Alberta. Pengrowth financed the acquisition by issuing 1,250,000 Royalty Units at a price of $10.00 per Royalty Unit, substantially all of which were issued to the Trust. The Trust issued 1,243,500 Trust Units to the public at a price of $10.00 per Trust Unit for gross proceeds of $12.4 million which were used to pay for the Royalty Units. An additional 56,500 Royalty Units were also issued in the public offering, all of which are now held by the Trust.

Trends

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

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

Increases or decreases in the Canadian dollar relative to the U.S. dollar also result in decreases or increases, respectively, in cash flow as the main markets for Pengrowth’s oil and gas are either directly priced in U.S. dollars or based on pricing linked to U.S. dollars. Also, Pengrowth’s operating expenses and capital costs are currently primarily paid in Canadian dollars, reducing or increasing margins as the Canadian dollar fluctuates against the U.S. dollar.

For additional information regarding the Trust’s strategy in this business environment, see "Management’s Discussion and Analysis – Outlook” in the Trust’s Annual Report for the year ended December 31, 2007.

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PENGROWTH MANAGEMENT LIMITED

Business

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

Management Agreement

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

Key elements of the Management Agreement are:

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

• a base fee determined on a sliding scale:

o in the first three year contract term:

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

o in the second three year contract term:

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

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

• a performance based fee based on total returns received by Unitholders which essentially compensates the Manager for total annual returns which average in excess of eight percent per annum over a three year period;

• 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;

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• requirement for the Manager to pay certain expenses of the Corporation and the Trust of approximately $2 million per year;

• an annual minimum management fee of $3.6 million comprised of $1.6 million of management fees and $2.0 million of expenses;

• key man provisions in respect of James S. Kinnear, the President of the Manager;

• an annual bonus pool based on 10 percent of the Manager’s base fee and performance fee for employees of, and special consultants to, the Corporation; and

• an optional buyout of the Management Agreement at the election of the Board of Directors upon the expiry of the first three year contract term with a termination payment of approximately 2/3 of the management fee paid during the first three year contract term plus expenses of termination.

The responsibilities of the Manager under the Management Agreement include:

• reviewing and negotiating acquisitions for the Corporation and the Trust;

• providing written reports to the Board of Directors to keep the Corporation fully informed about the acquisition, exploration, development, operation and disposition of properties, the marketing of petroleum substances, risk management practices and forecasts as to market conditions;

• supervising the Corporation in connection with it acting as operator of certain of its properties;

• arranging for, and negotiating on behalf of, and in the name of, the Corporation all contracts with third parties for the proper management and operation of the properties of the Corporation;

• supervising, training and providing leadership to the employees and consultants of the Corporation and assisting in recruitment of key employees of the Corporation;

• arranging for professional services for the Corporation and the Trust;

• arranging for borrowings by the Corporation and equity issuances by the Trust; and

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

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

Bonus Pool

The Manager has established an annual bonus plan as an incentive to the officers, employees and special consultants of the Manager and the Corporation (excluding the President, James S. Kinnear). The annual bonus plan is carved out from the management fee paid to the Manager, and is calculated as 10 percent of the total fees,

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including the management fee and the performance fee, received by the Manager. Bonuses are paid from time to time to top performing individuals in accordance with criteria recommended by the Manager.

Management Agreement Second Term

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

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

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

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

• The estimated cost of internal management, until June 30, 2009, in the event of a termination of the Management Agreement;

• The estimated maximum management fees that would be payable to the Manager over the final three years of the term of the Management Agreement;

• The advice of its financial advisor;

• The management fee ceiling applicable during the final three years of the Management Agreement, which will result in lower management fees in the second term of the Management Agreement ending June 30, 2009 as compared to the first term of the Management Agreement ended June 30, 2006; and

• The commitment by the Manager to certain key governance standards relating to the conduct of the affairs of the Trust and a continuing commitment to overall corporate governance practices (as such practices would apply to Pengrowth in an internalized management structure); and a further commitment to assist and work with the Board in establishing a plan for the orderly transition to a traditional corporate management structure at the end of the final term of the Management Agreement on June 30, 2009.

Based on the recommendation of the Independent Committee, the Board of Directors determined in March of 2006 not to terminate the Management Agreement at the end of the first term and has therefore resolved to continue the Management Agreement in accordance with its terms for a second three year term until its expiry on June 30, 2009. A special committee of the Board of Directors, comprised of all independent members of the Board, was formed for the purpose of advising the Board in connection with all matters pertaining to the orderly transition to a traditional corporate management structure at the end of the term.

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PENGROWTH – OPERATIONAL INFORMATION

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

Principle Properties

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

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

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

							P+P
							Value
					Reserve		Before Tax
	P+P		Remaining		Life		at 10%		2007 Oil		2007 Gas		2007 NGL		2007 Total
	Reserves(3)		Reserve Life		Index		Discount		Production		Production		Production		Production
Field	(Mboe)		(years)		(years)		($MM)		(bblpd)		(MMcfd)		(bblpd)		(boepd)(3)
Light Oil
Judy Creek		40,447		50		13.3		797.9		7,359		4.1		1,529		9,564
Weyburn		21,966		44		21.1		345.0		2,779		—		—		2,779
Swan Hills		17,593		50		20.1		255.1		1,968		1.5		280		2,505
Carson Creek		15,194		34		11.9		311.6		2,031		3.8		505		3,169
Fenn Big Valley		5,998		28		8.8		104.5		632		6.1		54		1,703
Deer Mountain		5,264		45		19.7		101.4		543		0.1		60		618
Other(2)		35,143				9.8		883.8		8,908		9.8		708		11,256
Sub-Total		141,605				13.1		2,799.3		24,220		25.4		3,136		31,594
Heavy Oil
Jenner		7,728		23		7.2		155.1		2,890		1.5		4		3,144
Bodo		7,658		41		12.6		107.9		1,439		2.5		—		1,862
Tangleflags		5,321		25		7.3		56.2		1,910		0.2		—		1,951
Other(2)		5,060				8.6		61.9		970		5.6		—		1,902
Sub-Total		25,767				8.6		381.1		7,209		9.9		4		8,859
Conventional Gas
Olds		26,615		48		16.4		293.1		12		25.0		769		4,952
Harmattan		10,857		36		7.9		178.8		346		10.3		932		2,993
Dunvegan		6,204		40		10.4		85.0		35		8.1		444		1,835
Quirk Creek		5,134		38		10.5		77.9		—		3.6		214		820
Kaybob		4,078		38		13.7		45.6		—		4.2		37		736
McLeod River		3,688		41		7.1		61.1		7		6.4		250		1,316
Blackstone		3,588		24		10.3		49.4		—		6.1		—		1,025
Carson Creek		2,958		39		5.2		50.6		—		6.2		397		1,430
Other(2)		18,788				7.3		309.1		523		43.7		1,332		9,137
Sub-Total		81,910				9.7		1,150.6		923		113.7		4,375		24,242
Shallow Gas
Three Hills/Twining		13,704		50		10.2		218.2		537		17.7		447		3,939
Coal Bed Methane		9,312		41		11.3		123.9		1		6.2		6		1,032
Monogram		8,044		32		8.9		127.0		—		12.1		—		2,015
Jenner		7,435		33		9.4		90.7		4		11.5		2		1,922
Lethbridge		3,685		50		7.6		51.2		—		7.2		—		1,193
Other(2)		16,728				10.0		247.5		600		30.2		18		5,713

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							P+P
							Value
					Reserve		Before Tax
	P+P		Remaining		Life		at 10%		2007 Oil		2007 Gas		2007 NGL		2007 Total
	Reserves(3)		Reserve Life		Index		Discount		Production		Production		Production		Production
Field	(Mboe)		(years)		(years)		($MM)		(bblpd)		(MMcfd)		(bblpd)		(boepd)(3)
Sub-Total		58,908				9.9		858.4		1,142		84.8		533		15,813
Offshore Gas
Sable Island		11,731		9		4.3		266.6		—		33.2		1,362		6,895
Sub-Total		11,731				4.3		266.6		—		33.2		1,362		6,895
Total		319,921				10.4		5,455.9		33,495		267.0		9,409		87,401

Notes:

(1) The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

(2) “Other” includes Pengrowth’s Working Interests and Royalty Interests in approximately 100 other properties.

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

Light Oil Properties

Judy Creek

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

     2007 Development Activity

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

     Carbon Dioxide (CO₂) Pilot

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

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     2008 Development Activity

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

Weyburn Unit

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

     2007 Development Activity

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

     2008 Development Activity

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

Swan Hills

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

     2007 Development Activity

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

     2008 Development Activity

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

Carson Creek – Light Oil

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

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

     2007 Development Activity

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

     2008 Development Activity

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

Fenn Big Valley

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

     2007 Development Activity

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

     2008 Development Activity

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

Deer Mountain Unit No. 1

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

     2007 Development Activity

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

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     2008 Development Activity

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

Heavy Oil Properties

Jenner – Heavy Oil

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

     2007 Development Activity

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

     2008 Development Activity

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

Bodo

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

     2007 Development Activity

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

     2008 Development Activity

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

Tangleflags

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

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The EOR project commenced operation in the late 1980’s and contains horizontal producing wells along with both vertical and horizontal steam injection wells. As steam is injected into the reservoir and oil and water is withdrawn, a steam chamber is created which expands vertically and laterally, heating the reservoir and allowing the oil to drain more easily to the horizontal producing wells located below the injection wells near the base of the reservoir. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 5.3 MMboe. The Remaining Reserve Life is 25 years and the Reserve Life Index is 7.3 years. Pengrowth’s Company Interest production for Tangleflags averaged 1,951 boepd in 2007.

     2007 Development Activity

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

     2008 Development Activity

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

Conventional Gas Properties

Olds

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

Pengrowth operates and owns 100 percent of the sour gas processing plant at Olds, which processes both Pengrowth’s production and third party volumes. Third party volumes represent approximately 30 percent of the total volumes processed.

     2007 Development Activity

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

     2008 Development Activity

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

Harmattan

The Harmattan gas field is located approximately 90 kilometres northwest of Calgary, Alberta. It is comprised of wells and pools in formations from the Cardium to the 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

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

     2007 Development Activity

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

     2008 Development Activity

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

Dunvegan Gas Unit No. 1

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

     2007 Development Activity

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

     2008 Development Activity

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

Quirk Creek

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

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     2007 Development Activity

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

     2008 Development Activity

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

Kaybob

The Kaybob Notikewin Unit No. 1 is located approximately 240 kilometres northwest of Edmonton, Alberta. Pengrowth holds a 98.88 percent working interest in the Unit. The Kaybob Notikewin Unit No. 1 produces natural gas and natural gas liquids from the Notikewin formation. Initial production from the Unit began in 1962. Remaining Company Interest Total Proved Plus Probable Reserves at December 31, 2007 are estimated to be 4.1 MMboe. The Remaining Reserve Life is 38 years and the Reserve Life Index is 13.7 years. Pengrowth’s Company Interest production for Kaybob averaged 736 boepd in 2007.

     2007 Development Activity

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

     2008 Development Activity

Pengrowth anticipates drilling three Kaybob Notikewin Unit wells in 2008.

McLeod River

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

     2007 Development Activity

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

     2008 Development Activity

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

Blackstone

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

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     2007 Development Activity

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

     2008 Development Activity

No activity is anticipated on the Blackstone property in 2008.

Carson Creek – Conventional Gas

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

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

     2007 Development Activity

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

     2008 Development Activity

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

Shallow Gas Properties

Twining/Three Hills Creek

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

     2007 Development Activity

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

     2008 Development Activity

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

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Coal Bed Methane (CBM)

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

     2007 Development Activity

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

     2008 Development Activity

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

Monogram Gas Unit

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

     2007 Development Activity

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

     2008 Development Activity

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

Jenner – Shallow Gas

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

     2007 Development Activity

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

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     2008 Development Activity

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

Lethbridge

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

     2007 Development Activity

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

     2008 Development Activity

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

Offshore Gas Properties

Sable Offshore Energy Project (SOEP)

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

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

     2007 Development Activity

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

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     2008 Development Activity

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

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Statement of Oil and Gas Reserves and Reserves Data

Disclosure of Reserves Data

The information in this section is based upon an evaluation by GLJ with an effective date of December 31, 2007 contained in the GLJ Report dated February 8, 2008, and was prepared in accordance with NI 51-101, with the exception of information relating to income tax and the after tax future net revenues associated with our reserves, which were determined by Pengrowth. The effective date of the information in this section is December 31, 2007 and the preparation date of the information is January 15, 2008. The information in this section summarizes the oil, liquids and natural gas reserves of Pengrowth and the net present values of future net revenue for these reserves using GLJ’s forecast prices and costs and constant prices and costs. Pengrowth engaged GLJ to provide an evaluation of Proved Reserves and Total Proved Plus Probable Reserves and no attempt was made to evaluate possible reserves. It is Pengrowth’s practice to obtain an engineering report evaluating all of its Proved Reserves and Probable Reserves as at December 31 of each year. All of Pengrowth’s reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia.

The following tables set forth certain information relating to the oil and natural gas reserves of Pengrowth and the present value of the estimated future net cash flow associated with such reserves as at December 31, 2007 contained in the GLJ Report dated February 8, 2008. These tables summarize the data contained in the GLJ Report, and, as a result, may contain slightly different numbers than the GLJ Report due to rounding. Columns may not add due to rounding.

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

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

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

The future net cash flow and present value of future net revenue after income taxes were determined by Pengrowth after taking into account the impact of the SIFT Legislation.

Our estimate of income tax in the foregoing analysis makes use of the following assumptions:

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

• Annual general and administration expenses at the current level;

• Interest expense at the current level;

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

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

• Distributions to Unitholders; and

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

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

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

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Reserves Data (Forecast Prices and Costs)

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

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

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

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

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

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

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

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

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

Future Net

Revenue

Capital

Before

Future net

Operating

Development

Abandonment

Income

Income

Revenue

Revenue

Royalties(1)

Costs

Costs

Costs(2)

Taxes

Tax

After Income

Reserves category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Taxes($MM)

Proved Reserves

15,750

2,600

4,898

566

214

7,473

1,189

6,284

Total Proved Plus Probable Reserves

21,467

3,584

6,391

819

240

10,433

2,336

8,097

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

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

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

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

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Reserves Data (Constant Prices and Costs)

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

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

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

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

- 40 -

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

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

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

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

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

Future Net

Capital

Future Net

Revenue

Operating

Development

Abandonment

Revenue Before

After Income

Revenue

Royalties(1)

Costs

Costs

Costs(2)

Income Taxes

Income Tax

Taxes

Reserves Category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Proved Reserves

15,186

2,526

4,131

526

164

7,839

1,435

6,404

Total Proved Plus Probable Reserves

20,154

3,402

5,175

758

170

10,649

2,422

8,227

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

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

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

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

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Pricing Assumptions

     Forecast Prices used in Estimates

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

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

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

     Constant Prices used in Estimates

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

Oil

Natural Gas

Natural Gas Liquids(1)

WTI

Edmonton

Cromer

LLB Crude

Cushing

Par Price

Medium

Oil at

AECO Gas

Pentanes

Exchange

Oklahoma

40o API

29.3o API

Hardisty

Price

Propane

Butane

Plus

Rate(2)

Year

($US/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/MMbtu)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

($US/Cdn)

December 31, 2007

95.92

93.39

74.26

53.74

6.63

59.77

74.71

94.24

1.012

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

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Reserves Reconciliation

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

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

	Light and Medium Oil									Heavy Oil									Natural Gas Liquids
																									Gross
							Gross									Gross									Proved
	Gross			Gross			Proved Plus			Gross			Gross			Proved Plus			Gross			Gross			Plus
	Proved			Probable			Probable			Proved			Probable			Probable			Proved			Probable			Probable
	(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)			(Mbbls)
December 31, 2006		84,648			27,467			112,115			14,236			4,090			18,326			22,400			6,682			29,082
Extensions		932			(141	)		791			30			10			40			496			(1	)		495
Infill Drilling		1,188			956			2,144			—			—			—			235			160			395
Improved Recovery		482			421			903			—			—			—			25			15			40
Technical Revisions		3,119			(1,421	)		1,698			742			(177	)		565			591			174			765
Discoveries		—			—			—			—			—			—			23			3			26
Acquisitions		14,256			4,893			19,149			5,939			1,542			7,481			2,828			629			3,457
Dispositions		(2,227	)		(993	)		(3,220	)		(1,432	)		(582	)		(2,014	)		(1,509	)		(478	)		(1,987	)
Economic Factors		—			—			—			—			—			—			—			—			—
Production		(9,582	)		—			(9,582	)		(2,616	)		—			(2,616	)		(3,411	)		—			(3,411	)
December 31, 2007		92,817			31,180			123,997			16,898			4,883			21,781			21,677			7,185			28,862

	Natural Gas									Coal Bed Methane									Total Oil Equivalent Basis(1)
																									Gross
							Gross									Gross									Proved
	Gross			Gross			Proved Plus			Gross			Gross			Proved Plus			Gross			Gross			Plus
	Proved			Probable			Probable			Proved			Probable			Probable			Proved			Probable			Probable
	(MMcf)			(MMcf)			(MMcf)			(MMcf)			(MMcf)			(MMcf)			(Mboe)			(Mboe)			(Mboe)
December 31, 2006		608,105			191,206			799,311			14,230			9,427			23,657			225,007			71,677			296,684
Extensions		16,729			5,195			21,924			14,055			4,883			18,938			6,588			1,548			8,136
Infill Drilling		11,350			7,846			19,196			—						—			3,314			2,424			5,738
Improved Recovery		508			221			729			—			—			—			592			472			1,064
Technical Revisions		14,661			(19,175	)		(4,514	)		1,791			(1,543	)		248			7,193			(4,877	)		2,316
Discoveries		519			234			753			338			112			450			165			62			227
Acquisitions		155,961			36,584			192,545			8,434			4,235			12,669			50,422			13,867			64,289
Dispositions		(99,088	)		(28,236	)		(127,324	)		—			—			—			(21,682	)		(6,760	)		(28,442	)
Economic Factors		—			—			—			—			—			—			—			—			—
Production		(94,384	)		—			(94,384	)		(1,845	)		—			(1,845	)		(31,648	)		—			(31,648	)
December 31, 2007		614,363			193,874			808,237			37,002			17,115			54,117			239,953			78,413			318,366

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

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

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

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

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

Significant factors on the reserves reconciliation were as follows:

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

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

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

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

Additional Information Relating to Reserves Data

Undeveloped Reserves

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

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

- 45 -

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

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

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

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

Proved Undeveloped Reserves

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

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

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

- 46 -

Probable Undeveloped Reserves

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

Future Development Costs

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

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

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

Finding, Development and Acquisition Costs

Finding and Development Costs

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

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

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

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

Further development and optimization occurred in the Weyburn field in southeast Saskatchewan. A large infill drilling program was carried out in 2007 along with new pattern development in the CO₂miscible flood project area. A third recycle compressor was also installed and other facility maintenance and upgrades were carried out.

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

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

Acquisitions and Divestitures

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

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

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

Future Development Capital

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

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2007 Finding, Development and Acquisition Costs
Company Interest Reserves

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

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

Other Oil and Gas Information

Oil and Gas Wells

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

	Producing				Non-Producing
	Gross		Net		Gross		Net
Crude Oil Wells
Alberta		2,346		1,473		473		277
British Columbia		151		105		47		43
Saskatchewan		1,134		279		187		81
Nova Scotia		—		—		—		—
Natural Gas Wells
Alberta		5,515		2,827		571		322
British Columbia		124		77		25		27
Saskatchewan	��	51		48		87		47
Nova Scotia		19		1		—		—
Other(1)
Alberta		250		217		165		115
British Columbia		—		—		50		46
Saskatchewan		14		10		22		19
Total		9,604		5,038		1,627		976

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

Properties with No Attributed Reserves

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

Unproved Properties
as at December 31, 2007

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

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

Additional Information Concerning Abandonment & Reclamation Costs

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

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

The following tables summarize Pengrowth’s total asset retirement obligation:

Asset Retirement Obligations

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

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

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Costs Incurred

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

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

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

Exploration and Development Activities

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

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

Production Estimates

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

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

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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:

	Quarter Ended
	March 31,			June 30,			September 30,			December 31,
	2007			2007			2007			2007
Light Crude Oil
Average Daily Oil Production(1) (bblpd)		27,461			27,083			24,903			25,892
Sales Price (net of hedging gains/losses) ($/bbl)		67.24			71.81			75.10			73.69
Processing and other income ($/bbl)		0.39			0.42			0.90			0.69
Royalties ($/bbl)		(9.88	)		(11.90	)		(10.65	)		(13.86	)
Amortization of injectants ($/bbl)		(3.84	)		(3.51	)		(3.69	)		(3.14	)
Production Costs(2)($/bbl)		(13.31	)		(15.11	)		(16.93	)		(15.69	)
Operating Netback ($/bbl)		40.60			41.71			44.73			41.69
Heavy Oil
Average Daily Oil Production(1) (bblpd)		6,773			7,254			7,205			7,434
Sales Price (net of hedging gains/losses) ($/bbl)		41.54			43.52			47.30			45.47
Processing and other income ($/bbl)		0.18			0.18			0.50			0.19
Royalties ($/bbl)		(5.23	)		(5.33	)		(6.90	)		(5.91	)
Production Costs(2)($/bbl)		(13.15	)		(15.37	)		(9.43	)		(12.92	)
Operating Netback ($/bbl)		23.34			23.00			31.47			26.83
NGLs
Average Daily NGL Production(1) (bblpd)		9,918			8,519			9,883			9,319
Sales Price (net of hedging gains/losses) ($/bbl)		49.67			56.42			61.69			67.64
Royalties ($/bbl)		(14.05	)		(17.53	)		(18.82	)		(23.61	)
Production Costs(2)($/bbl)		(12.02	)		(13.57	)		(10.96	)		(14.29	)
Operating Netback ($/bbl)		23.60			25.32			31.91			29.74
Natural Gas
Average Daily Gas Production(1) (Mcfpd)		275,495			280,667			261,976			250,117
Sales Price (net of hedging gains/losses) ($/Mcf)		7.91			7.61			6.67			6.90
Processing and other income ($/Mcf)		0.15			0.16			0.19			0.18
Royalties ($/Mcf)		(1.67	)		(1.47	)		(0.92	)		(1.22	)
Production Costs(2)($/Mcf)		(2.10	)		(2.24	)		(1.58	)		(2.11	)
Operating Netback ($/Mcf)		4.29			4.06			4.36			3.75
Barrels of Oil Equivalent Basis(3)
Average Daily Production(1) (boepd)		90,068			89,633			85,654			84,331
Sales Price (net of hedging gains/losses) ($/boe)		53.30			54.39			53.34			54.58
Processing and other income ($/boe)		0.58			0.66			0.90			0.76
Royalties ($/boe)		(10.06	)		(10.30	)		(8.67	)		(11.01	)
Amortization of injectants ($/boe)		(1.17	)		(1.06	)		(1.07	)		(0.97	)
Production Costs(2) ($/boe)		(12.78	)		(14.13	)		(11.84	)		(13.80	)
Operating Netback ($/boe)		29.87			29.56			32.66			29.56

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

Replacement of Properties

In the event that Pengrowth determines that the sale of any of its interests in properties, and the release of the royalty would be in the best interest of the Unitholders, the Royalty Indenture permits it to make sales without the requirement of approval of the Unitholders, provided that the aggregate properties sold in any given year total less

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than 25 percent of the assets of Pengrowth, determined as at the date of disposition of the properties based upon an independent engineering appraisal. Any sale exceeding this threshold must be approved by an extraordinary resolution of the Unitholders.

Net Asset Value (NAV) at December 31, 2007

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

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

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

TRUST UNITS

The Trust Indenture

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

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

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(iii) making typographical or other non-substantive changes that are not adverse to the interests of Computershare and the Unitholders.

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

The Trustee

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

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

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

Stock Exchange Listings

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

Ownership Restrictions

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

Redemption Right

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

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the time the Trust Units or class A trust units are to be redeemed. The price of Trust Units and class A trust units, as applicable, for redemption purposes is based upon the closing trading price of the Trust Units irrespective of whether the units being redeemed are Trust Units or class A trust units.

Conversion Rights

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

Voting at Meetings of Unitholders

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

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

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

Voting at Meetings of Corporation

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

Termination of the Trust

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

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

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

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

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

Unitholder Limited Liability

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

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THE ROYALTY INDENTURE

Royalty Units

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

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

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

The Royalty

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

• operating costs and capital expenditures;

• general and administrative costs;

• management fees and debt service charges;

• taxes or other charges payable by the Corporation; and

• any amounts paid into the “reserve”.

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

The “reserve” is established by the Corporation with miscellaneous revenues (such as processing and transportation revenues) and allowable portions of gross revenue, and must be used to fund the payment of operating costs, capital expenditures, future abandonments, environmental and reclamation costs, general and administrative costs, royalty income, management fees and debt service charges. The allowable portions of gross revenue consist of (i) amounts determined by the Corporation in accordance with prudent business practices for the payment of future operating costs and reclamation obligations, and (ii) amounts, not to exceed 20% of gross revenue, determined by the Corporation in accordance with prudent business practices to provide for the payment of future capital expenditures or for the payment of royalty income in any future period or periods. Any amounts remaining in the reserve when there are no longer any properties that are subject to the royalty, and all of the above obligations have been satisfied, are to be paid to the holders of Royalty Units in proportion to their respective interests.

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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 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.

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

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

No exchangeable shares are currently issued or outstanding.

DISTRIBUTIONS

General

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

Historical Distributions

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

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

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

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

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

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

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

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

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

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

Restrictions on Distributions

The ability of the Trust to make cash distributions or return capital contributions to Unitholders may be directly or indirectly affected in certain events as a result of certain restrictions, including restrictions set forth in (i) the credit agreement relating to the Credit Facility; (ii) the note purchase agreements relating to the 2003 U.S. Senior Notes, the 2007 U.S. Senior Notes and the U.K. Senior Notes; and (iii) the Debentures. In particular, the funds required to satisfy the interest payable on the foregoing obligations, as well as the amounts payable upon the redemption or maturity of such obligations, as applicable, or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to Unitholders.

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Revolving Credit Facility

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

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

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

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

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

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

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

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Total Capitalization: The aggregate of Consolidated Total Debt and the Unitholders’ equity (calculated in accordance with GAAP as shown on the Trust’s consolidated balance sheet)

Senior Unsecured Notes

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

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

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

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

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

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

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

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

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Convertible Debentures

In connection with the business combination with Esprit Energy Trust, Pengrowth assumed all obligations relating to the Debentures then outstanding. As at December 31, 2007, Pengrowth had $74.7 million principal amount of Debentures outstanding. Each $1,000 principal amount of Debentures is convertible at the option of the holder at any time into Trust Units at a conversion price of $25.54 per Trust Unit. The Debentures mature on December 31, 2010. After December 31, 2008, Pengrowth may elect to redeem all or a portion of the outstanding Debentures at a price of $1,050 per Debenture or $1,025 per Debenture after December 31, 2009. On December 12, 2006 Pengrowth redeemed a portion of the Debentures, pursuant to the change of control provision, for cash proceeds of $21.8 million (including accrued interest of $0.6 million and offer premium of $0.2 million). See the discussion above under the heading “General Development of Pengrowth Energy Trust – Recent Developments – Changes to Tax Legislation Affecting Pengrowth and its Unitholders and its Debentureholders” for the recent changes to the Tax Act which eliminate Canadian withholding tax on interest paid or credited to non-residents.

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

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

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

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

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

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

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

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

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CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

Taxation of the Trust

SIFT Legislation

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

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

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

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

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

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tax reduction in the second quarter of 2007 to reflect temporary differences in the Trust. See note 11 to our audited annual consolidated financial statements for the year ended December 31, 2007.

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

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

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

Taxation of Unitholders Resident in Canada

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

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

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

Taxation of Unitholders who are Non-Residents of Canada

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

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

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

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

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

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

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

UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

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

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

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

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partner and the activities of the partnership. A United States person that is a partner of a partnership (or an entity taxable as a partnership for United States federal income tax purposes) holding our Trust Units should consult its own tax advisors.

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

Classification of Pengrowth Energy Trust as a Partnership

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

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

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

Possible Classification as a Corporation; PFIC Rules

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

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

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without regard to the price paid for Trust Units by subsequent United States holders) or (in the absence of earnings and profits) a nontaxable return of capital (to the extent of the United States holder’s tax basis in its Trust Units) or taxable capital gain (after the United States holder’s tax basis in the Trust Units is reduced to zero). If we were treated as a corporation, it is possible that we would be considered a PFIC, in which case special rules (discussed below), potentially quite adverse to United States holders, would apply.

Consequences of Possible PFIC Classification

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

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

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

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

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

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

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

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

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

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

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Tax Consequences of Trust Unit Ownership

Flow-through of Taxable Income

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

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

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

Treatment of Distributions

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

Basis of Trust Units

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

Limitations on Deductibility of Losses

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

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

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Limitations on Interest Deductions

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

Foreign Tax Credits

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

Functional Currency

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

Tax Treatment of Trust Operations

Accounting Method and Taxable Year

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

Depletion

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

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

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

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

Depreciation

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

Valuation of Our Properties

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

Section 754 Election

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

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

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Disposition of Trust Units

Recognition of Gain or Loss

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

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

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

Allocations between Transferors and Transferees

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

Notification Requirements

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

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

Constructive Termination

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

Treatment of Trust Unit Lending and Short Sales

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

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

Disposition of Trust Units by Redemption

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

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Uniformity of Trust Units

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

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

Tax-Exempt Organizations

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

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

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

Administrative Matters

Trust Information Returns

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

Registration as a Tax Shelter

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

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

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

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

Reportable Transactions

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

Foreign Partnership Reporting

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

INDUSTRY CONDITIONS

Government Regulation

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

Pricing and Marketing — Oil

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

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Pricing and Marketing — Natural Gas

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

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

Pricing and Marketing — Natural Gas Liquids

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

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

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

Alberta

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

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

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British Columbia

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

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

Saskatchewan

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

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

Nova Scotia

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

Environmental Regulation

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

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

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

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

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RISK FACTORS

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

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

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

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

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

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

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

• political conditions in the Middle East;

• worldwide economic conditions;

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

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

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• the level of consumer demand;

• the price and availability of alternative fuels;

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

• the effect of worldwide energy conservation measures; and

• government regulation.

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

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

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

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

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

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

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

• the assumed effect of government regulation;

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

• initial production rates;

• production decline rates;

• ultimate recovery of reserves;

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• marketability of production; and

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of the Corporation. If the oil and natural gas reserves associated with the Corporation’s resource properties are

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not supplemented through additional development or the acquisition of oil and natural gas properties, the ability of the Corporation to continue to generate cash flow for distribution to Unitholders may be adversely affected.

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

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

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

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

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

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

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

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

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

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cash flow, the charge to earnings could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.

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

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

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

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

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

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

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

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

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

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

The Trust is an Alberta trust and the Manager and the Corporation are both Alberta corporations. All of these entities have their principal places of business in Canada. All of the directors and officers of the Manager and the majority of the directors and officers of the Corporation are residents of Canada and all or a substantial portion of the assets of such persons and of the Trust are located outside of the United States. Consequently, it may be difficult for United States investors to effect service of process within the United States upon the Trust or such persons or to realize in the United States upon judgments of courts of the United States predicated upon civil remedies under the United StatesSecurities Act of 1933, as amended. Investors should not assume that Canadian courts:

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

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

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

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

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

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

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

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

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

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

We include in the documents incorporated herein by reference estimates of proved and proved plus probable reserves. The SEC generally prohibits the inclusion of estimates of probable reserves in filings made with it by

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United States oil and gas companies. This prohibition does not apply to the Trust because it is a Canadian foreign private issuer.

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

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

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

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

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

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

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

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

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• We have registered as a “tax shelter” with the United States Secretary of the Treasury because of the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which otherwise might be imposed if we failed to register and it were subsequently determined that registration was required. Registration as a “tax shelter” may increase the risk of an IRS audit of us or a Unitholder. Any Unitholder owning less than a 1 percent profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our Unitholders’ tax returns and may lead to audits of Unitholders’ tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.

• Because we cannot match transferors and transferees of Trust Units, we must maintain uniformity of the economic and tax characteristics of the Trust Units to a purchaser of these Trust Units. In the absence of such uniformity, the Trust may be unable to comply completely with a number of federal income tax requirements. A lack of uniformity, however, can result from a literal application of some Treasury regulations. If any non-uniformity was required by the IRS, it could have a negative impact on the value of the Trust Units.

• The Trust may not be an appropriate investment for certain types of entities. For example, there is a risk that some of the Trust’s income could be unrelated business taxable income with respect to tax-exempt organizations. Prospective purchasers of Trust Units that are tax-exempt organizations are encouraged to consult their tax advisors regarding investments in Trust Units.

• The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Trust Units may be modified by administrative, legislative or judicial interpretation at any time. For example, in response to certain recent developments, members of Congress are considering substantive changes to the existing U.S. tax laws that would affect certain publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Trust Units.

• We prorate our items of income, gain, loss and deduction between transferors and transferees of our Trust Units each month based upon the ownership of our Trust Units on the first day of each month, instead of on the basis of the date a particular Trust Unit is transferred. The use of the proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.

• On September 21, 2007, Canada and the United States signed the Protocol to the Canada-U.S. Convention. On December 14, 2007, Canada completed the steps required to give effect to the Protocol. The Protocol will come into force once it has been ratified by the United States, and the two countries have formally notified each other that their procedures are complete. The Protocol contains new Article IV(7)(b), a treaty benefit denial rule, which would increase the Canadian withholding tax on Pengrowth’s distributions (which for the purposes of this paragraph includes deemed dividends pursuant to the SIFT Legislation) to Non-Resident Unitholders who are residents of the U.S. for the purposes of the Canada-U.S. Convention. Article IV(7)(b) of the Protocol will not come into force until the first day of the third calendar year that ends after the Protocol is in force. Article IV(7)(b) of the Protocol generally denies benefits under the Canada-U.S. Convention in circumstances where (i) a Unitholder who is a resident of the U.S. for the purposes of the Canada-U.S. Convention receives an amount, such as a distribution, from an entity that is a resident of Canada, such as Pengrowth, (ii) Pengrowth is treated as a fiscally

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transparent entity for U.S. federal income tax purposes, which is the case inasmuch as Pengrowth is treated as a partnership for U.S. federal income tax purposes, and (iii) the tax treatment of the amount (or distribution) received by the U.S. Resident Unitholder would, for U.S. federal income tax purposes, be different if Pengrowth were not treated as fiscally transparent for U.S. federal income tax purposes. The effect of Article IV(7)(b) of the Protocol is that the Canadian withholding tax rate on distributions of income would be 25 percent instead of 15 percent or such lower rate otherwise available under the Canada-U.S. Convention. Returns of capital would still be subject to a 15 percent Canadian withholding tax and such rate is not modified by the Protocol. The Protocol also contains measures which, generally speaking, are designed to limit the benefits under the Canada-U.S. Convention to “treaty shopping” transactions or arrangements.

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

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

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

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

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

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

The Trust’s production, reserves and future net revenues associated therewith as disclosed herein do not reflect the increased royalties contemplated by the proposed new royalty regime and, after taking the new royalty regime into account, such values will be adversely affected. Based on the interpretations by GLJ of the proposed royalty changes and based on the January 2008 commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as compared to the current royalty structure. This increase is expected to result in a decline in the net present value, discounted at 10 percent, of the future net revenues associated with (i) Pengrowth’s Proved Reserves of three to five percent; and (ii) Pengrowth’s Total Proved Plus Probable Reserves of three to five percent.

Under the new royalty regime, it is anticipated that there will be a less than one-half of one percent decrease in Pengrowth’s Company Interest reserves and a one to three percent decrease in Pengrowth’s Net reserves, as compared to the current royalty structure. It is anticipated that the new royalty regime will result in a five to

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seven percent decline in Pengrowth’s cash flow for 2009, the first year in which the royalty changes take effect, as compared to the current royalty structure.

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

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

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

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

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

• restrictions imposed by lenders;

• accounting delays;

• delays in the sale or delivery of products;

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

• blowouts or other accidents;

• adjustments for prior periods;

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

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

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.

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The limited liability of Unitholders is uncertain.

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

The redemption right of Unitholders is limited.

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

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

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

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MARKET FOR SECURITIES

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

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

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

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

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DIRECTORS AND OFFICERS

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

Directors and Officers of the Manager

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

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

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

Principal Holders of Shares of the Manager

James S. Kinnear, President and a director of Pengrowth Management and Chairman, President, Chief Executive Officer and a director of the Corporation, owns, directly or indirectly, all of the issued and outstanding voting securities of Pengrowth Management.

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:

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				Trust Units
				Controlled or
Name and Jurisdiction	Position with			Beneficially
of Residence	Pengrowth Corporation		Principal Occupation	Owned(1)
James S. Kinnear	President, Chairman, Director and		President		5,996,238
Alberta, Canada	Chief Executive Office (since 1988)		Pengrowth Management Limited
Thomas A. Cumming(2)(4)(5)	Director (since 2000)		Business Consultant		8,678
Alberta, Canada
Wayne K. Foo(2)(3)	Director (since 2006)	��	President		3,843
Alberta, Canada			Petro Andina Resources Ind.
Kirby L. Hedrick(2)(5)	Director (since 2005)		Business Consultant		4,000
Wyoming, United States of America
Michael S. Parrett(3)(4)(5)	Director (since 2004)		Business Consultant		4,000
Ontario, Canada
A. Terence Poole(3)(5)	Director (since 2005)		Business Consultant		30,000
Alberta, Canada
D. Michael G. Stewart(2)(4)	Director (since 2006)		Principal of the Ballinacurra		13,370
Alberta, Canada			Group, Corporate Director
Nicholas C.H. Villiers	Director (since 2007)		Business Consultant	—
London, England
John B. Zaozirny(3)(4)	Director (since 1988)		Counsel, McCarthy Tétrault		35,100
Alberta, Canada			Barristers and Solicitors
Gordon M. Anderson	Vice President (since 2001)		Vice President, Financial	21,066
Alberta, Canada	Vice President, Treasurer (1997-2001)		Services Pengrowth Management
	Treasurer (1995-1997)		Limited
	Chief Financial Officer (1991-1998)
Douglas C. Bowles	Vice President and Controller		Vice President and Controller	11,446
Alberta, Canada	(since March 1, 2006)		Pengrowth Corporation
	Controller (since 2005)
James E.A. Causgrove	Vice President, Production and		Vice President, Production	23,621
Alberta, Canada	Operations (since 2005)		and Operations Pengrowth Corporation
Peter Cheung	Vice President (since 2008)		Vice President and Treasurer	17,428
Alberta, Canada	Treasurer (since 2005)		Pengrowth Corporation
William G. Christensen	Vice President, Strategic Planning and		Vice President, Strategic	15,821
Alberta, Canada	Reservoir Exploitation (since 2005)		Planning and Reservoir Exploitation Pengrowth Corporation
James M. Donihee	Vice-President and Chief of Staff		Vice-President and Chief of	7,086
Alberta, Canada	(since 2007)		Staff Pengrowth Corporation
Charles V. Selby	Vice President and Corporate Secretary		President	146,916
Alberta, Canada	(since 2005)		Selby Professional Corporation
	Corporate Secretary (since 1993)
Larry B. Strong	Vice President, Geosciences (since 2005)		Vice President, Geosciences	37,118
Alberta, Canada			Pengrowth Corporation
Christopher G. Webster	Chief Financial Officer (since 2005)		Chief Financial Officer	37,065
Alberta, Canada	Treasurer (2000 — 2005)		Pengrowth Corporation

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

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

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

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

Corporate Cease Trade Orders or Bankruptcies

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

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

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(iii) within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

Personal Bankruptcies

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

Penalties or Sanctions

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

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

AUDIT COMMITTEE

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

		Financially
Name	Independent	Literate	Relevant Education and Experience
Thomas A. Cumming	Yes	Yes	Mr. Cumming was President and Chief Executive Officer of the Alberta Stock Exchange from 1988 to 1999. His career also includes 25 years with a major Canadian bank both nationally and internationally. He is currently Chairman of Alberta’s Electricity Balancing Pool, and serves as a Director of the Alberta Capital Market Foundation. He is also a past president of the Calgary Chamber of Commerce. Mr. Cumming is a professional engineer and holds a Bachelor of Applied Science degree in Engineering and Business from the University of Toronto.
Michael S. Parrett	Yes	Yes	Mr. Parrett is currently an independent consultant providing advisory service to various companies in Canada and the United States. Mr. Parrett is Chairman of Gabriel Resources Limited, a member of the board of Fording Inc. and is serving as a Trustee for Fording Canadian Coal Trust. He was formerly President of Rio Algom Limited and prior to that Chief Financial Officer of Rio Algom and Falconbridge Limited. Mr. Parrett is a chartered accountant and holds a Bachelor of Arts in Economics from York University.
A. Terence Poole	Yes	Yes	Mr. Poole brings extensive senior financial management, accounting, capital and debt market experience to Pengrowth. He retired from Nova Chemicals Corporation in 2006 where he had held various senior management positions including Executive Vice-President, Corporate Strategy and Development. Mr. Poole currently serves on the board of directors for Methanex Corporation and Synenco Energy Inc. Mr. Poole received a Bachelor of Commerce degree from Dalhousie University and holds a Chartered Accountant designation.

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		Financially
Name	Independent	Literate	Relevant Education and Experience
Kirby L. Hedrick	Yes	Yes	Mr. Hedrick has extensive engineering and senior management experience in the United States and internationally, retiring in 2000 as Executive Vice-President, Upstream of Phillips Petroleum. He currently serves on the board of directors of Noble Energy Inc. and has recently been appointed to the Wyoming Environmental Quality Council. Mr. Hedrick received a Bachelor of Science and Mechanical Engineering degree from the University of Evansville, Indiana in 1975. He completed the Stanford Executive Program in 1997 and the Stanford Corporate Governance Program in 2003.

Principal Accountant Fees and Services

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

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

Audit Fees

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

Audit-Related Fees

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

Tax Fees

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

Pre-approval Policies and Procedures

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

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

CONFLICTS OF INTEREST

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

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

• the issuance of additional Trust Units;

• material acquisitions and dispositions of properties;

• material capital expenditures;

• borrowing; and

• the payment of distributable cash.

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

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

LEGAL PROCEEDINGS

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

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Other than as discussed herein, there are no material interests, direct or indirect, of directors, executive officers, senior officers, any direct or indirect Unitholder of Pengrowth who beneficially owns, or who exercises control

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over, more than 10 percent of the outstanding Trust Units or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or will materially affect Pengrowth.

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

INTERESTS OF EXPERTS

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

AUDITORS, TRANSFER AGENT AND REGISTRAR

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

MATERIAL CONTRACTS

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

1.	Trust Indenture;
2.	Royalty Indenture;
3.	Unanimous Shareholders Agreement;
4.	Management Agreement;
5.	the Fifth Amended and Restated Credit Agreement dated June 17, 2007 between Pengrowth and a syndicate of eleven financial institutions concerning the Credit Facility;
6.	the Bridge Credit Agreement dated January 22, 2007 between Pengrowth and a syndicate of ten financial institutions entered into in conjunction with the CP Acquisition;
7.	the Acquisition Agreement dated November 28, 2006 in connection with the CP Acquisition;
8.	the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes;
9	the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes;
10.	the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes;
11.	the Debenture Indenture;
12.	the first supplemental trust indenture relating to the Debentures dated October 2, 2006; and

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

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

OFF-BALANCE SHEET ARRANGEMENTS

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

DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE

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

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

There is only one significant way in which Pengrowth’s corporate governance practices differ from those required to be followed by domestic United States issuers under the NYSE Listed Company Manual. The NYSE Listed Company Manual requires shareholder approval of all equity compensation plans and any material revisions to such plans, regardless of whether the security is to be delivered under such plans are newly issued or purchased on the open market, subject to a few limited exceptions. In contrast, the TSX rules require shareholder approval of equity compensation plans only when such plans involve newly issued securities. If the plan provides a procedure for its amendment, the TSX rules require shareholder approval of amendments only where the amendment

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involves a reduction in the exercise price or an extension of the term of options held by insiders. As a matter or practice, Pengrowth has obtained the approval of its Unitholders to all of its equity compensation plans, regardless of whether the Trust Units to be delivered under such plans are newly issued or purchased on the open market with the exception of the Trust Unit Award Plan which was implemented as an employee retention mechanism in a very tight prevailing market in the Canadian oil and gas industry.

ADDITIONAL INFORMATION

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

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

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

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

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

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APPENDIX A

Report On Reserves Data By Independent

Qualified Reserves Evaluator On Form 51-101F2

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

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

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

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

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

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

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

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 8, 2008

(signed)“Doug R. Sutton”Doug R. Sutton, P.Eng.

Vice-President

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APPENDIX B

Report Of Management And Directors On

Oil And Gas Disclosure On Form 51-101F3

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

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

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

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

(a)	reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator;
(b)	met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and
(c)	reviewed the reserves data with management and the independent qualified reserves evaluator.

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

(a)	the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
(b)	the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and
(c)	the content and filing of this report.

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

(signed) “James S. Kinnear”James S. Kinnear

Chairman, President and Chief Executive Officer

Pengrowth Corporation

(signed) “William G. Christensen”William G. Christensen

Vice President, Strategic Planning and Reservoir Exploitation

Pengrowth Corporation

(signed) “Kirby L. Hedrick”Kirby L. Hedrick
Director

Pengrowth Corporation

(signed) “D. Michael G. Stewart”D. Michael G. Stewart

Director

Pengrowth Corporation

March 19, 2008

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APPENDIX C

Audit Committee Terms of Reference

TERMS OF REFERENCE
AUDIT COMMITTEE

PENGROWTH CORPORATION
PENGROWTH ENERGY TRUST

Objectives

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

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

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

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

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

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

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

Composition

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

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

Meetings and Minutes

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

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

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

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

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

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

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

Scope, Duties and Responsibilities

Mandatory Duties

Review Procedures

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

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

2.

Prior to filing or public distribution, review, discuss with management and the internal and external auditors and recommend to the Board for approval, Pengrowth’s audited annual financial statements, annual earnings press releases, annual information form, all statements including the related management’s discussion and analysis required in prospectuses and other offering memoranda, financial statements required by regulatory authorities, all prospectuses and all documents which may be incorporated by reference into a prospectus, including without limitation, the annual proxy circular. Approve, on behalf of the Board, Pengrowth’s interim financial statements and related management’s discussion and analysis and interim earnings press releases. This review should include discussions with management, the internal auditors and the external auditors of significant issues regarding accounting principles, practices and judgements. Discuss any significant changes to Pengrowth’s accounting principles and any items required to be communicated by the external auditors in accordance with Assurance and Related Services Guideline #11 (AUG-11).

3.

Ensure that adequate procedures are in place for the review of Pengrowth’s public disclosure of financial information extracted or derived from Pengrowth’s financial statements, other than the

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public disclosure referred to in paragraph 2 above and periodically assess the adequacy of those procedures.

4.

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

External Auditors

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

2. Approve the fees and other compensation to be paid to the external auditors.

3. Pre-approve all services to be provided to Pengrowth or its subsidiary entities by Pengrowth’s external auditors and all related terms of engagement.

Other Audit Committee Responsibilities

4. Establish procedures for: (i) the receipt, retention and treatment of complaints received by Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii) the confidential and anonymous submission by employees of Pengrowth of concerns regarding questionable accounting or auditing matters.

5. Review and approve Pengrowth’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of Pengrowth.

Discretionary Duties

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

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.

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3. Meet separately with each of management, the internal auditors and the external auditors to discuss difficulties or concerns, specifically: (i) any difficulties encountered in the course of the audit work, including any restrictions on the scope of activities or access to requested information, and any significant disagreements with management; (ii) any changes required in the planned scope of the audit; and (iii) the responsibilities, budget, and staffing of the internal audit function, and report to the Board on such meetings.

4. Conduct an annual performance evaluation of the Audit Committee.

Internal Auditors

1. Review the annual audit plans of the internal auditors.

2. Review the significant findings prepared by the internal auditors and recommendations issued by any external party relating to internal audit issues, together with management’s response.

3. Review the adequacy of the resources of the internal auditors to ensure the objectivity and independence of the internal audit function.

4. Consult with management on management’s appointment, replacement, reassignment or dismissal of the internal auditors.

5. Ensure that the internal auditors have access to the Lead Director, the Chair of the Board and the Chief Executive Officer.

External Auditors

1. On an annual basis, the Audit Committee should review and discuss with the external auditors all significant relationships they have with Pengrowth that could impair the auditors’ independence.

2. The Audit Committee shall review the external auditors audit plan – discuss scope, staffing, locations, and reliance upon management and general audit approach.

3. Consider the external auditors’ judgments about the quality and appropriateness of Pengrowth’s accounting principles as applied in its financial reporting.

4. Be responsible for the resolution of disagreements between management and the external auditors regarding financial performance.

5. Ensure compliance by the external auditors with the requirements set forth in National Instrument 52-108Auditor Oversight.

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

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

Other Audit Committee Responsibilities

1. On at least an annual basis, review with Pengrowth’s counsel any legal matters that could have a significant impact on the organization’s financial statements, Pengrowth’s compliance with applicable laws and regulations, and inquiries received from regulators or governmental agencies.

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2. Annually prepare a report to unitholders as required by the United States’ Securities and Exchange Commission; the report should be included in Pengrowth’s annual proxy statement.

3. Ensure the preparation and filing of each annual certificate in Form 52-109F1 and each interim certificate in Form 52-109F2 to be signed by each of the Chief Executive Officer and Chief Financial Officer of the Corporation in accordance with the requirements set forth under Multilateral Instrument 52-109Certification of Disclosure in Issuers’ Annual and Interim Filings, as amended from time to time (“MI 52-109”).

4. In respect of annual filings only, the Audit Committee is responsible for ensuring that management evaluates the effectiveness of Pengrowth’s disclosure controls and procedures as of the end of the period covered by the annual filings and has caused Pengrowth to disclose in the annual management’s discussion and analysis its conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by the annual filings based on such evaluation. The terms “annual filings,” “interim filings,” “disclosure controls and procedures” and “internal control over financial reporting” shall have the meanings set forth under MI 52-109.

5. Be responsible for monitoring any changes in Pengrowth’s internal control over financial reporting and for ensuring that any change that occurred during Pengrowth’s most recent interim period that has materially affected, or is reasonably likely to materially affect, Pengrowth’s internal control over financial reporting is disclosed in Pengrowth’s most recent annual or interim management’s discussion and analysis.

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

7. Perform any other activities consistent with this Charter, the Trust Indenture, the Corporation’s by-laws, and other governing law as the Audit Committee or the Board deems necessary or appropriate.

8. Maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities.

Communication,Authority to Engage Advisors and Expenses

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

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

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

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

A-1

Schedule “A”

Excerpt from Multilateral Instrument 52-110

Standard of “Independence”

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

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

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

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

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

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

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

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

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

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

A-2

compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service.

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

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

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

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

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

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

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

(a)

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

(b)

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

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

Standard of “Financial Literacy”

An individual is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by Pengrowth’s financial statements.

B-1

Schedule “B”

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

Standard of “Independence"

b.	Required standards.
1.	Independence.

i.

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

ii.

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

A.

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

B.

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

e.	Definitions. Unless the context otherwise requires, all terms used in this section have the same meaning as in the Act. In addition, unless the context otherwise requires, the following definitions apply for purposes of this section:
1.

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

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

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

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

B-2

iii. The following will be deemed to be affiliates:

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

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

4.

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

8.

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

C-1

Schedule “C”

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

303A.02 “Independence” Tests

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

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

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

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

An “immediate family member” includes a person’s spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than domestic employees) who shares such person’s home. When applying the look-back provisions in Section 303A.02(b), listed companies 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 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 2007 ANNUAL REPORT — Management’s Discussion and Analysis 53

MANAGEMENT’S DISCUSSION & ANALYSIS

SUMMARY OF FINANCIAL RESULTS

(thousands,	Three Months ended December 31									Twelve Months ended December 31
except per unit amounts)	2007			2006			% Change			2007			2006			% Change
INCOME STATEMENT
Oil and gas sales	$	425,249		$	350,908			21		$	1,722,038		$	1,214,093			42
Net income	$	(3,665	)	$	3,310			(211	)	$	359,652		$	262,303			37
Net income per trust unit	$	(0.01	)	$	0.01			(200	)	$	1.47		$	1.49			(1	)
CASH FLOW
Cash flows from operating activities	$	196,325		$	91,237			115		$	800,344		$	554,368			44
Cash flows from operating activities per trust unit	$	0.80		$	0.41			95		$	3.26		$	3.15			3
Distributions declared	$	166,631		$	185,651			(10	)	$	706,601		$	559,063			26
Distributions declared per trust unit	$	0.675		$	0.75			(10	)	$	2.875		$	3.00			(4	)
Ratio of distributions declared over cash flows from operating activities		85	%		203	%					88	%		101	%
Capital expenditures	$	95,743		$	121,781			(21	)	$	309,708		$	300,809			3
Capital expenditures per trust unit	$	0.39		$	0.55			(29	)	$	1.26		$	1.71			(26	)
BALANCE SHEET
Working capital(1)										$	(189,603	)	$	(160,949	)		18
Property, plant and equipment										$	4,306,682		$	3,741,602			15
Long term debt										$	1,203,236		$	604,200			99
Trust unitholders’ equity										$	2,756,220		$	3,049,677			(10	)
Trust unitholders’ equity per trust unit										$	11.17		$	12.50			(11	)
Currency (U.S.$/Cdn$) (closing rate at period end)											1.0088			0.8581
Weighted average number of trust units outstanding		246,513			220,734			12			245,470			175,871			40
Number of trust units outstanding at period end											246,846			244,017			1

⁽¹⁾ Prior year restated to conform to presentation adopted in current year

54 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

SUMMARY OF OPERATING RESULTS

	Three Months ended December 31									Twelve Months ended December 31
	2007			2006			% Change			2007			2006			% Change
AVERAGE DAILY PRODUCTION
Crude oil (barrels)		25,892			25,000			4			26,327			21,821			21
Heavy oil (barrels)		7,434			4,695			58			7,168			4,964			44
Natural gas (mcf)		250,117			234,050			7			266,980			175,578			52
Natural gas liquids (barrels)		9,319			8,910			5			9,409			6,774			39
Total production (boe)		84,331			77,614			9			87,401			62,821			39
TOTAL PRODUCTION (mboe)		7,758			7,141			9			31,901			22,930			39
PRODUCTION PROFILE
Crude oil		31	%		32	%					30	%		35	%
Heavy oil		9	%		6	%					8	%		8	%
Natural gas		49	%		50	%					51	%		46	%
Natural gas liquids		11	%		12	%					11	%		11	%
AVERAGE REALIZED PRICES (after commodity risk management)
Crude oil (per barrel)	$	73.69		$	60.35			22		$	71.88		$	66.85			8
Heavy oil (per barrel)	$	45.47		$	37.61			21		$	44.53		$	42.26			5
Natural gas (per mcf)	$	6.90		$	7.12			(3	)	$	7.29		$	7.22			1
Natural gas liquids (per barrel)	$	67.64		$	52.69			28		$	58.86		$	57.11			3
Average realized price per boe	$	54.58		$	49.24			11		$	53.90		$	52.88			2
PROVED PLUS PROBABLE RESERVES
Crude oil (mbbls)											124,188			112,388			10
Heavy oil (mbbls)											21,792			18,336			19
Natural gas (bcf)											870			827			5
Natural gas liquids (mbbls)											28,994			29,142			(1	)
Total oil equivalent (mboe)											319,921			297,774			7
SUMMARY OF TRUST UNIT TRADING
NYSE — PGH ($U.S.)
High	$	19.21		$	20.25					$	19.85		$	25.15
Low	$	17.30		$	14.78					$	15.82		$	14.78
Close	$	17.77		$	17.21					$	17.77		$	17.21
TSX — PGF.UN ($Cdn)(1)
High	$	18.68		$	22.69					$	21.04		$	26.11
Low	$	17.00		$	16.81					$	16.92		$	16.81
Close	$	17.62		$	19.94					$	17.62		$	19.94

⁽¹⁾ July 27, 2006, Pengrowth’s Class A trust units and Class B trust units were consolidated into a single class of trust units (with the exception of Class A trust units held by residents of Canada who provided an election), the Class A trust units were delisted from the Toronto Stock Exchange and the Class B trust units were renamed as Trust units and their trading symbol changed to PGF.UN

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 55

MANAGEMENT’S DISCUSSION & 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, 2007 of Pengrowth Energy Trust and is based on information available to March 3, 2008.

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, 2008 production, production additions from Pengrowth’s 2008 development program, royalty obligations, 2008 operating expenses, future income taxes, goodwill, asset retirement obligations, taxability of distributions, remediation and abandonment expenses, capital expenditures, general and administration expenses, proceeds from the disposal of properties and the impact of the changes to the Canadian tax legislation as details have yet to be provided. 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.

56 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

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 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, whether as a result of new information, future events or otherwise, except as required by law. 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 year ended.

The amounts recorded for depletion, depreciation and amortization of injectants, the provision for asset retirement obligations, 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.

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.

Historically, we used non-GAAP measures such as funds generated from operations, funds generated from operations per trust unit, distributable cash, distributable cash per trust unit and payout ratio because we believe they facilitate the understanding of the results of our operations and financial position. In response to guidance from the Canadian Institute of Chartered Accountants (CICA) and the Canadian Securities Administrators (CSA), we are now using the GAAP measure cash flow from operating activities instead of funds generated from operations. The principal difference is that cash flow from operating activities includes changes in non-cash working capital. We have discontinued the use of distributable cash and distributable cash per trust unit.

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 can also be determined when it is compared to the difference in cash provided by operating activities and distributions paid in the financing section of the Statement of Cash Flows.

CONVERSION AND CURRENCY

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 method primarily applicable at the burner tip 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. All amounts are stated in Canadian dollars unless otherwise specified.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 57

MANAGEMENT’S DISCUSSION & ANALYSIS

2007 OVERVIEW

Pengrowth generated cash flow from operating activities of $800.3 million in 2007, a 44 percent increase from the prior year’s cash flow of $554.4 million. The increase is mainly attributable to higher production volumes from the ConocoPhillips (CP properties) acquisition completed at the beginning of 2007 and a full year’s production from the Carson Creek and Esprit Trust acquisitions which closed in the third and fourth quarter of 2006, respectively. Higher realized crude oil prices and favorable results from Pengrowth’s risk management program for natural gas have also contributed to the increase in cash flow from operating activities in 2007. Partially offsetting the above were the unfavourable impact on production volumes from non-core property dispositions, increased operating costs, and general and administrative expenses mainly due to the recent acquisitions, higher interest costs and losses on crude oil risk management activities.

In accordance with Canadian GAAP, Pengrowth includes certain non-cash items in the financial statements which significantly impact the calculation of net income. The recognition of these non-cash items can cause net income to vary from period to period. Pengrowth reported a net loss of $3.7 million in the fourth quarter of 2007 compared to net income of $161.5 million in the third quarter of 2007 and $3.3 million of net income in the fourth quarter 2006. A lower operating netback and an unrealized mark-to-market loss on commodity risk management contracts of $136.6 million, partially offset by a future tax reduction of $89.2 million were the main reasons for the reduction in net income from the third quarter of 2007. The decrease is also partly attributable to Pengrowth recording a lower unrealized foreign exchange gain of $5.7 million on its foreign denominated debt in the fourth quarter compared to a $40.8 million unrealized foreign exchange gain in the third quarter of 2007.

On a year-over-year basis, net income increased by 37 percent in 2007 to $359.7 million compared to $262.3 million in 2006. This increase is primarily due to higher production volumes, higher operating netbacks in 2007, recognizing a future income tax reduction and an unrealized foreign exchange gain on foreign denominated debt, partially offset by significant unrealized losses on risk management contracts ($130.4 million) and an increase in depreciation expense.

The strengthening Canadian dollar relative to the U.S. dollar has offset some of the effects of rising crude oil prices, which are typically quoted in U.S. dollars. Although the price of crude oil in U.S. dollars has increased nine percent in 2007 compared to 2006, using the West Texas Intermediate benchmark price as a basis, the Canadian dollar equivalent has only increased three percent. As a result, Pengrowth’s average realized crude oil price

58 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

did not fully reflect the impact of record high benchmark crude oil prices in 2007. Pengrowth’s commodity risk management activities have mitigated some of the effects of the strengthening Canadian dollar by fixing the Canadian dollar exchange rate on crude oil commodity contracts.

The strengthening Canadian dollar had a favourable impact on financial results related to Pengrowth’s foreign denominated debt in 2007. During the year, Pengrowth recognized unrealized foreign exchange gains of $57.8 million (2006 — $0.5 million unrealized foreign exchange loss) and $16.1 million (2006 — nil) on the U.S. dollar term debt and the U.K. Pound Sterling term debt respectively.

HIGHLIGHTS

• Oil and gas sales increased 42 percent to $1.7 billion dollars in 2007 due to higher production volumes and higher average realized prices. In the fourth quarter, oil and gas sales were $425 million, an increase of one percent from the third quarter and 21 percent from the same quarter in 2006.

• Production for 2007 averaged 87,401 barrels of oil equivalent (boe) per day, a 39 percent increase over 2006. The increase is primarily due to a full year of production from the Esprit and Carson Creek acquisitions, and production from the CP properties after the January 22, 2007 closing. Fourth quarter production averaged 84,331 boe per day, virtually unchanged from the third quarter and an increase of nine percent from the fourth quarter in 2006. The higher production levels compared to the prior year reflect the CP properties acquisition and development activities, partially offset by natural production declines and divestment activities.

• Cash flows from operating activities in 2007 increased from the prior year by 44 percent to $800.3 million reflecting the higher production and sales prices. Fourth quarter cash flows from operating activities was $196.3 million, representing a decrease of 10 percent from the third quarter and an increase of 115 percent from the fourth quarter in 2006. The decrease from the third quarter is mainly as a result of higher operating, royalty, administrative and interest costs incurred. The 115 percent increase in the fourth quarter of 2007 from the fourth quarter in 2006 is primarily due to higher production volumes, higher realized prices and the unfavourable impact on working capital in the prior year.

• Distributions declared to unitholders reached an all time high of $706.6 million, an increase of 26 percent when compared to $559.1 million in 2006. For the full year in 2007, distribution declared totaled $2.875 per trust unit. Distributions declared to unitholders totaled 88 percent of its cash flows from operating activities and 85 percent in the fourth quarter.

• During 2007, Pengrowth closed a U.S. $400 million offering of notes issued on a private placement basis at an interest rate of 6.35 percent due in 2017.

• Net income increased 37 percent to $359.7 million for 2007 compared to 2006. The increase was due to higher oil and gas sales, partly offset by higher royalties, operating expenses and general and administrative costs. In addition to the above cash items, net income was significantly effected by certain non-cash items including a $296.6 million increase in depletion, depreciation and accretion expenses, and $122.3 million of unrealized commodity risk management losses, offset by $264.6 million future tax recovery recorded in 2007 due to the enactment of the previously announced tax on income trusts, asset dispositions during the second half of 2007 and a reduction in the federal income tax rate.

• During 2007, Pengrowth’s average realized price was $53.90 per boe (after commodity risk management) compared to an average price of $52.88 per boe in 2006. Prices for liquids were higher year over year while there was a decrease in natural gas prices. For the fourth quarter, average realized prices were $54.58 per boe (after commodity risk management) up two percent from the third quarter and 11 percent from the same quarter last year. These increases largely reflect a higher commodity price environment for oil and natural gas liquids (NGLs) while natural gas has remained relatively stable in the fourth quarter of 2007.

• Operating netbacks (after commodity risk management) increased three percent in 2007 to $30.40 per boe, largely driven by higher realized prices partially offset by higher operating costs. For the fourth quarter, operating netbacks were $29.56 per boe down from the previous quarter by nine percent and an increase of 22 percent from the fourth quarter of 2006. The fourth quarter netbacks were lower than the third quarter largely due to higher operating costs and royalties.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 59

MANAGEMENT’S DISCUSSION & ANALYSIS

• Pengrowth’s development capital, excluding acquisitions, in 2007 totaled $283 million, resulting in a finding and development cost of $17.44 per boe, including future development costs. Including acquisitions, Pengrowth replaced 169 percent of its production on a proved plus probable basis at a cost of $18.97 per boe, including future development costs. During the year, Pengrowth participated in 511 gross (175 net) wells with a 97 percent success rate.

• Pengrowth completed asset sales for proceeds of $476 million ($459 million net of adjustments) in 2007. The assets disposed were non-core assets identified following the acquisitions of the CP properties and Esprit Trust.

RESULTS OF OPERATIONS

PRODUCTION

Average daily production increased 39 percent to 87,401 boe per day in 2007, compared to 2006. The increase is primarily due to the CP properties acquisition and the inclusion of 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 contributions from ongoing development activities, partially offset by dispositions of non-core properties. The fourth quarter of 2007 saw a slight decrease from the third quarter of 2007 due primarily to operational outages at the Quirk Creek Gas Plant that affected natural gas production.

At this time, Pengrowth anticipates 2008 full year production of 80,000 to 82,000 boe per day. This estimate excludes the impact from any potential future acquisitions or dispositions.

	Three months ended						Twelve months ended
	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Light crude oil (bbls per day)		25,892		24,903		25,000		26,327		21,821
Heavy oil (bbls per day)		7,434		7,205		4,695		7,168		4,964
Natural gas (mcf per day)		250,117		261,976		234,050		266,980		175,578
Natural gas liquids (bbls per day)		9,319		9,883		8,910		9,409		6,774
Total (boe per day)		84,331		85,654		77,614		87,401		62,821

Light crude oil production volumes increased 21 percent year-over-year mainly as a result of a full year’s production from the Esprit Trust and Carson Creek acquisitions and nearly a full year from the CP properties. Total additional production from the acquisitions added approximately 7,000 bbls per day, which was partially offset by divestments and natural declines. The fourth quarter of 2007 was four percent higher than the third quarter of 2007 due to increased light crude sales from Judy Creek and Swan Hills.

Heavy oil production increased 44 percent year-over-year and 58 percent in the fourth quarter of 2007 in comparison to the same period of 2006. The addition of approximately 2,900 bbls per day for the full year from the Jenner property acquired as part of the CP properties acquisition were partially offset by production declines and property divestments.

Natural gas production increased 52 percent year-over-year. Additional volumes from acquisitions, development activities, in particular new production from coalbed methane wells and a compression project completed at the Sable Offshore Energy Project (SOEP), combined to offset decreases due to non-core property divestments and natural declines. The five percent decrease in production in the fourth quarter compared to the third quarter of 2007 was due to plant outages at the Quirk Creek Gas Plant as well as operational outages at SOEP for subsea maintenance work; the decrease was partially offset by higher gas sales at Judy Creek and new wells on production in Cactus Lake. Fourth quarter production increased seven percent compared to the same time period of 2006 due to additional volumes from the CP properties and the SOEP compression project, partially offset by natural production decline and operational outages experienced in the fourth quarter of 2007.

NGLs production increased 39 percent year-over-year primarily due to acquisitions partially offset by natural production declines. Fourth quarter production decreased slightly due to one less condensate shipment at SOEP as compared to the third quarter 2007. The five percent increase in production compared to the fourth quarter of 2006, is mainly due to acquisitions, higher sales at Judy Creek due to less solvent demand partially offset by one less condensate shipment at SOEP and natural declines.

60 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

PRICING AND COMMODITY RISK MANAGEMENT

Compared to the previous year, higher U.S. dollar benchmark prices for crude oil and liquids were offset by lower natural gas market prices and the strengthening of the Canadian (Cdn) dollar.

As part of our financial management strategy, Pengrowth uses forward price swap 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. Thus, in conjunction with the CP properties acquisition, Pengrowth increased the volume of commodity price risk management contracts. As of December 31, 2007, Pengrowth has contracts for 2008 and 2009 for approximately 17,300 bbls per day and 6,000 bbls per day of crude oil and 95,000 mcf per day and 49,000 mcf per day of natural gas, respectively. Each Cdn $1 per barrel change in future oil prices would result in approximately Cdn $8.5 million 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 $26.3 million change in the value of the natural gas contracts. The potential changes in the value of the contracts would directly affect net income through the unrealized amounts booked to the statement of income during the period. The effect on cash flows will be recognized separately upon realization of the contracts, which could vary significantly from the unrealized amount recorded due to timing and prices when the contract is settled. Pengrowth has hedged the Canadian dollar exchange rate at the same time that it hedges any U.S. dollar denominated commodity in order to protect against changes in the foreign exchange rate.

In prior periods, hedge accounting was followed for commodity risk management contracts entered into prior to May 2006 and therefore recording of these contracts at fair value was not required by GAAP. Pengrowth has not designated any outstanding commodity contracts as hedges for accounting purposes and therefore must record 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 fluctuates, 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.

AVERAGE REALIZED PRICES

	Three months ended						Twelve months ended
	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Light crude oil (per bbl)		82.31		76.87		60.94		72.93		68.83
after realized commodity risk management		73.69		75.10		60.35		71.88		66.85
Heavy oil (per bbl)		45.47		47.30		37.61		44.53		42.26
Natural gas (per mcf)		6.20		5.54		6.82		6.71		7.08
after realized commodity risk management		6.90		6.67		7.12		7.29		7.22
Natural gas liquids (per bbl)		67.64		61.69		52.69		58.86		57.11
Total per boe		55.16		50.40		48.52		52.46		53.18
after realized commodity risk management		54.58		53.34		49.24		53.90		52.88
BENCHMARK PRICES
WTI oil (U.S.$  per bbl)		90.71		75.25		60.17		72.12		66.25
AECO spot gas (Cdn$  per gj)		5.69		5.32		6.36		6.27		6.70
NYMEX gas (U.S.$  per mmbtu)		6.97		6.16		6.56		6.86		7.24
Currency (U.S. $/Cdn$)		1.02		0.96		0.88		0.93		0.88

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 61

MANAGEMENT’S DISCUSSION & ANALYSIS

REALIZED COMMODITY RISK MANAGEMENT GAINS (LOSSES)

	Three months ended									Twelve months ended
	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Light crude oil ($ millions)		(20.5	)		(4.1	)		(1.4	)		(10.1	)		(15.8	)
Light crude oil ($  per bbl)		(8.62	)		(1.77	)		(0.59	)		(1.05	)		(1.98	)
Natural gas ($ millions)		16.0			27.2			6.5			56.1			8.8
Natural gas ($  per mcf)		0.70			1.13			0.30			0.58			0.14
Combined ($ millions)		(4.5	)		23.1			5.1			46.0			(7.0	)
Combined ($  per boe)		(0.58	)		2.94			0.72			1.44			(0.30	)

Commodity price contracts in place at December 31, 2007 are detailed in Note 19 to the consolidated financial statements. Additionally, the fair value of the outstanding contracts has been recorded on the balance sheet as a net liability of $85.2 million at year-end. An unrealized loss of $122.3 million resulting from the change in fair value from January 1 to December 31, 2007 has been recognized in the statement of income compared to an unrealized gain of $26.5 million in the prior year.

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	2007		total		2007		total		2006			total		2007		total		2006		total
Light crude oil		175.6		41		172.0		41		138.8			40		690.8		40		532.4		44
Natural gas		158.8		37		160.8		38		153.3			44		710.1		41		462.4		38
Natural gas liquids		57.9		14		56.1		13		43.2			12		202.1		12		141.2		12
Heavy oil		31.1		8		31.4		8		16.3			4		116.5		7		76.6		6
Brokered sales/sulphur		1.8		—		0.4		—		(0.7	)		—		2.5		—		1.5		—
Total oil and gas sales		425.2				420.7				350.9					1,722.0				1,214.1

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			NGL		Heavy oil		Other		Total
Year ended December 31, 2006		532.4		462.4			141.2		76.6		1.5		1,214.1
Effect of change in product prices		39.4		(36.1	)		6.0		5.9		—		15.2
Effect of change in sales volumes		113.2		236.2			54.9		34.0		—		438.3
Effect of change in realized commodity risk management activities		5.7		47.3			—		—		—		53.0
Other		0.1		0.3			—		—		1.0		1.4
Year ended December 31, 2007		690.8		710.1			202.1		116.5		2.5		1,722.0

62 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

PROCESSING AND OTHER INCOME

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Processing & other income		4.1		6.8		6.2		20.6		18.8
$  per boe		0.53		0.85		0.86		0.64		0.82

Processing and other income is primarily derived from fees charged for processing and gathering third party gas, road use and oil and water processing.

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

ROYALTIES

	Three months ended									Twelve months ended
($ millions)	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Royalty expense		85.4			68.3			73.1			319.3			241.5
$  per boe		11.01			8.67			10.23			10.01			10.53
Royalties as a percent of sales		20.0	%		16.2	%		20.8	%		18.5	%		19.9	%

Royalties include Crown, freehold and overriding royalties as well as mineral taxes. The royalty rate for 2007 is lower than 2006 primarily from the inclusion of the CP properties which have a lower average royalty rate. Fourth quarter 2007 royalty expense was higher compared to the third quarter as favourable adjustments in the third quarter which included a $3.7 million refund for the overpayment of royalties at SOEP based on the finalization of the 2006 annual royalty return and a one time credit of $1.6 million for reducing sulphur emissions at Judy Creek were not repeated.

The outlook for 2008 is for royalties to be approximately 20 percent of Pengrowth’s sales. The Alberta Government unveiled proposed changes to the methodology it uses to calculate royalties that if passed would become effective in 2009. At this time, based on the January 2008 price assumptions of GLJ Petroleum consultants, Pengrowth anticipates that the royalty rate would increase to between 22 and 24 percent.

OPERATING EXPENSES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Operating expenses		103.8		89.6		99.7		406.5		270.5
$  per boe		13.38		11.38		13.97		12.74		11.80

Operating expenses increased 16 percent from the third quarter of 2007 or 18 percent on a per boe basis. The increase is primarily due to higher maintenance activity at Red Earth, Jenner and Goose River ($5 million), and finalizing Harmattan joint venture billings with the operator ($5 million). Expenses for the fourth quarter of 2007 compared to the same period of 2006 increased $4 million, or a decrease of four percent on a per boe basis. The additional operating expenses related to the CP properties ($26 million) were offset by lower utility and maintenance costs ($13 million) as well as the absence of costs relating to divested properties. In comparing year-over-year, operating expenses increased 50 percent or $136 million, which was an eight percent increase on a per boe basis. Primarily the increase is due to the addition of the CP properties ($84 million) and full year inclusion of Esprit Trust ($39 million) and Carson Creek ($15 million). In addition, increased operations personnel, higher maintenance at Weyburn and a planned maintenance shutdown at the Quirk Creek Gas Plant in June 2007 were partly offset by lower utility costs at Judy Creek, Tangleflags and Nipisi. Operating expenses include costs incurred to earn processing and other income which are reported separately.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 63

MANAGEMENT’S DISCUSSION & ANALYSIS

Operating costs are expected to decrease slightly for the full year 2008; however per unit operating costs are estimated to increase to approximately $13.20 per boe, a four percent increase from full year 2007. The expected increase in per unit costs results from the relatively high percentage of fixed costs combined with the lower estimated production levels. In addition, operating costs at our light oil properties tend to be higher which are somewhat offset by higher netbacks and a longer reserve life.

NET OPERATING EXPENSES

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Net operating expenses		99.7		82.8		93.5		385.9		251.7
$  per boe		12.85		10.53		13.11		12.10		10.98

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

TRANSPORTATION COSTS

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Light oil transportation		1.2		1.2		0.5		3.5		2.0
$  per bbl		0.49		0.49		0.21		0.37		0.25
Natural gas transportation		2.1		2.5		1.8		9.1		5.6
$  per mcf		0.09		0.10		0.09		0.09		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. Oil transportation costs increased year-over-year due to the additional transportation incurred related to the CP properties; which Pengrowth began marketing in June 2007. 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, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Purchased and capitalized		8.1		7.4		9.4		26.1		34.6
Amortization		7.5		8.5		9.3		34.1		34.6

The cost of injectants (primarily natural gas and ethane) purchased for injection in miscible flood programs is amortized equally over the period of expected future economic benefit. The cost of injectants purchased in 2006 and 2007 is amortized over a 24 month period. As of December 31, 2007, the balance of unamortized injectant costs was $27.3 million.

The amount purchased and capitalized was lower year-over-year due to timing of the program. It is expected that the program will require additional injectants in upcoming quarters and therefore higher amounts will be purchased as shown by the increase in the fourth quarter 2007 over third quarter 2007. 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.

64 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

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 natural gas liquids production.

Pengrowth recorded an average operating netback of $29.56 per boe in the fourth quarter of 2007 compared to $32.66 per boe in the third quarter of 2007 and $24.17 per boe for the fourth quarter of 2006. The decrease in the netback in the fourth quarter compared to the third quarter of 2007 was a result of an increase in royalties and operating costs. The increase over the fourth quarter of 2006 is mainly due to higher liquids realizations partially offset by royalties. The increase from year-over-year is a result of higher combined commodity prices and lower royalties which were partially offset by higher operating costs.

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

	Three months ended									Twelve months ended
Combined Netbacks ($ per boe)	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Sales price		54.58			53.34			49.24			53.90			52.88
Other production income		0.23			0.05			(0.09	)		0.08			0.06
		54.81			53.39			49.15			53.98			52.94
Processing and other income		0.53			0.85			0.86			0.64			0.82
Royalties		(11.01	)		(8.67	)		(10.23	)		(10.01	)		(10.53	)
Operating expenses		(13.38	)		(11.38	)		(13.97	)		(12.74	)		(11.80	)
Transportation costs		(0.42	)		(0.46	)		(0.33	)		(0.40	)		(0.33	)
Amortization of injectants		(0.97	)		(1.07	)		(1.31	)		(1.07	)		(1.51	)
Operating netback		29.56			32.66			24.17			30.40			29.59

	Three months ended									Twelve months ended
Light Crude Netbacks ($ per bbl)	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Sales price		73.69			75.10			60.35			71.88			66.85
Other production income		0.36			0.13			(0.31	)		0.15			0.13
		74.05			75.23			60.04			72.03			66.98
Processing and other income		0.33			0.77			0.64			0.44			0.58
Royalties		(13.86	)		(10.65	)		(11.65	)		(11.57	)		(10.63	)
Operating expenses		(15.20	)		(16.44	)		(17.95	)		(14.85	)		(13.78	)
Transportation costs		(0.49	)		(0.49	)		(0.21	)		(0.37	)		(0.25	)
Amortization of injectants		(3.14	)		(3.69	)		(4.08	)		(3.54	)		(4.35	)
Operating netback		41.69			44.73			26.79			42.14			38.55

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 65

MANAGEMENT’S DISCUSSION & ANALYSIS

	Three months ended									Twelve months ended
Heavy Oil Netbacks ($ per bbl)	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Sales price		45.47			47.30			37.61			44.53			42.26
Processing and other income		0.19			0.50			0.80			0.27			0.43
Royalties		(5.91	)		(6.90	)		(5.44	)		(5.86	)		(4.53	)
Operating expenses		(12.92	)		(9.43	)		(14.06	)		(12.71	)		(15.16	)
Operating netback		26.83			31.47			18.91			26.23			23.00

	Three months ended									Twelve months ended
Natural Gas Netbacks ($ per mcf)	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Sales price		6.90			6.67			7.12			7.29			7.22
Other production income		0.04			—			—			0.01			0.01
		6.94			6.67			7.12			7.30			7.23
Processing and other income		0.14			0.19			0.20			0.16			0.21
Royalties		(1.22	)		(0.92	)		(1.41	)		(1.33	)		(1.54	)
Operating expenses		(2.02	)		(1.48	)		(1.90	)		(1.92	)		(1.65	)
Transportation costs		(0.09	)		(0.10	)		(0.09	)		(0.09	)		(0.09	)
Operating netback		3.75			4.36			3.92			4.12			4.16

	Three months ended									Twelve months ended
NGLs Netbacks ($ per bbl)	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Sales price		67.64			61.69			52.69			58.86			57.11
Royalties		(23.61	)		(18.82	)		(16.61	)		(18.49	)		(20.17	)
Operating expenses		(14.29	)		(10.96	)		(14.00	)		(12.65	)		(11.12	)
Operating netback		29.74			31.91			22.08			27.72			25.82

INTEREST

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Interest Expense		19.7		19.6		12.8		84.3		32.1

Interest expense remained stable in the fourth quarter compared to the third quarter of 2007. Year-over-year interest expense has more than doubled reflecting a higher average debt level resulting from the CP properties and Esprit Trust acquisitions combined with higher interest rates and standby fees. Interest of $13.9 million on bank indebtedness was incurred on a $600 million credit facility that Pengrowth fully repaid on July 13, 2007. Approximately half of Pengrowth’s outstanding long term debt as at December 31, 2007 incurs interest that is payable in U.S. dollars and therefore the amount of interest payable is subject to fluctuations in the U.S. dollar exchange rate.

66 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

GENERAL AND ADMINISTRATIVE (G&A)

	Three months ended							Twelve months ended
($ millions)	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006			Dec 31, 2007		Dec 31, 2006
Cash G&A expense		12.4		8.3		11.7			50.5		34.1
$  per boe		1.60		1.05		1.63			1.58		1.49
Non-cash G&A expense		1.8		0.4		(0.3	)		5.4		2.5
$  per boe		0.22		0.05		(0.04	)		0.17		0.11
Total G&A		14.2		8.7		11.4			55.9		36.6
Total G&A ($  per boe)		1.82		1.10		1.59			1.75		1.60

The cash component of G&A for the fourth quarter of 2007 compared to the third quarter of 2007 increased $4.1 million. This increase is primarily due to higher professional fees ($1.0 million), year-end reserves report ($0.8 million) and $1.0 million for the estimated reimbursement of G&A expenses incurred by the Manager, pursuant to the management agreement. Cash G&A increased $16.4 million year-over-year due to additional salaries and benefits associated with recent acquisitions ($8.3 million), the CP transition services fee ($3.0 million), legal fees associated with ongoing litigation ($1.8 million), professional fees associated with tax matters ($0.9 million), higher rent ($1.8 million) and other professional fees.

The non-cash component of G&A represents the compensation expense associated with Pengrowth’s long term incentive programs including trust unit rights and deferred entitlement units. The increase in the non-cash G&A in the fourth quarter compared to the third quarter of 2007 is due to higher Long Term Incentive Program (LTIP) expenses resulting from an improvement in the performance multiplier. The increase year-over-year is due to the higher expense resulting from granting additional trust units under the LTIP as a result of the increased number of employees from recent acquisitions.

General and administrative (G&A) expenses per boe are expected to remain stable in 2008 when compared to 2007. On a per boe basis, G&A is anticipated to be approximately $1.80 per boe for full year 2008, which includes non-cash G&A.

MANAGEMENT FEES

	Three months ended								Twelve months ended
($ millions)	Dec 31, 2007			Sept 30, 2007		Dec 31, 2006			Dec 31, 2007		Dec 31, 2006
Management Fee		(2.2	)		2.8		(0.7	)		6.8		9.9
$  per boe		(0.28	)		0.36		(0.09	)		0.21		0.43

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.

Management fees are lower in both the fourth quarter of 2007 and full year 2007 compared to the same periods in 2006 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 2007, the performance fee was significantly reduced due to lower trust unit prices which were partially a result of the government of Canada’s announcement of a new tax on specified investment flow-through (SIFT) trusts.

Management fees are expected to be approximately $0.40 per boe in 2008.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 67

MANAGEMENT’S DISCUSSION & ANALYSIS

RELATED PARTY TRANSACTIONS

Details of related party transactions undertaken in 2007 and 2006 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 2007 also include $1.1 million (2006 — $1.0 million) paid to a law 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 has been granted trust unit rights and deferred entitlement units from time to time, the cost of which are not included in the legal fees.

On January 12, 2006, Pengrowth divested non-core oil and gas properties for consideration of $22 million of cash, prior to adjustments, and approximately eight million shares in Monterey Exploration Ltd., a private oil and gas company. Pengrowth holds approximately 32 percent of the outstanding common shares of Monterey. Currently, a senior officer of the Corporation is a member of the Board of Directors of Monterey. In December 2007, two senior officers of the Corporation directly and indirectly purchased a total of 230,000 shares (2006 — 30,000 shares) of Monterey for a total consideration of $805,000 (2006 — $150,000) in a new share offering marketed by an independent investment dealer. At December 31, 2007, two senior officers of the Corporation directly and indirectly hold 260,000 shares of Monterey.

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 other corporate purposes. In the event cash withholdings increased 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.

The CP properties acquisition resulted in Pengrowth recording an additional future tax liability of $305.1 million, representing the difference between the tax basis and the fair value assigned to the acquired assets.

Bill C-52 Budget Implementation Act 2007

On October 31, 2006, the federal Minister of Finance (Finance) announced legislative tax proposals which modify the taxation of certain flow-through entities including mutual fund trusts referred to as “specific investment flow-through” entities or “SIFTS” and the taxation of distributions from such entities (the “October 31 Proposals”). The October 31 Proposals apply 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. The October 31 Proposals became law when Bill C-52 received Royal Assent on June 22, 2007 (the SIFT Legislation).

Pengrowth believes that it is characterized as a SIFT trust and, as a result, is subject to the SIFT Legislation. The SIFT Legislation is to commence January 1, 2007 for all SIFT trusts that begin to be publicly traded after October 31, 2006 and commencing January 1, 2011 for all SIFT trusts that were publicly traded on or before October 31, 2006. Subject to the qualification below regarding the possible loss of the four year grandfathering period in the case of “undue expansion”, it is expected that Pengrowth will not be subject to the SIFT Legislation until January 1, 2011.

Pursuant to the SIFT Legislation, commencing January 1, 2011, Pengrowth will not be able to deduct certain of its distributed income (referred to as specified income). Pengrowth will become subject to a distribution tax on this specified income. Based on information released by Finance (including the federal economic update on December 30, 2007), the proposed tax rate in 2011 will be 29.5 percent which is comprised on 16.5 percent federal tax and 13 percent tax rate on account of provincial tax. The federal component of the proposed tax on SIFTs is expected to be 15 percent in 2012 (28 percent total) and thereafter. The payment of this tax will reduce the amount of cash available for distribution to unitholders.

68 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

Under the previous provisions of the Tax Act, the Trust could 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, the Trust was generally not liable for any material amount of tax.

Pengrowth may lose the benefit of the four year grandfathering period 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 as follows: 40 percent for the period November 1, 2006 to December 31, 2007, 20 percent for each of 2008, 2009 and 2010. Unused portions may be carried forward until December 31, 2010. Pengrowth has issued additional equity after October 31, 2006 of approximately $517 million including the issuance of 21,100,000 trust units on December 8, 2006 for proceeds of $461 million. This will constitute a portion of the 40 percent normal growth limit for the period ending on December 31, 2007. Accordingly, Pengrowth may currently issue approximately $1.4 billion of additional equity without offending the normal growth guidelines and may issue an additional $960 million for each of 2008, 2009 and 2010.

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 $2.9 billion, which will be considered in identifying the alternatives and timing of our response to the enactment of the SIFT Legislation.

Pengrowth is actively investigating a number of alternative structures and solutions that may mitigate the impact of the SIFT Legislation.

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 2007, Pengrowth recorded a future tax reduction of $89.2 million due to asset dispositions and reduction in enacted rates. Since the October 31 Proposals have received Royal Assent, the tax legislation is considered enacted for accounting purposes. As a result of the enactment of the SIFT tax, the Trust recorded a future income tax reduction of $71 million in the second quarter of 2007 to reflect temporary differences in the Trust.

Other non-recurring items contributing to the reduction in future income taxes in 2007 include the asset disposition program ($68.7 million) and tax rate reductions ($39.6 million).

FOREIGN CURRENCY GAINS AND LOSSES

Pengrowth recorded a $61.9 million net foreign exchange gain in 2007, compared to an immaterial loss in 2006. Included in the gain is a $57.8 million unrealized foreign exchange gain related to the translation of the U.S. dollar denominated debt and a $16.1 million 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.

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 had a negative impact on 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).

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 69

MANAGEMENT’S DISCUSSION & ANALYSIS

DEPLETION, DEPRECIATION AND ACCRETION

	Three months ended						Twelve months ended
($ millions)	Dec 31, 2007		Sept 30, 2007		Dec 31, 2006		Dec 31, 2007		Dec 31, 2006
Depletion and depreciation		156.0		157.5		129.2		639.1		351.6
$  per boe		20.11		19.99		18.09		20.03		15.33
Accretion		6.5		6.2		4.9		25.7		16.6
$  per boe		0.84		0.79		0.68		0.81		0.72

Depletion and depreciation of property, plant and equipment is calculated on the unit of production method based on total proved reserves. The increase in 2007 rates for depletion, depreciation and accretion is due to the inclusion of the property, plant and equipment from the CP properties, Carson Creek and Esprit Trust acquisitions, over the applicable periods.

Pengrowth’s Asset Retirement Obligations liability increased due to 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. When required the cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. There was a significant surplus in the ceiling test at year-end 2007.

ASSET RETIREMENT OBLIGATIONS

The total future Asset Retirement Obligations (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 $352 million as at December 31, 2007 (December 31, 2006 — $255 million), based on a total escalated future liability of $2,015 million (December 31, 2006 — $1,530 million). These costs are expected to be incurred over 50 years with the majority of the costs incurred between 2035 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 2007, Pengrowth contributed $7.4 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 $18.1 million at December 31, 2007.

In 2007 an evaluation was completed on the Judy Creek properties. Pengrowth is currently in discussions with the former owner to determine if the future funding levels for the fund should be maintained or reduced. 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.

70 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

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 2007, Pengrowth spent $11.4 million on abandonment and reclamation (2006 — $9.1 million). Pengrowth expects to spend approximately $18 million for 2008, 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 credits or by contributing to the Climate Change and Emissions Management Fund. Pengrowth currently operates two facilities that collectively exceed the limit by approximately 89,000 tonnes. We are assessing our options and focusing on projects that reduce our greenhouse gas emission footprint. Under the Alberta regulations, if the emissions remain at the current levels, Pengrowth would experience an increase of approximately $0.5 million in annual costs.

In 2007, the Federal Government announced a 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

On a year-over-year basis, other expenses decreased $7.4 million primarily due to the absence of legal fees and the costs associated with the consolidation of Class A and Class B trust units completed in 2006.

GOODWILL

As at December 31, 2007, Pengrowth recorded goodwill of $660.6 million, an increase of $62.3 million from December 31, 2006. In accordance with GAAP, Pengrowth recorded goodwill of $62.3 million on the acquisition of the CP properties. The goodwill value was determined based on the excess of total consideration paid less the net value assigned to other identifiable assets and liabilities, including future income tax liability. 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, 2007.

CAPITAL EXPENDITURES

During 2007, Pengrowth spent $283.1 million on development and optimization activities. The largest expenditures were at Judy Creek ($35.0 million), Twining ($17.8 million), Swan Hills ($17.7 million), Carson Creek ($12.4 million), Weyburn ($11.9 million), Monogram ($11.2 million), Tangleflags ($9.7 million), Ghost Pine ($8.7 million), SOEP ($8.2 million), and Mikwan ($7.0 million). In addition to development activities, $26.6 million was spent on office premises and information technology (IT) capital.

	Three months ended								Twelve months ended
($ millions)	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006		Dec 31, 2007			Dec 31, 2006
Geological and geophysical		5.0			1.8			6.1		12.6			8.9
Drilling and completions		62.1			39.1			83.6		215.4			217.1
Plant and facilities		19.0			10.7			26.6		41.9			56.9
Land purchases		2.7			1.4			5.5		13.2			17.9
Development capital		88.8			53.0			121.8		283.1			300.8
Other capital		6.9			12.7			1.0		26.6			2.6
Total capital expenditures		95.7			65.7			122.8		309.7			303.4
Business acquisitions		(0.6	)		0.4			900.7		923.1			1,396.4
Property acquisitions		9.0			—			0.5		9.0			50.3
Proceeds on property dispositions		(23.7	)		(163.1	)		0.5		(458.8	)		(15.2	)
Net capital expenditures and acquisitions		80.4			(97.0	)		1,024.5		783.0			1,734.9

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 71

MANAGEMENT’S DISCUSSION & ANALYSIS

Pengrowth currently anticipates the 2008 development capital program to be $355 million, which is the largest in Pengrowth’s history and represents an increase in expenditures of approximately 25 percent compared to the 2007 full year spending. In addition, Pengrowth plans to spend $20 million to continue its evaluation of its oilsands asset at Lindbergh and $12 million in office premises and IT capital.

RESERVES

Pengrowth’s 2007 development program resulted in proved plus probable reserve additions of 17.4 mmboe’s, resulting in a finding and development cost of $17.44 per boe, including the change in future development costs. Including acquisitions of 36.7 mmboe’s, finding and development costs were $18.97 per boe on a proved plus probable basis, including the change in future development cost.

Pengrowth reported year-end proved reserves of 241.2 mmboe and proved plus probable reserves of 319.9 mmboe compared to 225.9 mmboe and 297.8 mmboe, respectively at year-end 2006. Further details of Pengrowth’s 2007 year-end reserves are provided in the annual report and the AIF.

ACQUISITIONS AND DISPOSITIONS

On January 22, 2007 Pengrowth closed the acquisition of four subsidiaries of ConocoPhillips, holding Canadian oil and natural gas producing properties and undeveloped lands (the CP properties) for a purchase price of $1.0375 billion, prior to adjustments. The acquisition of the CP properties was funded in part by the December 8, 2006 equity offering of approximately $461 million with the remainder supported by a $600 million bank credit facility that was repaid on July 13, 2007.

Following the acquisition of the CP properties, Esprit Trust and Carson Creek, Pengrowth completed asset sales for $476 million ($458.8 million net of adjustments) in 2007.

WORKING CAPITAL

The working capital deficiency increased by $28.7 million from $160.9 million at December 31, 2006 to $189.6 million at December 31, 2007. Most of the increase in the working capital deficiency is attributable to the accounting for risk management contracts, where there is a net current non-cash liability in 2007 in the amount of $62.8 million.

Pengrowth frequently operates with a working capital deficiency, partially due to 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 were 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.

72 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

FINANCIAL RESOURCES AND LIQUIDITY

Pengrowth’s capital structure is as follows:

As at December 31

($ thousands)	2007			2006
Term credit facilities		513,998			257,000
Senior unsecured notes		689,238			347,200
Working capital deficit excluding bank indebtedness (cash and term deposits)(1)		191,620			151,575
Bank indebtedness (cash and term deposits)		(2,017	)		9,374
Net debt excluding convertible debentures		1,392,839			765,149
Convertible debentures		75,030			75,127
Net debt including convertible debentures		1,467,869			840,276
Trust unitholders’ equity		2,756,220			3,049,677
Net debt excluding convertible debentures as a percentage of total book capitalization		33.6	%		20.1	%
Net debt including convertible debentures as a percentage of total book capitalization		34.8	%		21.6	%
Cash flow from operating activities		800,344			554,368
Net debt excluding convertible debentures to cash flow from operating activities		1.7			1.4
Net debt including convertible debentures to cash flow from operating activities		1.8			1.5

⁽¹⁾ Prior year restated to conform to presentation adopted in current year

The $650 million increase in net debt excluding convertible debentures from December 31, 2006 is attributable to funds borrowed for the CP properties acquisition and Pengrowth’s capital program offset by the net proceeds of property dispositions. The net debt to cash flow is higher in 2007 compared to 2006 because 2006 year-end debt levels were lower than normal due to the closing of the December 2006 equity offering which was used to pre-fund a portion of the CP properties acquisition in January, 2007.

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. 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 impact our access to bank credit facilities and our ability to fund operations, maintain distributions and pursue profitable growth opportunities.

On December 14, 2007, Pengrowth announced that it had 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 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. No trust units were issued under the Equity Distribution Program during the year ended December 31, 2007.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 73

MANAGEMENT’S DISCUSSION & ANALYSIS

On June 15, 2007, Pengrowth increased its term credit facility and extended the maturity date to June 16, 2010. At December 31, 2007, Pengrowth maintained a $1.2 billion term credit facility and a $35 million operating line of credit. These facilities were reduced by drawings of $514 million and by $11 million in letters of credit outstanding at year-end. Pengrowth remains well positioned to fund its 2008 development program and to take advantage of acquisition opportunities as they arise. At December 31, 2007, Pengrowth had approximately $712 million available to draw from its credit facilities.

On July 26, 2007, Pengrowth closed a U.S. $400 million offering of notes issued on a private placement basis in the United States. The private placement consists of 6.35 percent notes due in 2017. The notes are unsecured and rank equally with Pengrowth’s bank facilities and existing term notes.

Pengrowth does not have any off balance sheet financing arrangements.

Pengrowth’s U.S. $600 million senior unsecured notes, 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 ratio 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 Earnings Before Income Taxes Depreciation and Amortization (EBITDA) for the last four fiscal quarters
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.

The actual loan documents are filed on SEDAR as “Other” or “Material document”. As at December 31, 2007, 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 may 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 were originally issued on July 28, 2005 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 fully paid Pengrowth 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. As at December 31, 2007, the principal amount of debentures outstanding was $74.7 million.

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:

74 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

	Three months ended									Twelve months ended
($ thousands, except per trust unit amounts	Dec 31, 2007			Sept 30, 2007			Dec 31, 2006			Dec 31, 2007			Dec 31, 2006
Cash flows from operating activities		196,325			217,630			91,237			800,344			554,368
Net income (loss)		(3,665	)		161,492			3,310			359,652			262,303
Distributions declared		166,631			172,109			185,651			706,601			559,063
Distributions declared per trust unit		0.675			0.70			0.75			2.875			3.00
Excess (shortfall) of cash flows from operating activities over distributions declared		29,694			45,521			(94,414	)		93,743			(4,695	)
Per trust unit		0.12			0.19			(0.43	)		0.38			(0.03	)
Shortfall of net income over distributions declared		(170,296	)		(10,617	)		(182,341	)		(346,949	)		(296,760	)
Per trust unit		(0.69	)		(0.04	)		(0.83	)		(1.41	)		(1.69	)
Ratio of distributions declared over cash flows from operating activities		85	%		79	%		203	%		88	%		101	%

Distributions typically exceed net income as a result of non-cash expenses such as: unrealized losses on commodity risk management contracts; 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 is to optimize cash distributions on a per trust unit basis to our unitholders over time while enhancing the value of our 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. Notwithstanding the fact that distributions may not exceed cash flow from operating activities in most periods, the surplus cash flow is not sufficient to fund the capital spending required to fully replace production. Accordingly, we believe our distributions include a return of capital.

As a result of the depleting nature of Pengrowth’s oil and gas assets, some level of capital expenditures is required to minimize production declines while other capital is required to optimize facilities. 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. Forecasted capital spending in 2008 will not be sufficient to replace the oil and gas reserves Pengrowth expects to produce during the year which could impact future distributions. Pengrowth has no restrictions on the payment of its distributions other than maintaining its financial covenants and ratios in its borrowings. 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. 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 fix the commodity price and mitigate price volatility on a portion of its 2008 and 2009 sales volumes. Details of commodity contracts are contained in Note 19 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.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 75

MANAGEMENT’S DISCUSSION & ANALYSIS

During the third quarter, Pengrowth reduced the distribution level by ten percent to Cdn $0.225 per trust unit for the October 15, 2007 distribution. Distributions declared subsequent to October 15, 2007 were also declared at this level. The reduction is to provide additional funds for capital expenditures.

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

TAXABILITY OF DISTRIBUTIONS

The following discussion relates to the taxation of Canadian unitholders only. Cash distributions are comprised of a return of capital portion which is tax deferred and a portion which is taxable income. The return of capital portion reduces the cost base of a unitholders’ trust units for purposes of calculating a capital gain or loss upon ultimate disposition.

In 2007, 95 percent of 2007 distributions and 100 percent of 2008 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 Tax Act, distributions to U.S. unitholders 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 proposes to increase the amount of Canadian withholding tax from 15 percent to 25 percent on distributions of income. The proposed increase in Canadian withholding tax rate on distributions of income under the Protocol does not effect returns of capital which would still be subject to a 15 percent Canadian withholding tax. The increase will become effective no earlier than January 1, 2010. Residents of the U.S. should consult their individual tax advisors on the impact of any additional Canadian withholding tax and changes to the tax laws. As of December 14, 2007, Canada completed the steps required to give effect to the Protocol, however the Protocol has not yet been ratified by the U.S. The Protocol will come into effect once it has been ratified by the United Sates and the two countries have formally notified each other that their procedures are complete. Withholding tax amounts on distributions paid to unitholders in other countries vary based on individual tax treaties. For additional tax information relating to non-residents, please refer to our website www.pengrowth.com.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

($ thousands)	2008		2009		2010		2011		2012		Thereafter		Total
Long term debt(1)		—		—		662,693		—		—		546,574		1,209,267
Interest payments on long term debt(2)		40,801		40,801		33,407		33,407		33,407		130,760		312,583
Convertible debentures(3)		—		—		74,700		—		—		—		74,700
Interest payments on convertible debentures(4)		4,810		4,810		4,810		—		—		—		14,430
Other(5)		9,015		9,232		8,652		8,221		8,139		42,028		85,287
		54,626		54,843		784,262		41,628		41,546		719,362		1,696,267
Purchase obligations
Pipeline transportation		43,595		36,254		19,603		17,528		15,796		41,339		174,115
CO2 purchases(6)		7,357		3,586		3,616		3,196		2,890		9,784		30,429
		50,952		39,840		23,219		20,724		18,686		51,123		204,544
Remediation trust fund payments		250		250		250		250		250		11,500		12,750
		105,828		94,933		807,731		62,602		60,482		781,985		1,913,561

(1)	The debt repayment includes the principal owing at maturity on foreign denominated fixed rate debt. (see Note 9 of the financial statements)
(2)	Interest payments relate to the interest payable on foreign denominated fixed rate debt using the year-end exchange rate
(3)	Includes repayment of convertible debentures on maturity (see Note 8 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

76 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

SUMMARY OF TRUST UNIT TRADING DATA

	High		Low		Close		Volume		Value
							(000’s)		($ millions)
TSX — PGF.UN ($ Cdn)
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
2006 1st quarter		—		—		—		—		—
2nd quarter		—		—		—		—		—
3rd quarter *		26.11		21.02		21.94		29,262		708.0
4th quarter		22.69		16.81		19.94		75,576		1,505.0
Year		26.11		16.81		19.94		104,838		2,213.0
NYSE — PGH ($ U.S.)
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
2006 1st quarter		25.15		21.50		23.10		13,421		316.2
2nd quarter		25.00		21.85		24.09		14,277		337.0
3rd quarter		24.95		18.90		19.62		27,359		604.0
4th quarter		20.25		14.78		17.21		55,108		955.6
Year		25.15		14.78		17.21		110,165		2,212.8
TSX — PGF.A ($ Cdn)
2007 1st quarter		—		—		—		—		—
2nd quarter		—		—		—		—		—
3rd quarter		—		—		—		—		—
4th quarter		—		—		—		—		—
Year		—		—		—		—		—
2006 1st quarter		28.96		24.96		26.88		1,244		33.8
2nd quarter		28.50		24.20		26.70		1,810		47.6
3rd quarter *		28.25		24.95		25.30		4,297		110.6
4th quarter		—		—		—		—		—
Year		28.96		24.20		25.30		7,351		192.0
TSX — PGF.B ($ Cdn)
2007 1st quarter		—		—		—		—		—
2nd quarter		—		—		—		—		—
3rd quarter		—		—		—		—		—
4th quarter		—		—		—		—		—
Year		—		—		—		—		—
2006 1st quarter		24.50		20.71		23.32		18,338		420.1
2nd quarter		26.05		22.41		26.05		18,982		459.6
3rd quarter *		27.25		24.84		25.31		14,226		364.0
4th quarter		—		—		—		—		—
Year		27.25		20.71		25.31		51,546		1,243.7

* On July 27, 2006, Pengrowth’s Class A trust units and Class B trust units were consolidated into a single class of trust units pursuant to which the Class A trust units were delisted from the Toronto Stock Exchange, Class A trust units were converted into Class B trust units (with the exception of Class A trust units held by residents of Canada who elected to retain their Class A trust units) and the Class B trust units were renamed as trust units and their trading symbol changed to PGF.UN

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 77

MANAGEMENT’S DISCUSSION & ANALYSIS

SUMMARY OF QUARTERLY RESULTS

The following table is a summary of quarterly results for 2007 and 2006.

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

2006	Q1		Q2		Q3		Q4
Oil and gas sales ($000’s)		291,896		283,532		287,757		350,908
Net income ($000’s)		66,335		110,116		82,542		3,310
Net income per trust unit ($)		0.41		0.69		0.51		0.01
Net income per trust unit — diluted ($)		0.41		0.68		0.51		0.01
Cash flow from operating activities ($000’s)		156,360		126,800		179,971		91,237
Distributions declared ($000’s)		120,302		120,597		132,513		185,651
Distributions declared per trust unit ($)		0.75		0.75		0.75		0.75
Daily production (boe)		58,845		56,325		58,344		77,614
Total production (mboe)		5,296		5,126		5,368		7,141
Average realized price ($  per boe)		55.04		54.91		53.67		49.24
Operating netback ($  per boe)		31.44		33.94		30.82		24.17

Production has increased over the quarters as a result the acquisitions completed by Pengrowth in the third and fourth quarters of 2006 and first quarter of 2007, offset by the property dispositions and operational outages experienced in the second half of 2007. Changes in commodity prices have affected oil and gas sales but have been partially muted by risk management activity. Net income in 2006 and 2007 has been impacted by non-cash charges, in particular depletion, depreciation and accretion, unrealized mark-to-market 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.

78 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

SELECTED ANNUAL INFORMATION FINANCIAL RESULTS

Oil and gas sales for 2007 increased 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)	2007		2006		2005
Oil and gas sales		1,722,038		1,214,093		1,151,510
Net income		359,652		262,303		326,326
Net income per trust unit ($)		1.47		1.49		2.08
Net income per trust unit — diluted ($)		1.46		1.49		2.07
Distributions declared per trust unit ($)		2.875		3.00		2.82
Total assets(1)		5,234,251		4,690,129		2,391,432
Long term debt(2)		1,278,266		679,327		368,089
Trust unitholders’ equity		2,756,220		3,049,677		1,475,996
Number of trust units outstanding at year-end (thousands)		246,846		244,017		159,864

(1)	Prior years restated to conform to presentation adopted in the current year
(2)	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:

• 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 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 including implementation of the October 31 Proposals governing such royalties, taxes and fees could have a material impact on Pengrowth’s financial results and the value of Pengrowth trust units;

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 79

MANAGEMENT’S DISCUSSION & ANALYSIS

• Changes to the royalty regime in Alberta were announced on October 25, 2007. The full details required to accurately assess the impact are not known at this time but will reduce future cash flows and reserve valuations;

• 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 Pengrowth’s success in developing existing reserves, acquiring new reserves and financing this development and acquisition activity within the context of the capital markets. Additional uncertainty with new legislation may limit access to capital or increase the cost of raising capital;

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

• A significant portion of our 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;

• Increased activity within the oil and gas sector has increased the cost of goods and services and makes it 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 may 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;

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

• Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital costs; and

• 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.

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

80 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION & ANALYSIS

SUBSEQUENT EVENTS

Subsequent to December 31, 2007, Pengrowth has entered into a series of fixed price commodity sales contracts with third parties. Pengrowth has committed for the remainder of 2008 and 2009 approximately 1,500 bbls per day and 3,000 bbls per day of crude oil and approximately 4,800 mcf per day and 14,200 mcf per day of natural gas respectively.

OUTLOOK

At this time, Pengrowth is forecasting average 2008 production of 80,000 to 82,000 boe per day from our existing properties. This estimate excludes the impact from other future acquisitions or divestitures.

Full year outlook for operating costs for 2008 is expected to decrease; however per unit operating costs are estimated to increase to $13.20 per boe.

Royalty expense is expected to be approximately 20 percent of Pengrowth’s sales for 2008.

General and administrative (G&A) expenses per boe are expected to remain stable in 2008 when compared to 2007. On a per boe basis, G&A is anticipated to be approximately $2.20 per boe for full year 2008, which includes non-cash G&A and anticipated management fees of approximately $0.40 per boe.

The development capital program of $355 million is the largest in Pengrowth’s history and represents an increase in expenditures of approximately 25 percent compared with estimated 2007 full year development capital expenditures of $283 million. In addition, Pengrowth plans to spend $20 million to continue its evaluation of its oilsands asset at Lindbergh and $12 million in office premises and information technology (IT) capital.

Pengrowth expects to spend approximately $18 million for 2008, excluding contributions to remediation trust funds on remediation and abandonment.

RECENT ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2007, Pengrowth adopted new and revised Canadian accounting standards relating to financial instruments. The impact of adopting the new standards are reflected in the financial statements. There was no material impact of adopting these new and revised standards. For a description of the new accounting rules and the impact on Pengrowth’s financial statements of adopting such rules, including the impact on Pengrowth’s deferred financing charges, long term debt and deferred foreign exchange gains, see Notes 2 and 3 to the financial statements.

New Canadian accounting recommendations for capital disclosures have been issued which will require additional disclosure of both qualitative and quantitative information about objectives, policies and processes for managing capital. These recommendations are effective for year-ends beginning January 1, 2008.

New Canadian accounting recommendations for additional disclosures about financial instruments have been issued which will require additional disclosure about the nature and extent of risks arising from financial instruments to which Pengrowth is exposed. These recommendations are effective for year-ends beginning January 1, 2008.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 81

MANAGEMENT’S DISCUSSION AND ANALYSIS

In February 2008, the Canadian Institute of Chartered Accountants confirmed that Canadian GAAP for publicly accountable enterprises will be converted to International Financial Reporting Standards (IFRS) on January 1, 2011. This change in GAAP will be effective for years beginning January 1, 2011.

In December 2007, the SEC announced that U.S. GAAP reconciliations requirement will be waived for Foreign Private Issuers who file financial statements prepared in accordance with IFRS for years beginning on or after January 1, 2009.

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 where both the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) must 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 Webster, evaluated the effectiveness of Pengrowth’s disclosure controls and procedures for the year ending December 31, 2007. 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, 2007 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.

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 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.

82 Management’s Discussion and Analysis — PENGROWTH 2007 ANNUAL REPORT

MANAGEMENT’S DISCUSSION AND ANALYSIS

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, 2007. 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, 2007.

The effectiveness of our internal control over financial reporting as of December 31, 2007 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report, which is included in our audited consolidated financial statements for the year ended December 31, 2007.

PENGROWTH 2007 ANNUAL REPORT — Management’s Discussion and Analysis 83

APPENDIX C

CONSOLIDATED FINANCIAL STATEMENTS OF PENGROWTH ENERGY TRUST INCLUDING MANAGEMENT’S REPORT TO UNITHOLDERS, THE AUDITORS’ REPORTS AND NOTE 23 THEREOF WHICH INCLUDES A RECONCILIATION OF THE CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

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 3, 2008

84 Management’s Report to Unitholders — PENGROWTH 2007 ANNUAL REPORT

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, 2007 and 2006 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, 2007 and 2006 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, 2007, 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 3, 2008 expressed an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting.

 

Chartered Accountants 

Calgary, Canada 

March 3, 2008 

PENGROWTH 2007 ANNUAL REPORT — Auditor’s Report 85

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, 2007, 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 the Trust’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company 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, 2007, 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 Company Accounting Oversight Board (United States). Our report dated March 3, 2008 expressed an unqualified opinion on those consolidated financial statements.

 

Chartered Accountants 

Calgary, Canada 

March 3, 2008 

86 Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS
(stated in thousands of dollars)

As at December 31	2007			2006
ASSETS
Current assets
Cash and term deposits	$	2,017		$	—
Accounts receivable		206,583			171,876
Due from Pengrowth Management Limited		731			—
Fair value of risk management contracts (Note 19)		8,034			37,972
Future income taxes (Note 11)		18,751			—
		236,116			209,848
Fair value of risk management contracts(Note 19)		6,024			495
Deposit on acquisition		—			103,750
Other assets(Note 5)		24,831			36,132
Property, plant and equipment(Note 6)		4,306,682			3,741,602
Goodwill(Note 4)		660,598			598,302
TOTAL ASSETS	$	5,234,251		$	4,690,129
LIABILITIES AND UNITHOLDERS’ EQUITY
Current liabilities
Bank indebtedness	$	—		$	9,374
Accounts payable and accrued liabilities		239,091			221,213
Distributions payable to unitholders		111,119			122,080
Due to Pengrowth Management Limited		—			2,101
Fair value of risk management contracts (Note 19)		70,846			—
Future income taxes (Note 11)		—			11,012
Contract liabilities (Note 7)		4,663			5,017
		425,719			370,797
Fair value of risk management contracts(Note 19)		22,613			1,367
Contract liabilities(Note 7)		12,162			16,825
Convertible debentures(Note 8)		75,030			75,127
Long term debt(Note 9)		1,203,236			604,200
Asset retirement obligations(Note 10)		352,171			255,331
Future income taxes(Note 11)		387,100			316,805
Trust unitholders’ equity(Note 12)
Trust Unitholders’ capital		4,432,737			4,383,993
Equity portion of convertible debentures		160			160
Contributed surplus		9,679			4,931
Deficit (Note 14)		(1,686,356	)		(1,339,407	)
		2,756,220			3,049,677
Commitments(Note 20)
Contingencies(Note 21)
Subsequent Events(Note 22)
TOTAL LIABILITIES AND UNITHOLDERS’ EQUITY	$	5,234,251		$	4,690,129

See accompanying notes to the consolidated financial statements.

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

Director	Director

PENGROWTH 2007 ANNUAL REPORT — Consolidated Financial Statements 87

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
(stated in thousands of dollars)

Years ended December 31	2007			2006
REVENUES
Oil and gas sales	$	1,722,038		$	1,214,093
Unrealized (loss) gain on commodity risk management (Note 19)		(122,307	)		26,499
Processing and other income		20,573			18,768
Royalties, net of incentives		(319,319	)		(241,494	)
Net revenue		1,300,985			1,017,866
EXPENSES
Operating		406,522			270,519
Transportation		12,672			7,621
Amortization of injectants for miscible floods		34,063			34,644
Interest on bank indebtedness		13,876			—
Interest on long term debt		70,416			32,109
General and administrative		55,903			36,613
Management fee		6,807			9,941
Foreign exchange (gain) loss (Note 15)		(61,857	)		22
Depletion, depreciation and amortization		639,084			351,575
Accretion (Note 10)		25,722			16,591
Other expenses		2,737			10,197
		1,205,945			769,832
Income before taxes		95,040			248,034
Future income tax reduction (Note 11)		(264,612	)		(14,269	)
NET INCOME	$	359,652		$	262,303
Deficit, beginning of year		(1,339,407	)		(1,042,647	)
Distributions declared		(706,601	)		(559,063	)
DEFICIT, END OF YEAR	$	(1,686,356	)	$	(1,339,407	)
Net income per trust unit (Note 18)
Basic	$	1.47		$	1.49
Diluted	$	1.46		$	1.49

See accompanying notes to the consolidated financial statements.

88 Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

CONSOLIDATED STATEMENTS OF CASH FLOWS
(stated in thousands of dollars)

Years ended December 31	2007			2006
CASH PROVIDED BY (USED FOR):
OPERATING
Net income	$	359,652		$	262,303
Depletion, depreciation and accretion		664,806			368,166
Future income tax reduction (Note 11)		(264,612	)		(14,269	)
Contract liability amortization (Note 7)		(5,017	)		(5,447	)
Amortization of injectants		34,063			34,644
Purchase of injectants		(26,052	)		(34,630	)
Expenditures on remediation		(11,428	)		(9,093	)
Unrealized foreign exchange (gain) loss (Note 15)		(73,940	)		480
Unrealized loss (gain) on risk management contracts (Note 19)		130,374			(26,499	)
Trust unit based compensation (Note 13)		5,351			2,546
Deferred charges and other items		2,987			498
Changes in non-cash operating working capital (Note 16)		(15,840	)		(24,331	)
		800,344			554,368
FINANCING
Distributions paid (Note 14)		(717,562	)		(516,966	)
Bank indebtedness		(9,374	)		9,374
Change in long term debt, net		674,276			(54,870	)
Redemption of convertible debentures (Note 8)		—			(21,184	)
Repayment of note payable		—			(20,000	)
Proceeds from issue of trust units		48,141			971,791
		(4,519	)		368,145
INVESTING
Business acquisition (Note 4)		(923,121	)		(500,451	)
Expenditures on property, plant and equipment		(309,708	)		(300,809	)
Other property acquisitions		(9,012	)		(52,880	)
Proceeds on property dispositions		458,804			15,230
Deposit on acquisition		—			(103,750	)
Change in remediation trust funds		(6,950	)		(2,815	)
Change in non-cash investing working capital (Note 16)		(3,821	)		37,529
		(793,808	)		(907,946	)
CHANGE IN CASH AND TERM DEPOSITS		2,017			14,567
CASH AND TERM DEPOSITS (BANK INDEBTEDNESS) AT BEGINNING OF YEAR		—			(14,567	)
CASH AND TERM DEPOSITS AT END OF YEAR	$	2,017		$	—

See accompanying notes to the consolidated financial statements.

PENGROWTH 2007 ANNUAL REPORT — Consolidated Financial Statements 89

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 a closed-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 2007 and 2006, this Residual Interest, as computed, did not result in any income retained by the Corporation.

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.

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.

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 the 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, the Corporation and its subsidiaries, Esprit Trust, Esprit Exploration and 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.

90 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 proportionate 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.

As a result of growth in exploration activities in 2007, Pengrowth began to capitalize 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. The effect of the change in accounting policy on prior periods was not material. In addition, transaction costs directly attributable to successful acquisitions are also capitalized.

Repairs and maintenance costs are expensed as incurred.

The capitalized costs, including the cost of unproven properties, are depleted on a unit of production method based on proved reserves before royalties as estimated by independent engineers. 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.

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 ceiling 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 an 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.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 91

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 estimated as 24 to 30 months.

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

The Trust is a taxable trust under the Canadian Income Tax Act. In prior years, the Trust was taxable only on Canadian income not distributed or distributable to its unitholders. Since the trust distributes all of its taxable income to its unitholders, historically, no provision was made for income tax by the Trust. Changes to Canadian tax legislation during 2007 impose a new tax on distributions from publicly traded income trusts which is expected to apply to the Trust on January 1, 2011. This has resulted in the recognition of future income taxes at the trust level.

Pengrowth follows the tax 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. Held to maturity investments are measured at amortized cost and held for trading investments are measured at fair value. 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. Pengrowth has not elected to designate any financial instruments as held for trading.

92 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 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).

Effective May 1, 2006, Pengrowth discontinued designating new commodity contracts as hedges. As a result, all commodity contracts entered into after the date are recorded at fair value with changes in fair value over a reporting period recognized in net income. Prior to May 1, 2006, any contracts previously designated as hedges continued to be designated as hedges and Pengrowth formally documented the relationships between hedging instruments and the hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process included linking derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. Pengrowth also formally assessed, both at the hedge’s inception and on an ongoing basis, whether the derivatives that were used in hedging transactions were highly effective in offsetting changes in fair value or cash flows of hedged items. Commodity contracts designated as hedges in 2006 were not recorded in the balance sheet. Receipts or payments arising from these contracts were recognized in oil and gas sales.

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. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 93

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 include 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 maturities of less than 90 days.

COMPARATIVE FIGURES

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

3. CHANGE IN ACCOUNTING POLICIES

Effective January 1, 2007, Pengrowth adopted several new and revised Canadian accounting standards related to financial instruments, as discussed in Note 2. The new handbook sections provide standards for the recognition and measurement of financial instruments and the use of hedge accounting. A statement of comprehensive income is required pursuant to the new standards. Certain gains and losses and other amounts arising from changes in fair value are temporarily recorded outside the income statement in other comprehensive income. The new standards have been adopted on a prospective basis with no restatement to prior period financial statements. Adoption of the new accounting policy resulted in the following:

I.

Pengrowth had deferred $2.8 million of debt issue costs related to prior issuances of private placement debt. The deferred issue costs were being amortized on a straight-line basis over the term of the debt. On January 1, 2007, an adjustment of $1.6 million was made to reduce the carrying amount of the related debt and other assets. No adjustment was made to opening retained earnings for the cumulative effect of the change in accounting policy as the amount was not significant.

II.

Foreign exchange swaps were used to fix the foreign exchange rate on the interest and principal of the Pounds Sterling 50 million ten year senior unsecured notes (see Note 9). In prior years, Pengrowth had formally documented this relationship as a hedge and applied hedge accounting to this transaction which resulted in any unrealized foreign exchange gains (losses) on the translation of the debt to be deferred and recorded in other assets (other liabilities). On January 1, 2007, Pengrowth ceased to designate the foreign exchange swaps as a cash flow hedge of the U.K. Pounds Sterling 50 million unsecured notes and as a result hedge accounting was no longer used to account for the transaction. As the hedging relationship qualified for hedge accounting under the revised hedging standards, $13.6 million of deferred foreign exchange loss related to the debt was reclassified to accumulated other comprehensive income. An asset related to the fair value of foreign exchange swaps of $13.9 million was recognized on the balance sheet on January 1, 2007 with a corresponding adjustment to reduce accumulated other comprehensive income. The remaining balance in accumulated other comprehensive income of $0.3 million was reclassified to net income in the period as the amount was not significant.

ACCOUNTING CHANGES

New Canadian accounting recommendations for capital disclosures have been issued which will require additional disclosure of both qualitative and quantitative information about objectives, policies and processes for managing capital. These recommendations are effective for years beginning January 1, 2008.

New Canadian accounting recommendations for additional disclosures about financial instruments have been issued which will require additional disclosure about the nature and extent of risks arising from financial instruments to which Pengrowth is exposed. These recommendations are effective for years beginning January 1, 2008.

94 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In February 2008, the Canadian Institute of Chartered Accountants confirmed that Canadian GAAP for publicly accountable enterprises will be converted to International Financial Reporting Standards (IFRS) on January 1, 2011.

In December 2007, the SEC announced that U.S. GAAP reconciliation requirement will be waived for Foreign Private Issuers who file financial statements prepared in accordance with IFRS for years beginning on or after January 1, 2009.

4. ACQUISITIONS

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		62,296
Asset retirement obligations		(90,772	)
Future income taxes		(305,144	)
	$	1,026,871
Consideration:
Cash	$	1,024,585
Acquisition costs		2,286
	$	1,026,871

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. The results of operations between the effective date of November 1, 2006 and the closing date have not been finalized. Final determination of the cost of the acquisition and the allocation thereof to the fair values of the CP properties is still pending.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 95

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2006 ACQUISITIONS

	Carson Creek			Esprit
	Properties			Energy Trust			Total
Allocation of Purchase Price:
Property, plant and equipment	$	495,806		$	1,207,121		$	1,702,927
Goodwill		129,745			285,722			415,467
Fair value of commodity contracts		—			10,601			10,601
Bank debt		—			(276,870	)		(276,870	)
Convertible debentures		—			(96,500	)		(96,500	)
Contract liabilities		(9,073	)		—			(9,073	)
Asset retirement obligations		(20,668	)		(51,651	)		(72,319	)
Future income taxes		(121,384	)		(110,590	)		(231,974	)
Working capital deficiency		—			(45,864	)		(45,864	)
	$	474,426		$	921,969		$	1,396,395
Consideration:
Cash	$	474,089		$	19,990		$	494,079
Pengrowth trust units issued		—			895,944			895,944
Acquisition costs		337			6,035			6,372
	$	474,426		$	921,969		$	1,396,395

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.

Carson Creek Properties

On September 28, 2006, Pengrowth acquired all of the issued and outstanding shares of a company which has interests in oil and natural gas assets in the Carson Creek area of Alberta (the “Carson Creek” acquisition). The transaction was accounted for using the purchase method of accounting.

Pengrowth assumed a firm pipeline transportation contract liability. The fair value of the contract was determined at the date of acquisition. Results of operations from the Carson Creek acquisition subsequent to the acquisition date are included in the consolidated financial statements.

Esprit Energy Trust

On October 2, 2006, Pengrowth and Esprit Trust completed a business combination (the “Combination”). Under the terms of the Combination agreement, each Esprit trust unit was exchanged for 0.53 of a Pengrowth trust unit and a one time special distribution of $0.30 per Esprit trust unit that was paid to Esprit unitholders prior to the closing date of the Combination.

As a result of the Combination, 34,725,157 Pengrowth trust units were issued to Esprit unitholders. The value assigned to each Pengrowth trust unit issued was approximately $25.80 per unit based on the weighted average market price of the trust units on the five days surrounding the announcement of the Combination. The Combination was accounted for as an acquisition of Esprit Trust by Pengrowth using the purchase method of accounting.

96 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The consolidated financial statements include the results of operations and cash flows of Esprit Trust and Esprit subsequent to October 2, 2006.

5. OTHER ASSETS

	2007		2006
Deferred compensation expense (net of accumulated amortization of $5,077, 2006 — $2,381)	$	—	$	2,696
Debt issue costs (net of accumulated amortization of, 2006 — $1,192)		—		1,626
		—		4,322
Deferred foreign exchange loss on translation of U.K. debt		—		13,631
Remediation trust funds (Note 10)		18,094		11,144
Equity investment		6,737		7,035
	$	24,831	$	36,132

On January 12, 2006 Pengrowth closed certain transactions with Monterey Exploration Ltd. (“Monterey”) under which Pengrowth has sold certain oil and gas properties for $22 million in cash, less closing adjustments, and 8,048,132 common shares of Monterey. As of December 31, 2007, Pengrowth held approximately 32 percent (2006 — 34 percent) of the common shares of Monterey.

In 2007, Pengrowth reduced the recorded amount of the equity investment by $0.3 million to reflect Pengrowth’s proportionate share of Monterey’s loss from operations.

6. PROPERTY, PLANT AND EQUIPMENT

	2007			2006
Property, plant and equipment, at cost	$	6,577,484		$	5,365,309
Accumulated depletion, depreciation and amortization		(2,298,083	)		(1,658,999	)
Net book value of property, plant and equipment	$	4,279,401			3,706,310
Net book value of deferred injectant costs		27,281			35,292
Net book value of property, plant and equipment and deferred injectants	$	4,306,682		$	3,741,602

In 2007, approximately $6.1 million of general and administrative costs associated with exploration and development activities were capitalized.

Pengrowth performed a ceiling test calculation at December 31, 2007 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, 2008 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 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, 2007.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 97

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			Foreign		Edmonton Light
	WTI Oil		Exchange Rate		Crude Oil		AECO Gas
Year	(U.S.$/bbl)		(U.S.$/Cdn$)		(Cdn$/bbl)		(Cdn$/mmbtu)
2008	$	92.00		1.000	$	91.10	$	6.75
2009	$	88.00		1.000	$	87.10	$	7.55
2010	$	84.00		1.000	$	83.10	$	7.60
2011	$	82.00		1.000	$	81.10	$	7.60
2012	$	82.00		1.000	$	81.10	$	7.60
2013	$	82.00		1.000	$	81.10	$	7.60
2014	$	82.00		1.000	$	81.10	$	7.80
2015	$	82.00		1.000	$	81.10	$	7.97
2016	$	82.02		1.000	$	81.12	$	8.14
2017	$	83.66		1.000	$	82.76	$	8.31
Thereafter	+ 2.0 percent/yr			1.000	+ 2.0 percent/yr		+ 2.0 percent/yr

7. CONTRACT LIABILITIES

Contract liabilities are comprised of the following amounts:

	2007			2006
Fixed price commodity contract	$	4,110		$	7,800
Firm transportation contracts		12,715			14,042
		16,825			21,842
Less current portion		(4,663	)		(5,017	)
	$	12,162		$	16,825

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.

8. CONVERTIBLE DEBENTURES

As a result of the Combination (see Note 4), Pengrowth assumed all of Esprit Trust’s 6.5 percent convertible unsecured subordinated debentures (the “Debentures”). The Debentures were originally issued by Esprit Trust on July 28, 2005 for a $100 million principal amount with interest paid semi-annually in arrears on June 30 and December 31 of each year. 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. 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.

Pursuant to a change of control provision in the Debenture Indenture, Pengrowth was required to make an offer to purchase all of the outstanding Debentures at a price equal to 101 percent of the principal amount, plus any accrued and unpaid interest. On December 12, 2006 Pengrowth redeemed a portion of the 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).

The Debentures were recorded on the consolidated financial statements at the estimated fair value on October 2, 2006, the date of the Combination. The estimated fair value of the Debentures was higher than the book (or “recorded”) value based on the market trading price of the Debentures on the date of the Combination. The Debentures have been classified as debt, net of the fair value of the conversion feature at the date of the Combination, which has been classified as part of Trust Unitholders’ Equity.

98 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the conversion feature was calculated using an option pricing model. The debt premium will be 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, 2007, Debentures with a face value of $74.7 million remain outstanding.

The following is a reconciliation of the Debentures balance from October 2, 2006:

	Debt			Equity			Total
Fair value on October 2, 2006 (Note 4)	$	96,295		$	205		$	96,500
Amortization of debt premium		(29	)		—			(29	)
Redeemed for cash		(21,139	)		(45	)		(21,184	)
Balance, December 31, 2006	$	75,127		$	160		$	75,287
Amortization of debt premium		(97	)		—			(97	)
Balance, December 31, 2007	$	75,030		$	160		$	75,190

9. LONG TERM DEBT

	2007		2006
U.S. dollar denominated debt:
U.S. dollar 150 million senior unsecured notes at 4.93 percent due April 2010	$	148,053	$	174,810
U.S. dollar 50 million senior unsecured notes at 5.47 percent due April 2013		49,351		58,270
U.S. dollar 400 million senior unsecured notes at 6.35 percent due July 2017		394,390		—
		591,794		233,080
Pound sterling denominated 50 million unsecured notes at 5.46 percent due December 2015		97,444		114,120
Canadian dollar revolving credit borrowings		513,998		257,000
	$	1,203,236	$	604,200

Pengrowth has a $1.2 billion syndicated extendible revolving term credit facility. The facility is unsecured, covenant based and has a three-year term maturing June 16, 2010. 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. 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 $35 million demand operating line of credit. The facilities were reduced by drawings of $514 million and by outstanding letters of credit in the amount of approximately $11.1 million at December 31, 2007.

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.

On December 1, 2005, Pengrowth closed a U.K. Pounds 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

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 99

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $2.3 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.

As of December 31, 2007, an unrealized cumulative foreign exchange gain of $115.0 million (December 31, 2006 — $57.2 million) has been recognized on the U.S. dollar term notes since the date of issuance. As of December 31, 2007, an unrealized cumulative foreign exchange gain of $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 (Note 3).

The five year schedule of long term debt repayment based on current maturity dates is as follows: 2008 — nil, 2009 — nil, 2010 — 662.7 million, 2011 — nil, 2012 — nil.

10. ASSET RETIREMENT OBLIGATIONS

The Asset Retirement Obligations (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 $352 million as at December 31, 2007 (2006 — $255 million), based on a total escalated future liability of $2,015 million (2006 — $1,530 million). These costs are expected to be made over 50 years with the majority of the costs incurred between 2035 and 2054. Pengrowth’s credit adjusted risk free rate of eight percent (2006 — eight percent) and an inflation rate of two percent (2006 — two percent) were used to calculate the net present value of the ARO.

The following reconciles Pengrowth’s ARO:

	2007			2006
Asset retirement obligations, beginning of year	$	255,331		$	184,699
Increase (decrease) in liabilities during the year related to:
Acquisitions		91,333			72,680
Disposals		(35,199	)		(1,500	)
Additions		3,753			1,649
Revisions		22,659			(9,695	)
Accretion expense		25,722			16,591
Liabilities settled during the year		(11,428	)		(9,093	)
Asset retirement obligations, end of year	$	352,171		$	255,331

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. In 2007, an evaluation was completed and Pengrowth is currently in discussions with the former owner of the Judy Creek properties to determine if the future funding levels should be maintained or reduced. Contributions to the Judy Creek remediation trust fund may change based on future evaluations of the fund.

100 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2007 and 2006 and Pengrowth’s expenditures on ARO:

��
Remediation Trust Funds	2007			2006
Opening balance	$	11,144		$	8,329
Contributions to Judy Creek Remediation Trust Fund		917			1,036
Contributions to SOEP Environmental Restoration Fund		6,441			2,153
Remediation funded by Judy Creek Remediation Trust Fund		(408	)		(374	)
Change in remediation trust funds		6,950			2,815
Closing balance	$	18,094		$	11,144
Expenditures on ARO		2007			2006
Expenditures on ARO not covered by the trust funds	$	11,020		$	8,719
Expenditures on ARO covered by the trust funds		408			374
	$	11,428		$	9,093

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. As a result of the enactment of the SIFT tax, the Trust recorded a future income tax reduction of $71 million in the second quarter of 2007 to reflect temporary differences in the Trust.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 101

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2007			2006
Income before taxes	$	95,040		$	248,048
Combined federal and provincial tax rate		32.1	%		34.1	%
Expected income tax		30,508			84,584
Net income of the Trust		(123,227	)		(85,989	)
Impact of SIFT legislation		(71,048	)		—
Resource allowance		—			(8,618	)
Non-deductible crown charges		—			17,586
Unrealized foreign exchange gain		(9,254	)		1
Book to tax differential on dispositions		(68,722	)		—
Attributed Canadian royalty income		—			(6,616	)
Change in enacted tax rates		(59,230	)		(19,886	)
Future tax rate difference		19,679			2,491
Other including stock based compensation		16,682			2,178
Future income tax reduction		(264,612	)		(14,269	)
Capital taxes		—			14
	$	(264,612	)	$	(14,255	)

Changes in 2007 to income tax rates have reduced Pengrowth’s future tax rate to approximately 25 percent (2006 — 29 percent) applied to the temporary differences compared to the federal and provincial statutory rate of approximately 32 percent for the 2007 income tax year (2006 — 34 percent).

The net future income tax liability is comprised of:

	2007			2006
Future income tax liabilities:
Property, plant, equipment and other assets	$	344,701		$	339,660
Unrealized foreign exchange gain		10,776			8,288
Deferred partnership income		27,929			—
Other		—			150
		383,406			348,098
Future income tax assets:
Attributed Canadian royalty income		(10,351	)		(13,947	)
Contract liabilities		(4,706	)		(6,334	)
	$	368,349		$	327,817

102 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. TRUST UNITS

The total authorized capital of Pengrowth is 500,000,000 trust units.

Total Trust Units:

Years ended December 31	2007					2006
	Number					Number
Trust units issued	of trust units		Amount			of trust units		Amount
Balance, beginning of year		244,016,623	$	4,383,993			159,864,083	$	2,514,997
Issued for the Esprit Trust business combination (non-cash)		—		—			34,725,157		895,944
Issued for cash		—		—			47,575,000		987,841
Issue costs		—		(745	)		—		(51,575	)
Issued on redemption of DEUs (non-cash)		2,931		55			14,523		233
Issued for cash on exercise of trust unit options and rights		350,615		4,006			607,766		9,476
Issued for cash under Distribution Reinvestment Plan (DRIP)		2,461,299		44,880			1,226,806		26,049
Issued on redemption of Royalty Units (non-cash)		14,952		—			3,288		—
Trust unit rights incentive plan (non-cash exercised)		—		548			—		1,028
Balance, end of year		246,846,420	$	4,432,737			244,016,623	$	4,383,993

“Consolidated” Trust Units:

Years ended December 31	2007					2006
	Number					Number
Trust units issued	of trust units		Amount			of trust units		Amount
Balance, beginning of year		244,005,105	$	4,383,819			—	$	—
Issued in trust unit consolidation		—		—			160,921,001		2,535,949
Issued on conversion of Class A trust units		9,630		173			3,450		57
Issued for the Esprit Trust business combination (non-cash)		—		—			34,725,157		895,944
Issued for cash		—		—			47,575,000		987,841
Issue costs		—		(745	)		—		(51,575	)
Issued on redemption of DEUs (non-cash)		2,931		55			14,523		233
Issued for cash on exercise of trust unit options and rights		350,615		4,006			99,228		1,579
Issued for cash under DRIP		2,461,299		44,880			663,458		13,415
Issued on redemption of Royalty Units (non-cash)		14,952		—			3,288		—
Trust unit rights incentive plan (non-cash exercised)		—		548			—		376
Balance, end of year		246,844,532	$	4,432,736			244,005,105	$	4,383,819

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 103

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Class A Trust Units:

Years ended December 31	2007						2006
	Number						Number
Trust units issued	of trust units			Amount			of trust units			Amount
Balance, beginning of year		11,518		$	174			77,524,673		$	1,196,121
Trust units converted to Class A trust units		(9,630	)		(173	)		2,760			43
Trust units converted to “consolidated” trust units		—			—			(77,515,915	)		(1,195,990	)
Balance, end of year		1,888		$	1			11,518		$	174

Class B Trust Units:

Year ended December 31	2006
	Number
Trust units issued	of trust units			Amount
Balance, beginning of year		82,301,443		$	1,318,294
Trust units converted to (from) Class B trust units		1,095			17
Issued for cash on exercise of trust unit options and rights		508,538			7,897
Issued for cash under DRIP		563,348			12,634
Trust unit rights incentive plan (non-cash exercised)		—			652
Trust units renamed to become “consolidated” trust units		(83,374,424	)		(1,339,494	)
Balance, end of year		—		$	—

Unclassified Trust Units:

Year ended December 31	2006
	Number
Trust units issued	of trust units			Amount
Balance, beginning of year		37,967		$	582
Converted to Class A or Class B trust units		(3,855	)		(60	)
Trust units converted to “consolidated” trust units		(34,112	)		(522	)
Balance, end of year		—		$	—

Class A Trust Unit and Class B Trust Unit Consolidation

On June 23, 2006 the Pengrowth unitholders voted to consolidate the Class A trust units and Class B trust units into one class of trust units (“consolidated” trust units). As a result, the restrictions on the Class B trust units that provided that the Class B trust units may only be held by residents of Canada were eliminated and all of the issued and outstanding trust units were converted into “consolidated” trust units on the basis of one “consolidated” trust unit for each whole trust unit previously held (with the exception of Class A trust units held by residents of Canada who provided a residency declaration to the Trustee).

104 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Redemption Rights

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 of the Corporation (the “Board of Directors”) for the ten days after the Trust Units or Class A trust units are surrendered for redemption and (ii) the closing price of the Trust Units on such market on the date the Trust Units or Class A trust units are surrendered for redemption. The redemption right permits Unitholders to redeem Trust Units and Class A trust units for maximum proceeds of $25,000 in any calendar month provided that such limitation may be waived at the discretion of the Board of Directors. Redemptions in excess of the cash limit must be satisfied by way of a 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 or Class A trust units are to be redeemed. The price of Trust Units and Class A trust units, as applicable, for redemption purposes is based upon the closing trading price of the Trust Units irrespective of whether the units being redeemed are Trust Units or Class A trust units.

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 all 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 announced that it had 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 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. No Trust Units were issued under the Equity Distribution Program during the year ended December 31, 2007.

Contributed Surplus

	2007			2006
Balance, beginning of year	$	4,931		$	3,646
Trust unit rights incentive plan (non-cash expensed)		1,903			1,298
Deferred entitlement trust units (non-cash expensed)		3,448			1,248
Trust unit rights incentive plan (non-cash exercised)		(548	)		(1,028	)
Deferred entitlement trust units (non-cash exercised)		(55	)		(233	)
Balance, end of year	$	9,679		$	4,931

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 105

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13. TRUST UNIT BASED COMPENSATION PLANS

Up to ten percent of the issued and outstanding trust units, to a maximum of 18 million trust units, may be reserved for DEUs, rights and option grants, in aggregate.

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 2007 and 2006 grants and 117 percent for 2005 grants (2006 — 125 percent for all 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 $3.4 million in 2007 (2006 — $1.3 million) related to the DEUs based on the weighted average grant date fair value of $20.07 per DEU (2006 — $20.65 per DEU). As at December 31, 2007, the amount of compensation expense to be recognized over the remaining vesting period was $6.6 million (December 31, 2006 — $4.4 million) or $10.71 per DEU (2006 — $13.44 per DEU). The unrecognized compensation cost will be expensed to net income over the remaining weighted average vesting period of 1.5 years (2006 — 1.8 years).

	2007					2006
				Weighted					Weighted
	Number			average		Number of			average
DEUs	of DEUs			fair value		DEUs			fair value
Outstanding, beginning of year		399,568		$	20.55		185,591		$	18.32
Granted		451,615		$	19.73		222,088		$	22.28
Forfeited		(92,672	)	$	20.15		(33,981	)	$	20.13
Exercised		(2,931	)	$	20.06		(14,207	)	$	20.43
Deemed DRIP		112,462		$	20.27		40,077		$	19.14
Outstanding, end of year		868,042		$	20.13		399,568		$	20.55

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. 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 2007 were $1.14 per trust unit right (2006 — $1.79 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.

106 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2007, rights to purchase 2,250,056 trust units were outstanding (2006 — 1,534,241) that expire at various dates to December 2, 2011.

	2007					2006
				Weighted					Weighted
	Number			average		Number			average
Trust Unit Rights	of rights			exercise price		of rights			exercise price
Outstanding at beginning of year		1,534,241		$	16.06		1,441,737		$	14.85
Granted(1)		1,259,562		$	19.75		617,409		$	22.39
Exercised		(343,925	)	$	11.35		(452,468	)	$	14.75
Forfeited		(199,822	)	$	14.63		(72,437	)	$	17.47
Outstanding at year-end	��	2,250,056		$	17.39		1,534,241		$	16.06
Exercisable at year-end		1,317,296		$	16.30		969,402		$	14.22

⁽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, 2007:

	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
$9.00 to $11.99		255,178		1.1	$	11.07		255,178	$	11.07
$12.00 to $14.99		281,990		2.0	$	13.91		281,990	$	13.91
$15.00 to $16.99		97,376		2.8	$	15.83		97,376	$	15.83
$17.00 to $18.99		1,206,999		4.2	$	17.84		415,257	$	18.55
$19.00 to $23.99		408,513		3.2	$	20.47		267,495	$	20.47
$9.00 to $23.99		2,250,056		3.3	$	17.39		1,317,296	$	16.30

Compensation expense associated with the trust unit rights granted during 2007 was based on the estimated fair value of $2.04 per trust unit right (2006 — $1.79). The fair value of trust unit rights granted in 2007 was estimated at eight 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 4.0 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 2007 was $1.9 million (2006 — $1.3 million). As at December 31, 2007, the amount of compensation expense to be recognized over the remaining vesting period was $1.0 million (December 31, 2006 — $0.6 million) or $0.31 per trust unit right (2006 — $0.64 per trust unit right). The unrecognized compensation cost will be expensed to net income over the weighted average remaining vesting period of 0.9 year (2006 — 0.9 year). The trust units are issued from treasury upon vesting.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 107

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2007, options to purchase 66,318 trust units were outstanding (2006 — 98,619) that expire at various dates to June 28, 2009.

	2007					2006
				Weighted					Weighted
	Number			average		Number			average
Trust Unit Options	of options			exercise price		of options			exercise price
Outstanding at beginning of year		98,619		$	16.12		259,317		$	17.28
Exercised		(6,690	)	$	15.25		(155,298	)	$	18.03
Expired		(25,611	)	$	18.61		(5,400	)	$	16.96
Outstanding and exercisable at year-end		66,318		$	15.25		98,619		$	16.12

Trust Unit Award Plan

Effective February 27, 2006, Pengrowth awarded trust units and in some cases trust units and cash to eligible employees under the Trust Unit Award Plan. Eligible employees received the trust units and cash on July 1, 2007. Pengrowth acquired the trust units to be awarded under the plan on the open market for $5.1 million and placed them in a trust account established for the benefit of the eligible employees. The cost to acquire the trust units has been charged to net income on a straight-line basis over the vesting period. In addition, the cash portion of the incentive plan of approximately $1.1 million was accrued on a straight line basis over the vesting period. Unvested trust units were sold on the open market. In 2007, the amount charged to net income related to the February 27, 2006 trust unit award plan including the cash portion of the award was $2.9 million (2006 — $3.0 million).

Employee Savings Plans

Pengrowth has savings plans whereby Pengrowth will match contributions by qualifying employees of one to 12 percent (2006 — one to 11 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 13 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 $3.5 million in 2007 (2006 — $2.1 million) and $0.9 million in 2007 (2006 — $0.6 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. Certain officers hold trust units under the Trust Unit Margin Purchase Plan; however, they have been prohibited since 2005 from increasing the number of trust units they can hold under the plan. 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, 2007, 432,988 trust units (2006 — 527,482) were deposited under the plan with a market value of $7.6 million (2006 — $10.5 million) and a corresponding margin loan of $4.4 million (2006 — $5.8 million).

108 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The investment dealer has limited the total margin loan available under the plan to the lesser of $20 million or 75 percent of the market value of the units held under the plan. If the market value of the trust units under the plan declines, Pengrowth may be required to make payments or post additional letters of credit to the investment dealer. Any payments to be made by Pengrowth are to 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, 2007 was $4.4 million (2006 — $5.8 million), however, the individual plan members are primarily responsible for any margin loans and Pengrowth would only be responsible for any unpaid amounts.

14. DEFICIT

	2007			2006
Accumulated earnings	$	1,675,338		$	1,315,686
Accumulated distributions declared		(3,361,694	)		(2,655,093	)
	$	(1,686,356	)	$	(1,339,407	)

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 2007 were $717.6 million (2006 — $517.0 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 (GAIN) LOSS

	2007			2006
Unrealized foreign exchange loss (gain) on translation of U.S. dollar denominated debt	$	(57,820	)	$	480
Unrealized foreign exchange gain on translation of U.K. Pound denominated debt		(16,120	)		—
	$	(73,940	)	$	480
Unrealized loss on foreign exchange risk management contracts (Note 19)		8,067			—
Realized foreign exchange (gain) loss		4,016			(458	)
	$	(61,857	)	$	22

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 109

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

16. OTHER CASH FLOW DISCLOSURES

Change in Non-Cash Operating Working Capital

Cash provided by (used for):	2007			2006
Accounts receivable	$	(34,707	)	$	12,819
Accounts payable and accrued liabilities		21,699			(30,974	)
Due to Pengrowth Management Limited		(2,832	)		(6,176	)
	$	(15,840	)	$	(24,331	)

Change in Non-Cash Investing Working Capital

Cash provided by (used for):	2007			2006
Accounts payable for capital accruals	$	(3,821	)	$	37,529

Cash payments

	2007		2006
Interest on long term debt	$	58,192	$	32,183
Interest on bank indebtedness		13,876		—
	$	72,068	$	32,183

Interest of $13.9 million on bank indebtedness was incurred on a $600 million credit facility that Pengrowth fully repaid on July 13, 2007.

17. RELATED PARTY TRANSACTIONS

The Manager provides certain services pursuant to a management agreement for which Pengrowth was charged $0.1 million (2006 — $2.9 million) for performance fees and $6.7 million (2006 — $7.0 million) for management fees. In addition, Pengrowth was charged $1.0 million (2006 — $1.0 million) for reimbursement of general and administrative expenses incurred by the Manager pursuant to the management agreement. The law firm controlled by the Vice President and Corporate Secretary of the Corporation charged $1.1 million (2006 — $1.0 million) for legal and advisory services provided to Pengrowth. The transactions have been recorded at the exchange amount. Amounts payable to the related parties are unsecured, non-interest bearing and have no set terms of repayment.

A senior officer of the Corporation is a member of the Board of Directors of Monterey, a company that Pengrowth owns approximately 32 percent of the outstanding common shares. In December 2007, two senior officers of the Corporation directly and indirectly purchased a total of 230,000 shares (2006 — 30,000 shares) of Monterey for a total consideration of $805,000 (2006 — $150,000) in a new share offering marketed by an independent broker. At December 31, 2007, two senior officers of the Corporation directly and indirectly hold 260,000 shares of Monterey.

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:

	2007		2006
Weighted average number of trust units — Basic		245,470		175,871
Dilutive effect of trust unit options, trust unit rights and DEUs		740		583
Weighted average number of trust units — Diluted		246,210		176,454

110 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2007, 3.7 million (2006 — 0.8 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. FINANCIAL INSTRUMENTS

Interest Rate Risk

Pengrowth has mitigated some exposure to interest rate risk by entering into fixed rate term notes (Note 9). Pengrowth is exposed to interest rate risk on the Canadian revolving credit facility as the interest charged on the amount borrowed is based on a floating interest rate.

Foreign Currency 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 forward and futures contracts section below. Pengrowth is exposed to foreign currency fluctuation on the U.S. dollar denominated notes for both interest and principal payments.

Pengrowth entered into foreign exchange swaps in conjunction with issuing U.K. Pounds Sterling 50 million ten year term notes (Note 9) which fixed the Canadian dollar to Pound Sterling exchange rate on the interest and principal of the Pound Sterling denominated debt at approximately Pounds Sterling 0.4976 per Canadian dollar. The estimated fair value of the foreign exchange swaps have been determined based on the amount Pengrowth would receive or pay to terminate the contract at year-end. At December 31, 2007, the amount Pengrowth would receive to terminate the foreign exchange swap would be approximately $5.8 million (December 31, 2006 — $13.9 million).

Credit Risk

Pengrowth sells a significant portion of its oil and gas to commodity marketers, refiners and end-users, and the accounts receivable are subject to normal industry credit risks. 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 “A” credit ratings or better.

Forward and Futures Contracts

Pengrowth has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates.

As at December 31, 2007, Pengrowth had fixed the price applicable to future production as follows:

Crude Oil:

	Volume		Reference	Price
Remaining Term	(bbl/d)		Point	per bbl
Financial:
Jan 1, 2008 — Oct 31, 2008		1,000	WTI(1)	$74.25 Cdn
Jan 1, 2008 — Dec 31, 2008		16,500	WTI(1)	$76.20 Cdn
Jan 1, 2009 — Dec 31, 2009		6,000	WTI(1)	$77.57 Cdn

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

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 111

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Natural Gas:

	Volume		Reference	Price
Remaining Term	(mmbtu/d)		Point	per mmbtu
Financial:
Jan 1, 2008 — Dec 31, 2008		5,000	Transco Z6(1)	$10.90 Cdn
Jan 1, 2008 — Dec 31, 2008		12,500	NYMEX(1)	$8.22 Cdn
Jan 1, 2009 — Dec 31, 2009		10,000	NYMEX(1)	$8.50 Cdn
Jan 1, 2008 — Mar 31, 2008		2,370	AECO	$8.44 Cdn
Jan 1, 2008 — Dec 31, 2008		61,609	AECO	$8.26 Cdn
Jan 1, 2009 — Dec 31, 2009		26,065	AECO	$7.56 Cdn
Jan 1, 2008 — Dec 31, 2008		15,000	Chicago MI(1)	$8.45 Cdn
Jan 1, 2009 — Dec 31, 2009		12,500	Chicago MI(1)	$8.40 Cdn

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

The estimated fair value of the financial crude oil and natural gas contracts has been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at year-end. At December 31, 2007, the amount Pengrowth would receive (pay) to terminate the financial crude oil and natural gas contracts would be ($121) million and $36 million, respectively.

The fair value of the commodity and foreign exchange risk management contracts are allocated to current and non-current assets and liabilities on a contract by contract basis.

				Foreign
	Commodity risk			exchange risk
	management			management
Balance Sheet as at December 31, 2007	contracts			contracts			Total
Current portion of unrealized risk management assets	$	8,034		$	—		$	8,034
Non-current portion of unrealized risk management assets		66			5,958			6,024
Current portion of unrealized risk management liabilities		(70,694	)		(152	)		(70,846	)
Non-current portion of unrealized risk management liabilities		(22,613	)		—			(22,613	)
Total unrealized risk management assets (liabilities) as at December 31, 2007	$	(85,207	)	$	5,806		$	(79,401	)

				Foreign
	Commodity risk			exchange risk
	management			management
Balance Sheet as at December 31, 2006	contracts			contracts		Total
Current portion of unrealized risk management assets	$	37,972		$	—	$	37,972
Non-current portion of unrealized risk management assets		495			—		495
Current portion of unrealized risk management liabilities		—			—		—
Non-current portion of unrealized risk management liabilities		(1,367	)		—		(1,367	)
Total unrealized risk management assets (liabilities) as at December 31, 2006	$	37,100		$	—	$	37,100

112 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The change in the fair value of the risk management contracts during the year is recognized as an unrealized gain or loss, as summarized below:

				Foreign
	Commodity risk			exchange risk
	management			management
Year ended December 31, 2007	contracts			contracts			Total
Total unrealized risk management assets (liabilities) at December 31, 2007	$	(85,207	)	$	5,806		$	(79,401	)
Less: Unrealized risk management assets at January 1, 2007		37,100			13,873			50,973
Unrealized loss on risk management for the year ended December 31, 2007	$	(122,307	)	$	(8,067	)	$	(130,374	)

			Foreign
	Commodity risk		exchange risk
	management		management
Year ended December 31, 2006	contracts		contracts		Total
Total unrealized risk management assets at December 31, 2006	$	37,100	$	—	$	37,100
Less: Unrealized risk management asset recognized as part of Esprit business combination		10,601		—		10,601
Unrealized gain on risk management for the year ended December 31, 2006	$	26,499	$	—	$	26,499

Natural Gas Fixed Price Sales Contract

Pengrowth assumed a natural gas fixed price physical sales contract in conjunction with an acquisition. At December 31, 2007, the amount Pengrowth would pay to terminate the fixed price sales contract would be $9 million. Details of the physical fixed price sales contract are provided below:

	Volume		Price
Remaining Term 2008 to 2009	(mmbtu/d)		per mmbtu(1)
Jan 1, 2008 — Oct 31, 2008		3,886	$2.34 Cdn
Nov 1, 2008 — April 30, 2009		3,886	$2.40 Cdn

⁽¹⁾ Reference price based on AECO

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 113

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair value of financial instruments

The carrying value of financial instruments included in the balance sheet, other than U.S. and U.K. debt, the debentures, the fair value of the risk management contracts and remediation trust funds approximate their fair value due to their short maturity. The fair value of the other financial instruments is as follows:

	2007				2006
			Net book				Net book
As at December 31	Fair value		value		Fair value		value
Remediation funds	$	18,107	$	18,094	$	11,162	$	11,144
U.S. dollar denominated debt	$	627,674	$	591,794	$	224,624	$	233,080
U.K. Pound Sterling denominated debt	$	96,181	$	97,444	$	109,692	$	114,120
Convertible debentures	$	74,741	$	75,030	$	75,488	$	75,127

20. COMMITMENTS

	2008		2009		2010		2011		2012		Thereafter		Total
Operating leases	$	9,015	$	9,232	$	8,652	$	8,221	$	8,139	$	42,028	$	85,287

Operating leases include office rent and vehicle leases.

21. 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.

22. SUBSEQUENT EVENTS

Subsequent to December 31, 2007, Pengrowth has entered into a series of fixed price commodity sales contracts with third parties as follows: Crude Oil:

	Volume		Reference	Price
Remaining Term	(bbl/d)		Point	per bbl
Financial:
Mar 1, 2008 — Dec 31, 2008		1,500	WTI(1)	$95.88Cdn
Jan 1, 2009 — Dec 31, 2009		3,000	WTI(1)	$93.25Cdn

Natural Gas:

	Volume		Reference	Price
Remaining Term	(mmbtu/d)		Point	per mmbtu
Financial:
Mar 1, 2008 — Dec 31, 2008		2,370	AECO	$7.97Cdn
Jan 1, 2009 — Dec 31, 2009		14,217	AECO	$7.97Cdn
Feb 1, 2008 — Dec 31, 2008		2,500	Chicago MI (1)	$8.31Cdn

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

114 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

23. 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, 2007, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs. At December 31, 2006, the application of the full cost ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $114.2 million.

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. 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 2007 depletion charge by $35.8 million (2006 — $24.0 million).

(b) Statement of Financial Accounting Standards (SFAS) 130, “Reporting Comprehensive Income” requires the reporting of comprehensive income in addition to net income. Comprehensive income includes net income plus other comprehensive income; specifically, all changes in equity of a company during a period arising from non-owner sources. Under Canadian GAAP, comprehensive income is reported for periods beginning on or after January 1, 2007. 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.

(c) SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” establishes accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity’s approach to managing risk.

Effective May 1, 2006, Pengrowth discontinued designating new commodity contracts as hedges. As at December 31, 2007 and 2006, there were no financial crude oil and natural gas contracts outstanding for which hedge accounting was applied. The accounting treatment for financial commodity contracts entered into after May 1, 2006 and where hedge accounting was no longer applied by Pengrowth is consistent with the accounting standards for these contracts under 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, $2.4 million, will be amortized to income over the remaining life of the foreign exchange swap of approximately nine years. 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.

Under Canadian GAAP, for the year ended December 31, 2006, a $13.6 million exchange loss on the translation of the U.K. pound denominated debt was deferred and included in other assets on the balance sheet. This deferred exchange loss has been expensed under U.S. GAAP and has been offset by the reclassification of $13.6 million of the unrealized gain on the foreign currency swap from other comprehensive income.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 115

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(d) 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 percent 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.

(e) 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, 2007 is $219.0 million (2006 — $9.4 million). The portion of income tax reduction taxed at the provincial level is $114.7 million (2006 — $4.9 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 year. 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.

(f) Additional disclosures required by SFAS 123 (revised 2004) with respect to Pengrowth’s equity incentive plans are provided below.

The intrinsic value of the DEUs, trust unit rights and trust unit options exercised was as follows:

	2007					2006
	Number Exercised			Intrinsic Value		Number Exercised			Intrinsic Value
DEUs		2,931	(1)	$	58		14,523	(1)	$	334
Trust Unit Options		6,690			32		155,298			827
Trust Unit Rights		343,925			2,837		452,468			3,924
Total		353,546		$	2,927		622,289		$	5,085

⁽¹⁾ DEUs exercised relates to trust units issued under the plan for retirees as DEUs vest immediately upon retirement, including accumulated DRIP

116 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about trust unit options, trust unit rights and DEUs vested and expected to vest:

	Trust Unit		Trust Unit
As 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 price of DEUs
(2)	Based on December 31 closing trust unit price

	Trust Unit		Trust Unit
As at December 31, 2006	Options		Rights		DEUs
Number vested and expected to vest		98,619		1,521,207		374,595
Weighted average exercise price per unit(1)	$	16.12	$	16.04	$	—
Aggregate intrinsic value(2)	$	377	$	5,936	$	7,469
Weighted average remaining life (years)		1.5		3.2		1.8

(1)	No proceeds are received upon exercise price 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:

As at December 31, 2007	Trust Unit Options		Trust Unit Rights
Number exercisable(1)		66,318		1,317,296
Weighted average exercise price per unit	$	15.25	$	16.30
Aggregate intrinsic value(2)	$	157	$	1,743
Weighted average remaining life (years)		0.8		3.3

(1)	No DEUs were exercisable at December 31, 2007
(2)	Based on December 31 closing trust unit price

As at December 31, 2006	Trust Unit Options		Trust Unit Rights
Number exercisable(1)		98,619		969,402
Weighted average exercise price per unit	$	16.12	$	14.22
Aggregate intrinsic value(2)	$	377	$	5,542
Weighted average remaining life (years)		1.5		3.2

(1)	No DEUs were exercisable at December 31, 2006
(2)	Based on December 31 closing trust unit price

(g) 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.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 117

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

(h) Under SFAS 141, “Business Combinations”, supplemental pro forma disclosure is required for significant business combinations occurring during the year. On October 2, 2006, Pengrowth and Esprit Trust completed a business combination. The consolidated financial statements include the results of operations and cash flows of Esprit Trust and Esprit subsequent to October 2, 2006.

The following unaudited pro forma information provides an indication of what Pengrowth’s results of operations might have been under U.S. GAAP, had the business combination taken place on January 1, 2006:

	Pro Forma
	(unaudited)
Oil and gas sales	$	1,458,370
Net income	$	182,661
Net income per trust unit:
Basic	$	0.90
Diluted	$	0.89

(i) 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 is 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, are not material.

The following table summarizes the unrecognized tax benefits under FIN 48:

	2007
Balance, January 1	$	—
Additions based on tax positions related to the current year		17,810
Balance, December 31	$	17,810

The following table summarizes open taxation years, by jurisdiction:

Jurisdiction	Years
Federal(1)		2004 — 2007
Alberta, British Columbia, Saskatchewan and Nova Scotia		2003 — 2007

⁽¹⁾ 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.

118 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(j) New Accounting Pronouncements

In February 2006, FASB issued SFAS No. 155, ‘Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140’ (SFAS 155). SFAS 155 simplifies the accounting for certain hybrid financial instruments under SFAS 133 by permitting fair value remeasurement for financial instruments containing an embedded derivative that otherwise would require separation of the derivative from the financial instrument. SFAS 155 is effective for all financial instruments acquired, issued or subject to a remeasurement event occurring in fiscal years beginning after September 15, 2006. Pengrowth does not expect that SFAS 155 will have a material impact on the financial position, results of operations or cash flows.

In September 2006, FASB issued SFAS No. 157, ‘Fair Value Measurements’ (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value under GAAP and to expand disclosures about fair value measurements. The statement is effective for fair value measures already required or permitted by other standards for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The effective date for SFAS 157 as it relates to fair value measurement requirements for financial assets and liabilities that are not remeasured at fair value on a recurring basis has been deferred to fiscal years beginning on or after December 31, 2008. Pengrowth has not yet determined the impact on the financial position, results of operations or cash flows from SFAS 157.

In February 2007, FASB issues SFAS No. 159, ‘The Fair Value Option for Financial Assets and Liabilities’ (SFAS 159). SFAS 159 permits entities to measure many financial instruments and certain other items at fair value. The statement is effective for years beginning on or after November 15, 2007. Pengrowth has not yet determined the impact on the financial position, results of operations or cash flows from SFAS 157.

In December 2007, the 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 material impact on the financial position, results of operations or cash flows.

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 119

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	2007			2006
Net income, as reported	$	359,652		$	262,303
Adjustments:
Depletion and depreciation (a)		35,761			23,997
Ceiling test write down under U.S. GAAP (a)		—			(114,212	)
Unrealized gain (loss) on ineffective portion of oil and natural gas hedges (c)		—			255
Reclassification of hedging losses on foreign exchange swap from other comprehensive income (c)		—			13,631
Deferred foreign exchange loss (c)		(242	)		(13,631	)
Non-cash interest on convertible debentures (g)		69			(29	)
Amortization of discontinued hedge (c)		272			—
Future tax adjustments (e)(i)		69,040			—
Net income — U.S. GAAP	$	464,552		$	172,314
Other comprehensive income (b):
Unrealized gain on foreign exchange swap (c)		—			16,077
Unrealized hedging gain (c)		—			18,153
Reclassification to net income (c)		—			(13,631	)
Amortization of discontinued hedge (c)		(272	)		—
Comprehensive income — U.S. GAAP	$	464,280		$	192,913
Net income — U.S. GAAP — Basic and diluted	$	1.89		$	0.98

120 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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)

	As		Increase
As at December 31, 2007	Reported		(Decrease)			U.S. GAAP
Assets
Property, plant and equipment (a)	$	4,306,682	$	(246,673	)	$	4,060,009
			$	(246,673	)
Liabilities
Convertible debentures (g)	$	75,030	$	120		$	75,150
Future income taxes (e) (i)		387,100		(86,850	)		300,250
Other long term liabilities (i)		—		17,810			17,810
Unitholders’ equity (d):
Accumulated other comprehensive income (b)(c)	$	—	$	2,174		$	2,174
Trust Unitholders’ Equity (a)		2,756,220		(179,927	)		2,576,293
			$	(246,673	)

	As		Increase
As at December 31, 2006	Reported		(Decrease)			U.S. GAAP
Assets
Current portion of unrealized foreign exchange gain (c)	$	—	$	1,559		$	1,559
Other assets (c)		36,132		(1,317	)		34,815
Property, plant and equipment (a)		3,741,602		(282,434	)		3,459,168
			$	(282,192	)
Liabilities
Convertible debentures (g)	$	75,127	$	189		$	75,316
Unitholders’ equity (d):
Accumulated other comprehensive income (b)(c)	$	—	$	2,446		$	2,446
Trust Unitholders’ Equity (a)		3,049,677		(284,827	)		2,764,850
			$	(282,192	)

PENGROWTH 2007 ANNUAL REPORT — Notes to Consolidated Financial Statements 121

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ADDITIONAL DISCLOSURES REQUIRED UNDER U.S. GAAP

The components of accounts receivable are as follows:

As at December 31	2007		2006
Trade	$	179,253	$	145,680
Prepaids		27,330		23,972
Other		—		2,224
	$	206,583	$	171,876

The components of accounts payable and accrued liabilities are as follows:

As at December 31	2007		2006
Accounts payable	$	93,180	$	93,788
Accrued liabilities		145,911		127,425
	$	239,091	$	221,213

122 Notes to Consolidated Financial Statements — PENGROWTH 2007 ANNUAL REPORT

APPENDIX D

COMMENTS BY AUDITORS FOR US READERS
ON CANADA-US REPORTING DIFFERENCES

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Pengrowth Energy Trust’s financial statements, such as the change described in note 3 to the consolidated financial statements as at December 31, 2007 and 2006 and for the years then ended. Our report to the unitholders dated March 3, 2008 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

/s/ KPMG LLP

Chartered Accountants
Calgary, Canada
March 3, 2008

APPENDIX E

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, 2007 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.

(thousands of dollars)	2007		2006
Revenue
Sales	$	1,422,148	$	988,238
Deduct
Production costs		378,216		253,162
Transportation costs		12,672		7,621
Amortization of injectant costs		34,063		34,644
Technical support and other		28,306		17,357
Depletion, depreciation and amortization		603,323		327,578
Results of operations from producing activities	$	365,568	$	347,876

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:

	2007		2006
	(thousands of dollars)
Property Acquisition Costs
Proved	$	986,148	$	1,333,666
Unproved		383,355		440,357
Exploration Costs		21,192		8,900
Development Costs		288,277		275,705
Injectant Costs		26,052		34,630
	$	1,705,024	$	2,093,258

Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

Development costs include the costs of drilling and equipping development wells and 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 as 24 to 30 months.

Pengrowth capitalizes a portion of general and administrative costs associated with exploration activities and development activities. Transaction costs directly attributable to successful acquisitions are also capitalized.

There were no oil and gas property costs not being amortized in any of the years presented.

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:

(thousands of dollars)	2007			2006
Oil and gas properties	$	6,578,258		$	5,400,601
Less accumulated depletion, depreciation and amortization		(2,540,283	)		(1,941,433	)
Net capitalized costs	$	4,037,975		$	3,459,168

(thousands of dollars)	2007		2006
Unproven oil and gas properties	$	1,065,519	$	471,820
Proven oil and gas properties		2,972,456		2,987,348
Net capitalized costs	$	4,037,975	$	3,459,168

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:

	Crude Oil
	and Natural			Natural
	Gas Liquids			Gas
	MMbbls			Bcf
NET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIES
End of year 2005		88.2			333.5
Revision of previous estimates		5.5			9.6
Purchase of reserves in place		18.2			184.7
Sales of reserves in place		(0.4	)		(8.0	)
Discoveries and extensions		0.8			23.9
Production		(10.1	)		(51.8	)
End of year 2006		102.2			491.9
Revision of previous estimates		4.5			34.2
Purchase of reserves in place		20.6			133.4
Sales 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
NET PROVED DEVELOPED RESERVES AFTER ROYALTIES
End of year 2005		70.4			309.3
End of year 2006		84.1			453.1
End of year 2007		93.0			474.9

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. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and 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, 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/mcf. The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2006 was based on the following benchmark prices; Edmonton par crude oil price of $67.58/bbl and AECO natural gas price of $6.07 /mcf.

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.

	2007			2006
	(millions of dollars)
Future cash inflows	$	12,796		$	9,480
Future costs
Future production and development costs		(4,957	)		(4,162	)
Future income taxes (1)		(2,000	)		—
Future net cash flows		5,839			5,318
Deduct: 10% annual discount factor		(2,149	)		(2,152	)
Standardized measure of discounted future net cash flows	$	3,690		$	3,166

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.

	2007			2006
	(millions of dollars)
Future discounted net cash flows at beginning of year	$	3,166		$	3,344
Sales and transfer, net of production costs		(970	)		(676	)
Net change in sales and transfer prices, net of production costs		1,111			(637	)
Development costs during the year		271			284
Changes in estimated future development costs		(346	)		(355	)
Changes due to extensions and discoveries		130			83
Changes due to revisions (including infill drilling and improved recovery)		234			129
Accretion of discount		317			334
Sales of reserves in place		(303	)		(40	)
Purchase of reserves in place		983			842
Net changes in income taxes		(895	)		—
Changes in timing of future net cash flows and other		(8	)		(142	)
End of Year	$	3,690		$	3,166

Note:

1. The schedules above are calculated using year-end prices, costs, statutory tax rates and existing 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 F

PENGROWTH ENERGY TRUST CODE OF BUSINESS CONDUCT AND ETHICS
DATED FEBRUARY 19, 2008

Pengrowth Energy Trust

CODE OF BUSINESS CONDUCT AND ETHICS

February 19, 2008

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. Any violations of this Code must be promptly reported to an appropriate person as outlined in Appendix “A”.

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 behavior expected from employees and contractors in all circumstances.

Members are expected to comply with all aspects of this Code.

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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 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.

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, the individual should immediately seek the advice of his or her manager.

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 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.

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Pengrowth, as well as individual employees, officers and directors, 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. Employees 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 employees 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 officers and employees 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 shareholders and other members of the investment community.

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:

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• 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 Pengrowth Corporation 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.

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

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Chair of the Corporate Governance Committee (or, in the case of the Chair 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 Pengrowth Corporation 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 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

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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 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.

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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 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 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.

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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 directors, officers and employees:

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.

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”.

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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 Securities by Directors, Officers and Employeesof 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 thePublic Disclosure Policy, Electronic Communications and Related Proceduresof Pengrowth Energy Trust.

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.

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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 company.

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 behavior 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”.

Acknowledgement

It is essential that all Members of Pengrowth understand and adhere to this Code.

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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 Accounting Matters may report their concerns to the Chairman of the Audit Committee.

• Directors, officers, employees, consultants or contractors with concerns regarding Conduct Matter may report their concerns to the Chairman of the Corporate Governance Committee.

• Directors, officers and employees may report concerns regarding Accounting Matters or Conduct Matters 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 Accounting Matters or Conduct Matters and (ii) when possible, acknowledge receipt of the complaint to the sender.

• Complaints relating to Accounting Matters 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 Conduct Matters will be reviewed by the Corporate Governance Committee, outside legal counsel and such other 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 Accounting Matters or Conduct Matters.

• 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 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 19, 2008.

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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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