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, 2005		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		(I.R.S. Employer
Classification Code Number)		Identification Number)

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

Vinson & Elkins L.L.P.
2300 First City Tower, 1001 Fannin
Houston, Texas 77002-6760
(713) 758-2222
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

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

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

None

None

     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 77,524,673 Class A Trust Units, of no par value, outstanding as of December 31, 2005.

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

Yes     o		No     þ

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

Yes     þ		No     o

 

 

DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT

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

Appendix		Documents
A		Pengrowth Energy Trust Annual Information Form for the year ended December 31, 2005.
B		Management’s Discussion and Analysis (included on pages 54 through 80 of the Pengrowth Energy Trust 2005 Annual Report).
C		Consolidated Financial Statements of Pengrowth Energy Trust, including note 20 thereof which includes a reconciliation of the Consolidated Financial Statements to United States generally accepted accounting principles.
D		Five Year Review — Pengrowth Energy Trust Consolidated Financial Results (included on pages 115 through 119 of the Pengrowth Energy Trust 2005 Annual Report).
E		Corporate Governance (included on pages 48 through 53 of the Pengrowth Energy Trust 2005 Annual Report).
F		Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”.

CONTROLS AND PROCEDURES

     As of the end of the period covered by this report, an evaluation was carried out under the supervision, and with the participation, of the Registrant’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Registrant’s disclosure controls and procedures, as that term is defined in Rules 13a - 15(e) and 15d - 15(e). Based on that evaluation, the Registrant’s Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective to ensure that material information required to be disclosed by the Registrant in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms.

     During the fiscal year ended December 31, 2005, 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. It should be noted that any system of controls, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems, there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.

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.

GOVERNANCE DISCLOSURE INCORPORATED BY REFERENCE

     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, off-balance sheet arrangements and contractual obligations, is included on pages    ·    through    ·    of the Annual Information Form contained in Appendix A and incorporated herein.

UNDERTAKING

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

SIGNATURES

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

APPENDIX A

PENGROWTH ENERGY TRUST

ANNUAL INFORMATION FORM

Pengrowth Energy Trust is an energy investment trust formed under the laws of the Province of Alberta which offers and sells its trust units to the public. The trust units are not “deposits” within the meaning of the Canadian Deposit Insurance Corporation Act (Canada) (“CDIC Act”) and are not insured under the provisions of the CDIC Act or any other legislation. Furthermore, Pengrowth Energy 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 the business of a trust company.

March 29, 2006

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS			1
CONVERSION			4
PRESENTATION OF OUR FINANCIAL INFORMATION			4
PRESENTATION OF OUR RESERVE INFORMATION			4
FORWARD-LOOKING STATEMENTS			5
PENGROWTH ENERGY TRUST			6
GENERAL DEVELOPMENT OF PENGROWTH TRUST			6
Organization and Structure			6
Business Strategy and Strengths			7
Historical Development			8
Recent Acquisitions, Financings and Developments			11
Trends			12
PENGROWTH MANAGEMENT LIMITED			13
Business			13
Management Agreement			13
Management Agreement Second Term			15
PENGROWTH CORPORATION — OPERATIONAL INFORMATION			15
Principal Properties			16
Additional Information Relating to Reserves Data			32
Finding, Development and Acquisition Costs			34
FD&A Costs — Company Interest Reserves			35
Other Oil and Gas Information			35
Production			38
Replacement of Properties			40
Borrowing			40
TRUST UNITS			41
The Trust Indenture			41
The Trustee			41
Redemption Right			42
Voting at Meetings of Pengrowth Trust			42
Voting at Meetings of Pengrowth Corporation			42
Termination of Pengrowth Trust			42
Unitholder Limited Liability			43
Special Voting Unit			43
Trust Unit Reclassification			43
Background			43
THE ROYALTY INDENTURE			48
Royalty Units			48
The Royalty			49
The Trustee			49
EXCHANGEABLE SHARES			50
DISTRIBUTIONS			50

INDUSTRY CONDITIONS			51
Government Regulation			51
Pricing and Marketing — Oil			51
Pricing and Marketing — Natural Gas			51
Pricing and Marketing — Natural Gas Liquids			52
The North American Free Trade Agreement			52
Provincial Royalties and Incentives			52
Environmental Regulation			54
MARKET FOR SECURITIES			55
Class A Trust Units			55
Class B Trust Units			55
DIRECTORS AND OFFICERS			56
Directors and Officers of Pengrowth Management Limited			56
Principal Holders of Shares of Pengrowth Management			56
Directors and Officers of the Corporation			57
Corporate Cease Trade Orders or Bankruptcies			58
Personal Bankruptcies			58
Penalties or Sanctions			58
AUDIT COMMITTEE			59
Principal Accountant Fees and Services			60
Pre-approval Policies and Procedures			60
RISK FACTORS			60
CONFLICTS OF INTEREST			71
LEGAL PROCEEDINGS			72
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			72
INTERESTS OF EXPERTS			72
AUDITORS, TRANSFER AGENT AND REGISTRAR			72
MATERIAL CONTRACTS			73
CODE OF ETHICS			73
OFF-BALANCE SHEET ARRANGEMENTS			73
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS			73
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE			73
ADDITIONAL INFORMATION			75

APPENDIX A			A-1
Report On Reserves Data By Independent
Qualified Reserves Evaluations On Form 51-101F2
APPENDIX B			B-1
Report Of Management And Directors On
Oil And Gas Disclosure On Form 51-101F3
APPENDIX C			C-1

     Audit Committee Charter

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2005.

GLOSSARY OF TERMS AND ABBREVIATIONS

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

Corporate

	•		Board of Directors refers to the board of directors of the Corporation;
	•		Computershare refers to Computershare Trust Company of Canada;
	•		Corporation refers to Pengrowth Corporation, the administrator of the Trust;
	•		Pengrowth, we, us and our refers to the Trust and the Corporation on a consolidated basis;
	•		Manager refers to Pengrowth Management Limited, the manager of the Trust and the Corporation;
	•		Reclassification means the reclassification of our outstanding Trust Units as Class B Trust Units and the conversion of Class B Trust Units held by non-residents of Canada to Class A Trust Units which occurred on July 27, 2004;
	•		Trust refers to Pengrowth Energy Trust;
	•		Trust Units, when used in reference to any time before 5:00 p.m. Eastern Daylight Time on July 27, 2004, refers to the Trust Units of the Trust as they existed before the Reclassification, and when used in reference to any time after 5:00 p.m. Eastern Daylight Time on July 27, 2004, refers to the Class A Trust Units and the Class B Trust Units of the Trust as well as the Trust Units of the Trust that remain as they existed before the Reclassification; and
	•		Unitholders refers to holders of Trust Units issued by the Trust.

Engineering

	•		Company Gross Interest or Pengrowth Gross Interest refers to the Working Interest share of reserves prior to the deduction of interests owned by others (burdens). Company Royalty Interest reserves are not included in the Company Gross Interest reserves;
	•		Company Net Interest or Pengrowth Net Interest refers to Pengrowth’s Working Interest share of production or reserves, as the case may be, after the deduction of royalties and including Company Royalty Interest reserves, and, with respect to land and wells, refers to Pengrowth’s Working Interest share therein;
	•		Company Royalty Interest refers to an 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;
	•		Developed Non-Producing Reserves refers to those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown;
	•		Developed Producing Reserves refers to those reserves expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production and the date of resumption of production must be known with reasonable certainty;
	•		Developed Reserves refers to those reserves that are expected to be recovered from existing wells and facilities or, if facilities have not been installed, that would involve a low expenditure to put the reserves on production. The developed category may be subdivided into producing and non-producing;
	•		GLJ refers to GLJ Petroleum Consultants Ltd., independent petroleum consultants, Calgary, Alberta;
	•		GLJ Report refers to the report prepared by GLJ dated February 17, 2006, having an effective date of December 31, 2005;

	•		Gross with respect to production and reserves refers to the total production and reserves attributable to a property before the deduction of royalties and with respect to land and wells refers to the total number of acres or wells, as the case may be, in which Pengrowth has a Working Interest or a royalty interest;
	•		Net refers to Pengrowth’s Working Interest share of production or reserves, as the case may be, after the deduction of royalties, and, with respect to land and wells, refers to Pengrowth’s Working Interest share therein;
	•		Pengrowth Company Interest is equal to Company Gross Interest plus Company Royalty Interest. That is, the Working Interest share of production or reserves prior to the deduction of interests owned by others (burdens) plus the interest in production made from gross production or reserves at the wellhead;
	•		Pengrowth Total Proved Plus Probable Reserves means Company Interest share of the Total Proved Plus Probable Reserves;
	•		Probable Reserves refers to those additional reserves that are less likely to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves;
	•		Proved Reserves refers to those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves;
	•		Reserve Life Index refers to the number of years determined by dividing the aggregate of the reserves of a property by the estimated production per year from such property using estimated production for the year 2006 as a reference;
	•		Reserves refers to estimated remaining quantities of oil and natural gas and related substances anticipated to be recovered from known accumulations, from a given date forward, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and specified economic conditions which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimate (e.g., proved, probable);
	•		Total Proved Plus Probable Reserves means the aggregate of Proved Reserves and Probable Reserves before the deduction of royalties;
	•		Undeveloped Reserves refers to those reserves expected to be produced 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 reserve classification (proved, probable) to which they are assigned;
	•		Unitization refers to a process whereby owners of adjoining properties pool reserves into a single unit operated by one of the owners, typically in order to conduct secondary recovery projects in a manner that promotes improved recovery of reserves from a pool or field; and
	•		Working Interest refers to the percentage of undivided interest held by Pengrowth in an oil and gas property.

Abbreviations

	•		API means American Petroleum Institute;
	•		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; barrels of oil equivalent may be misleading, particularly if used in isolation; a conversion ratio of 6 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;
	•		boepd refers to barrels of oil equivalent per day;
	•		CBM refers to coal bed methane;
	•		EOR refers to enhanced oil recovery;
	•		$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; and
	•		TSX refers to the Toronto Stock Exchange.

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.

PRESENTATION OF OUR FINANCIAL INFORMATION

Financial information in this Annual Information Form has been prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada. Canadian GAAP differs in some significant respects from U.S. GAAP and thus our financial statements may not be comparable to the financial statements of U.S. companies. The principal differences as they apply to us are summarized in note 20 to the audited annual consolidated financial statements of the Trust which are available on the SEDAR website at www.sedar.com and in our Form 40-F which is available through EDGAR at the United States Securities and Exchange Commission’s website at www.sec.gov.

PRESENTATION OF OUR RESERVE INFORMATION

The United States Securities and Exchange Commission (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. In 2003, the securities regulatory authorities in Canada (other than Québec) adopted National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves but also probable reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable reserves are of a higher risk and are less likely to be accurately estimated or recovered than proved reserves. Because we are permitted to prepare this Annual Information Form in accordance with Canadian disclosure requirements, we have disclosed in this Annual Information Form and in the documents incorporated by reference reserves designated as “probable”. If this Annual Information Form was required to be prepared in accordance with U.S. disclosure requirements, the SEC’s guidelines would prohibit reserves in these categories from being included. Moreover, in accordance with Canadian practice, we have determined and disclosed estimated future net cash flow from our reserves using both escalated and constant prices and costs; for the constant prices and costs case, prices and costs in effect as of December 31, 2005 were held constant for the economic life of the reserves. The SEC does not permit the disclosure of estimated future net cash flow from reserves based on escalating prices and costs and generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. For a description of these and additional differences between Canadian and U.S. standards of reporting reserves (see page 66 “Risk Factors — Canadian and United States practices differ in reporting reserves and production”). Additional information prepared in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities” relating to our oil and gas reserves is set forth in our Form 40-F which is available through EDGAR at the SEC’s website at www.sec.gov.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains forward-looking statements within the meaning of securities laws, including the “safe harbour” provisions of the Ontario Securities Act 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”, “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: business strategy and strengths, goals, focus and the effects thereof, acquisition criteria, capital expenditures, reserves, reserve life indices, estimated production, remaining producing reserve lives, 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, abandonment and reclamation costs, government royalty rates and expiring acreage. Statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can profitably be produced in the future.

Forward-looking statements and information are based on Pengrowth’s current beliefs as well as assumptions made by and information currently available to Pengrowth concerning anticipated financial performance, business prospects, strategies and regulatory developments. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.

By their very nature, forward-looking statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in such forward-looking statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs and capital expenditures; the imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids; Pengrowth’s ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax laws; the failure to qualify as a mutual fund trust; and Pengrowth’s ability to access external sources of debt and equity capital. Further information regarding these factors may be found under the heading “Business Risks” in our management’s discussion and analysis for the year ended December 31, 2005 and under “Risk Factors” herein.

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

PENGROWTH ENERGY TRUST

The Trust is an oil and gas royalty trust that was created under the laws of the Province of Alberta on December 2, 1988. The Trust is governed by a trust indenture dated July 27, 2004 (amending and restating the trust indenture dated June 17, 2003 and subject to further amendments authorized by Unitholders on April 26, 2005), between the Corporation and Computershare, as trustee. In 1996, the Trust’s original name, “Pengrowth Gas Income Fund”, was changed to “Pengrowth Energy Trust”. The purpose of the Trust is to purchase and hold royalty units issued by the Corporation, its majority owned subsidiary, and to issue Trust Units to members of the public. The Corporation acquires, owns and manages Working Interests and royalty interests in oil and natural gas properties as well as oil and gas processing facilities. The beneficiaries of the Trust are the Unitholders.

The Corporation was created under the laws of the Province of Alberta on December 30, 1987. In 1998, the name of the Corporation was changed from “Pengrowth Gas Corporation” to “Pengrowth Corporation”. The Corporation has 1,100 common shares outstanding, 1,000 of which are owned by the Trust and 100 of which are owned by the Manager. The Corporation has its head and registered offices at 2900, 240 — 4th Avenue S.W., Calgary, AB T2P 4H4.

The Manager was created under the laws of the Province of Alberta on December 16, 1982 as Pengrowth Management Limited. The Manager serves as the manager of the Trust and as the manager of the Corporation.

GENERAL DEVELOPMENT OF PENGROWTH TRUST

Organization and Structure

Under the royalty indenture between the Corporation and Computershare, as trustee, the Corporation has granted a royalty consisting of a 99 percent share of “royalty income” to the holders of royalty units. The royalty units represent fractional undivided interests in the royalty.

Under the trust indenture between the Corporation and Computershare, as trustee, the Trust has issued Trust Units to the Unitholders. Each Trust Unit represents a fractional undivided beneficial interest in the Trust. Our Unitholders are entitled to receive monthly distributions in respect of the royalty and in respect of investments that are held directly by us.

The Trust presently holds approximately 99.9 percent of the royalty units issued by the Corporation. In addition, the Trust holds other permitted investments, such as oil and gas processing facilities, debt obligations of the Corporation and its affiliates and cash.

The Corporation directly and indirectly 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” (on page 48) related to the oil and natural gas interests of the Corporation.

The Corporation owns all of the issued and outstanding shares of Stellar Resources Limited (“Stellar”), a corporation incorporated under the laws of the Province of Alberta. Stellar holds a 0.01 percent partnership interest in three partnerships, Pengrowth Heavy Oil Partnership, Pengrowth Energy Partnership and Crispin Energy Partnership and acts as the general partner of the partnerships. The remaining 99.99 percent partnership interest in each of the partnerships is held by the Corporation. Pengrowth Heavy Oil Partnership and Pengrowth Energy Partnership were acquired in connection with the acquisition of certain properties from Murphy. Crispin Energy Partnership was acquired during 2005 in connection with the acquisition of Crispin Energy Inc. (“Crispin”).

Pursuant to the unanimous shareholder agreement dated June 17, 2003 (amending and restating the unanimous shareholder agreement dated April 23, 2002 and subject to amendments authorized by Unitholders on April 22, 2004 and April 26, 2005) among the Manager, the Trust, the Corporation and Computershare, our Unitholders and holders of royalty units (other than Computershare) are entitled to notice of, and to attend, all meetings of shareholders of the Corporation and vote as shareholders at all meetings of the shareholders of the Corporation to the same extent as if they were holders of common shares of the Corporation in respect of all matters upon which the Business

Corporations Act (Alberta) requires a shareholder vote including voting on the election of the directors of the Corporation (other than the two directors to be appointed by the Manager), appointing its auditors and appointing the auditor of the Trust. In addition, our Unitholders are entitled to vote on any proposed amendment to the unanimous shareholder agreement.

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 to the Corporation. In particular, the Manager also manages and provides services relating to the acquisition 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 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 the Manager.

The following chart illustrates the organization and structure of Pengrowth:

Note:

(1)		These properties were acquired on May 31, 2004 in an acquisition from Murphy Oil which had interests in oil and natural gas assets in Alberta and
(2)		These properties were acquired on April29, 2005 in the acquisition of Crispin.

Business Strategy and Strengths

Our goal is to maximize cash distributions on a per Trust Unit basis to our Unitholders over time while enhancing the value of our Trust Units. We engage in limited exploration for oil and natural gas. Instead, we focus on making accretive acquisitions, adding reserves and production through development drilling, and maximizing the value of

our mature property base by reducing operating costs, implementing new development technologies, such as tertiary recovery operations, and implementing other operational efficiencies.

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

Financial

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

Operational

•

Properties to be acquired should be high quality, relatively long life and proven producing properties. The Corporation 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		relatively long reserve life;
	o		potential synergies with our current properties and areas of our core expertise; and
	o		low environmental and site remediation risk.

Independent Verification

•

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

Our structure, tax effectiveness and cost of capital allow us to bid competitively for oil and natural gas properties relative to taxable corporations and other taxable entities. Opportunities to acquire oil and gas properties generally arise from sellers looking to reduce indebtedness, seeking funds for higher risk exploration and development activities, exiting the business, or fulfilling other strategic objectives.

Historical Development

The Corporation’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, Alberta in the Peace River Arch. The Corporation financed the acquisition by issuing 1,250,000 royalty units at a price of $10.00 per royalty unit, substantially all of which were issued to the Trust. The Trust issued 1,243,500 Trust Units to the public at a price of $10.00 per Trust Unit for gross proceeds of $12,435,000 which were used to pay for the royalty units. An additional 56,500 royalty units were also

issued in the public offering. Of these additional royalty units, 18,240 royalty units were outstanding as of December 31, 2005.

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

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

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

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

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

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

Effective June 15, 2001, the Corporation acquired a royalty representing substantially all of the beneficial interest in the natural gas and liquids production from an 8.4 percent Working Interest in the Sable Offshore Energy Project (“SOEP”) 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 SOEP production facilities downstream of Thebaud Central Platform from SOEP 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 (“SDLs”) for $4.5 million plus a 10 percent Net Profit Interest to NSRL. In December 2003 Pengrowth acquired from Emera Offshore Incorporated (and its subsidiaries, associates and affiliates on a consolidated basis) (“Emera”) their 8.4 percent interest in the SOEP 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 SOEP.

On June 4, 2002, the Trust issued 8,000,000 Trust Units at a price of $15.40 per Trust Unit for total gross proceeds of $123.2 million.

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

In November, 2002, the Trust completed a cross-border equity offering in Canada and the United States of 20,125,000 Trust Units at $14.00 per Trust Unit (U.S. $8.93 per unit) for gross proceeds of approximately

$281.8 million. In total, two public Trust Unit offerings completed during 2002 raised $380 million in net equity proceeds.

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 notes were offered in two tranches: U.S. $150 million at 4.93 percent due April 23, 2010 and U.S. $50 million at 5.47 percent due April 23, 2013. Interest on the notes is payable semi-annually.

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

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

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

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

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

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

On April 29, 2005, pursuant to a Plan of Arrangement under the Business Corporations Act (Alberta), Pengrowth completed the acquisition of Crispin 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.

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. 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.

On January 12, 2006, Pengrowth announced transactions with Monterey Exploration Ltd. (“Monterey”) under which Pengrowth sold approximately 1,000 boepd of non-core production for $22 million cash and 8 million shares in Monterey and farmed out acreage in northeast British Columbia under terms that include our ability to participate in exploration activities in conjunction with Monterey. As at March 24, 2006, Pengrowth holds approximately 34 percent of the common shares of Monterey.

Since the formation of Pengrowth in 1988, Pengrowth has completed a total of 18 public equity financings for gross proceeds of approximately $2.3 billion.

Recent Acquisitions, Financings and Developments

2006 Forecast Capital, Production and Operating Costs

On November 29, 2005, the Board of Directors of the Corporation approved Pengrowth’s 2006 Capital Expenditure Program of up to $236 million. Pengrowth will continue to develop the Judy Creek miscible flood program through a combination of infill drilling and new horizontal injection wells. In northeast British Columbia, Pengrowth will focus on new gas wells and further development of existing waterflood programs. Pengrowth also anticipates an additional well being drilled and increased compression being installed at SOEP. Several drilling opportunities in both heavy oil and shallow gas in Southern Alberta are anticipated to be completed in 2006.

Pengrowth expects to fund the 2006 Capital Expenditures Program through a combination of undistributed cash from operations, unused credit facilities, dividend reinvestment program proceeds rights and options proceeds and any proceeds from property dispositions.

The table below describes the forecasted capital, production and operating costs for 2006:

PLANNED CAPITAL EXPENDITURES		$ MILLIONS				% OF TOTAL
Drilling expenditures			131				56
Facilities and maintenance			64				27
Land and seismic			21				9
Recompletions and workovers			12				5
Other			8				3
TOTAL			236				100
Average daily production volume (boepd)			54,000 - 56,000(1)
Operating costs per boe			$ 11.00(2)

Notes:

1.		After the divestiture of approximately 1,300 boepd of production in the first quarter of 2006 comprised of volumes associated with previously disclosed purchase and sale agreements, as well as the divestment of approximately 1,000 boepd of production related to the Monterey transactions announced on January 12, 2006. The 2006 estimate excludes potential additions through acquisition.
2.		Assuming the production targets for 2006 are achieved.

Borrowing and Note Payable

The Corporation has a $370 million revolving unsecured credit facility syndicated among eight financial institutions with an extendible 364 day revolving period and a three year amortization term period. The revolving credit facility will revolve until June 16, 2006, whereupon it may be renewed for a further 364 days, subject to satisfactory review by the lenders, or converted into a term facility. If converted to a term facility, one third of the amount outstanding would be repaid in equal quarterly instalments in each of the first two years with the final one third to be repaid upon maturity of the term period. In addition, the Corporation has a $35 million demand operating line of credit. As of March 24, 2006, an aggregate of $11 million was drawn on these facilities which are also reduced by outstanding letters of credit in the amount of approximately $17 million. In addition, a note payable is due to Emera in respect to the acquisition of the SOEP facilities. The note is secured by Pengrowth’s Working Interest in SOEP. It is a non-interest bearing note with the final $20 million payment due on December 31, 2006.

U.K. 10 Year Term Notes

On December 1, 2005, Pengrowth completed a £50 million private placement of senior unsecured 10 year notes to a group of U.K. based investors. 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. We enter into term loans from time to time to diversity our sources of debt and to stagger repayment over time.

Crispin Acquisition

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

Monterey Transaction

On January 12, 2006, Pengrowth announced certain transactions with Monterey under which Pengrowth sold approximately 1,000 boepd of production for $22 million of cash and 8 million shares in Monterey and farmed out acreage in northeast British Columbia under terms that include our ability to participate in exploration activities in conjunction with Monterey. As at March 24, 2006, Pengrowth holds approximately 34 percent of the common shares of Monterey.

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

Formation of Special Committee to Examine Dual Class Structure

On March 23, 2006 the Trust received a letter from the Department of Finance (Canada) confirming that it remains the intention of the Department of Finance to recommend to the Minister of Finance the changes to the Tax Act contained in the comfort letter the Department provided to the Trust dated November 26, 2004. The Department of Finance undertook therein to recommend to the Minister of Finance that an amendment be made to the Property Test (as defined herein) that would clarify the Trust’s ability to rely upon that test and effectively remove any significant risk regarding the status of the Trust as a mutual fund trust.

On March 27, 2006 Pengrowth announced the formation of a special committee of the Board of Directors to make recommendations to the Board of Directors. The mandate of the special committee includes examining alternatives to that structure including the removal of the restriction from the Class B Trust Units, the merger of the Class A Trust Units and the Class B Trust Units into a single class of Trust Units or any other alternatives the committee considers appropriate.

For added information see page 43 “Trust Units — Trust Unit Reclassification — Background”.

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.

The conversion of traditional oil and gas companies into income and royalty trusts continued in 2005. The proliferation of income and royalty trusts, the efforts of these trusts to replace annual production declines, robust oil and natural gas prices and low interest rates have resulted in a very competitive market for the acquisition of oil and gas properties and related assets. There has been a corresponding increase in the valuation parameters for corporate and asset acquisitions, while at the same time income and royalty trusts, including the Trust, have enjoyed favourable access to equity and debt capital markets.

Many Canadian royalty trusts, including Pengrowth, have increased their capital spending on development drilling opportunities and limited exploration prospects in order to replace production. Pengrowth engaged a highly qualified operations team including retaining three new vice presidents in 2005 in the areas of operations, geosciences and strategic planning and reservoir exploitation. We have developed areas of core competency that include EOR, shallow gas, heavy oil and CBM. In recent transactions with Murphy and Crispin, we have enhanced our undeveloped land position. As a result we have an opportunity to add reserves less expensively through development than through the current acquisition market. Thus, expanded development drilling programs have become more important to Pengrowth.

Commodity prices, while volatile, are at high levels compared with historical averages. However, the appreciation of the Canadian dollar in 2005 relative to the U.S. dollar has offset a portion of the economic benefit to Canadian oil and gas producers, including trusts, of these higher prices. Increases or decreases in the Canadian dollar relative to the U.S. dollar also result in decreases or increases, respectively, in net revenue as the main markets for our oil and gas are priced in U.S. dollars or based on pricing linked to U.S. dollars and operating costs are denominated in Canadian dollars. The Canadian dollar has continued its strength into 2006.

For additional information regarding the Trust’s strategy in this business environment, see “Management’s Discussion and Analysis — Outlook” on page 78 of the Trust’s Annual Report for the year ended December 31, 2005.

PENGROWTH MANAGEMENT LIMITED

Business

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

Management Agreement

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

Key elements of the Management Agreement are:

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

o

in the first three-year contract term:

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

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 8 percent per annum over a 3-year period;

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

The responsibilities of the Manager under the Management Agreement include:

	•		reviewing and negotiating acquisitions for the Corporation and the Trust;
	•		providing written reports to the Board of Directors to keep the Corporation fully informed about the acquisition, exploration, development, operation and disposition of properties, the marketing of petroleum substances, risk management practices and forecasts as to market conditions;
	•		supervising the Corporation in connection with it acting as operator of certain of its properties;
	•		arranging for, and negotiating on behalf of, and in the name of, the Corporation all contracts with third parties for the proper management and operation of the properties of the Corporation;
	•		supervising, training and providing leadership to the employees and consultants of the Corporation and assisting in recruitment of key employees of the Corporation;
	•		arranging for professional services for the Corporation and the Trust;
	•		arranging for borrowings by the Corporation and equity issuances by the Trust; and
	•		conducting general Unitholder services, including investor relations, maintaining regulatory compliance, providing information to Unitholders in respect of material changes in the business of the Corporation or the Trust and all other reports required by law, and calling, holding and distributing material in respect of meetings of Unitholders and holders of royalty units.

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

Management Fee

Management fees are calculated on a percentage of “net operating income” (oil and gas sales and other income, less royalties, operating costs, solvent amortization and reclamation funding.) The base fee has been reduced from a sliding scale between 3.5 percent and 2.5 percent, to the new rate of 2 percent on the first $200 million of net operating income and 1 percent on net operating income over $200 million. Acquisition fees were eliminated (effective July 1, 2003), and the Manager is eligible to receive a “performance fee” if certain performance criteria are met. The previous fee arrangements remain relevant however as there is a cap imposed on the fees, including

the performance fee, limiting the aggregate of such fees to 80 percent of the fees that would otherwise have been paid under the old management agreement (inclusive of acquisition fees) for the first three years, and 60 percent for the second three years.

Bonus Pool

As an incentive to officers, employees and special consultants of the Manager (including employees of the Corporation but excluding the President, James S. Kinnear), an annual bonus pool has been established which is carved out from the management fee paid to the Manager, determined as 10 percent of the total fees received by the Manager (i.e. 10 percent of the management fee and any performance fee earned). Bonuses are paid from time to time in accordance with criteria recommended by the Manager as a further incentive for top performing employees.

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 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 Committee recommended to the full Board of Directors that the Management Agreement not be terminated at the end of the first term.

The Committee based its recommendation on several factors including:

	•		The amount of the termination fee payable to the Manager on termination of the Management Agreement effective June 30, 2006;
	•		The estimated cost of internal management to June 30, 2009 in the event of a termination of the Management Agreement effective June 30, 2006;
	•		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 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 ending June 30, 2006; and
	•		The commitment by the Manager to certain key governance standards relating to the conduct of the affairs of the Trust and a continuing commitment to overall corporate governance practices (as such practices would apply to Pengrowth in an internalized management structure); and a further commitment to assist and work with the Board in establishing a plan for the orderly transition to a traditional corporate management structure at the end of the final term of the Management Agreement on June 30, 2009.

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

PENGROWTH CORPORATION — OPERATIONAL INFORMATION

As at December 31, 2005, the Corporation had 303 permanent employees. The Corporation has invested more than $3 billion in the energy sector primarily to purchase mature, proven producing oil and natural gas properties in Canada.

Principal Properties

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

The Corporation obtained the GLJ Report dated February 17, 2006 in respect to the oil and gas properties of the Corporation effective December 31, 2005. All reserve data presented under this sub-heading is based on the GLJ Report.

The Corporation’s producing properties are summarized in the following table:

Summary of Property Interests Held by Pengrowth Corporation as at December 31, 2005⁽³⁾
Forecast Prices and Costs

										Company Interest								2005 Actual
		Remaining				Reserve Life				Total Proved Plus				Value at				Oil Equivalent
		Reserve Life				Index				Probable Reserves(2)				10% Discount				Production(2)
		(Years)				(Years)				(Mboe)				($million)				(boepd)
Judy Creek BHL Unit			50				11.9				36,820				538.1				8,847
Swan Hills Unit No.1			50				21.1				19,903				196.5				2,481
Weyburn Unit			50				18.6				19,253				186.1				2,649
SOEP			11				5.7				15,241				346.1				7,075
Judy Creek West BHL Unit			50				23.1				9,160				81.1				1,415
Monogram Gas Unit			36				8.7				6,265				120.6				2,517
McLeod River			50				7.3				5,480				92.5				2,321
East Bodo			50				28.3				5,252				31.5				542
Dunvegan Gas Unit No. 1			39				9.3				5,154				72.6				1,442
Twining			45				10.3				4,390				63.9				1,360
Kaybob Notikewin Unit No. 1			40				12.8				4,366				53.6				1,048
Tangleflags			18				6.8				4,344				22.8				1,806
Oak			50				10.9				4,030				70.4				1,014
Quirk Creek			35				11.9				3,574				42.7				807
Princess			50				9.0				3,556				65.1				796
Enchant			50				15.3				3,270				37.1				684
Rigel			21				6.7				3,150				73.4				1,625
Other(1)			50				8.9				66,188				1,110.4				20,928
Total			50				10.5				219,396				3,204.5				59,357

Notes:

1.		“Other” includes the Corporation’s working and royalty interest in approximately 100 other properties. 2. Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural gas being equal to one boe.
3.		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.

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

The Corporation holds a 100 percent Working Interest in both the Judy Creek Beaverhill Lake Unit (the “Judy Creek A Pool”) and the Judy Creek West Beaverhill Lake Unit (the “Judy Creek B Pool”), (together, “Judy Creek”). Judy Creek is located approximately 200 kilometres northwest of Edmonton in north-central Alberta and covers an area of approximately 155 square kilometres (60 sections). Judy Creek was discovered in 1959, placed on waterflood (secondary recovery) in 1962 and miscible flood (tertiary recovery) in 1985. Original-oil-in-place totaled 815 mmbbls in the Judy Creek A Pool, making it one of the largest oil pools discovered in western Canada. To December 31, 2005, a total of 353 mmbbls (gross) have been produced from the Judy Creek A Pool. Remaining Total Proved Plus Probable Reserves at December 31, 2005 are estimated at 36.8 mmboe. Original-oil-in-place at the Judy Creek B Pool totaled 262 mmbbls, and at December 31, 2005, 115 mmbbls (gross) have been produced.

The remaining producing reserve life is 50 years and the Reserve Life Index is 11.9 and 23.1 years, respectively for the A and B pools. Pengrowth’s Company Interest production for Judy Creek averaged 10,262 boepd in 2005.

Development Activity

The Corporation operates both the Judy Creek A and B Pools, which are produced using both waterflood and the EOR program that was initiated in 1985. In the Judy Creek hydrocarbon miscible flood, oil production is increased by injecting a hydrocarbon-based solvent (mostly natural gas and ethane) into the reservoir. In 2005, solvent was injected at 11 miscible patterns with anticipated increased oil production from up to 32 producing wells.

Development activity in 2005 was largely focused within the A Pool and included one horizontal solvent injection well, one produced water injector and three oil producers. Three additional drilling locations from the 2005 program were delayed until the first quarter of 2006. The horizontal solvent injector pattern is a follow-up to a similar pattern developed in 2001 which has to date recovered over 750 mbbls of oil.

Drilling and related activities such as well workovers and conversions resulted in the development of four new solvent patterns and one new waterflood pattern in 2005. Six new solvent patterns will be developed in 2006. During 2005 significant upgrades were completed on the Judy Creek A Pool produced water injection system. These proactive upgrades improve the integrity of the system and reduce the potential for line failures and spills. Development plans in 2006 include drilling up to ten new oil wells, three injection wells and eleven gas wells targeting shallow natural gas reservoirs. Other methods of enhancing future production in Judy Creek are being investigated including the use of CO₂ as a solvent.

Natural gas production may also be possible through development of the CBM on Pengrowth’s acreage. Pengrowth entered into an agreement with a prominent CBM company for the farmout of a portion of Pengrowth’s lands at Judy Creek with CBM potential. Several horizontal wells have been drilled on these lands to test the Mannville coal formations.

Swan Hills Unit No. 1

After acquiring an additional 11.89 percent Working Interest in February 2005, Pengrowth holds a 22.34 percent Working Interest in the partner-operated Swan Hills Unit No. 1 located in north central Alberta. At December 31, 2005, GLJ estimates remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 19.9 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 21.1 years. Pengrowth Company Interest production averaged 2,481 boepd in 2005 and exited the year at 2,874 boepd.

Development Activity

In 2005 seven new wells were drilled in the Phase 3 hillslide area of the Unit adding about 560 boepd (gross) to year end production. In addition to the drilling, four wells were reactivated, two wells were acid fracture stimulated and four wells were equipped with larger pumping systems collectively adding a further 750 boepd (gross) to year end production. Although no new hydrocarbon miscible flood patterns were developed in 2005, the Unit continued injecting into three existing patterns.

The 2006 development plans include drilling four new infill wells in the Phase 1 northwest area of the Unit, developing two new miscible flood injection patterns and carrying out a variety of well and pump optimization projects.

The CO₂ miscible flood pilot project has completed seven of nine scheduled injection cycles since starting up in October, 2004. Due to the limited response seen so far at the producing wells, the pilot will probably be extended for at least two additional injection cycles after the originally scheduled nine cycles are completed later in 2006.

Weyburn Unit

Pengrowth holds a 9.76 percent Working Interest in the partner-operated Weyburn Unit in southeast Saskatchewan. Medium gravity oil is produced from the Midale carbonate reservoir under waterflood and a CO₂ miscible flood enhanced recovery scheme. At December 31, 2005, GLJ estimates remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 19.3 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 18.6 years. Pengrowth Company Interest production averaged 2,649 boepd in 2005 and exited the year at 2,813 boepd.

Development Activity

A total of 53 horizontal infill/re-entry wells were drilled in 2005 adding about 7,000 boepd (gross) to year end production. Additionally, eight new CO₂ miscible flood patterns were brought on stream in 2005, bringing the number of active patterns up to 44. Ultimately, 75 patterns are expected to be developed. The Unit secured an additional 30 mmcfpd of CO₂ under a new agreement signed with the supplier in 2005 increasing the total CO₂ supply to 125 mmcfpd. The additional CO₂, scheduled to come on stream in the third quarter of 2006, will allow the Unit to expand the EOR program and should result in higher overall production and ultimate oil recovery.

Building on the success of the 2004 and 2005 infill drilling programs, an additional 40 wells are planned for 2006. The 2006 development program also includes four new CO₂ miscible flood patterns. Higher production volumes have resulted in some infrastructure bottlenecks that will be addressed in 2006; most notably, 90,000 bblpd of water injection pumping capacity will be added (on stream early 2007) and 100 mmcfpd of CO₂ recycle compression capacity will be added (on stream late 2007).

Sable Offshore Energy Project

SOEP involves the development of several natural gas fields near Sable Island which is located approximately 225 kilometres off the east coast of Nova Scotia. Raw gas from SOEP is delivered to the onshore gas plant facility at Goldboro, where the liquids are extracted and sent to the fractionation plant in Point Tupper for processing. Sales gas is transported to market via the Maritimes & Northeast Pipeline. Propane and butane is shipped by both truck and rail while condensate is transported by ship.

As of December 31, 2005, the total SOEP remaining gross Total Proved Plus Probable Reserves are estimated by GLJ to be 841.0 bcf of natural gas and 41.3 mmbbls of NGLs and Pengrowth Company Interest Total Proved Plus Probable Reserves are estimated to be 70.6 bcf of natural gas and 3.5 mmbbls of NGLs. Pengrowth’s Working Interest is 8.4 percent in SOEP. The Pengrowth Company Interest production averaged 32.1 mmcfpd of sales gas and 1,722 bblpd of NGLs and condensate in 2005.

Development Activity

A significant portion of Pengrowth’s capital expenditures on partner-operated properties was invested at SOEP in 2005 with the addition of three new wells. The South Venture 2 well was drilled in 2004 and completed in 2005 while the South Venture 3 and Venture 7 wells were both drilled and completed in 2005.

Capital was also spent on the construction of a 30,000 HP compression project which will be installed at Thebaud in 2006. As of December 31, 2005, fabrication of the compression facilities was approximately 75 percent complete. The compression project involves the fabrication of an additional platform and topsides that will be installed beside the Thebaud platform and connected to Thebaud by a bridge. Installation of the platform and topsides will occur in mid 2006 with start-up scheduled for late 2006. Compression will allow the SOEP fields to be drawn down to much lower pressures allowing for a higher recovery of gas at higher production rates.

Monogram Gas Unit

Pengrowth holds a 53.8 percent Working Interest in the partner-operated Monogram Gas Unit located in southern Alberta. The Monogram Gas Unit produces sweet, dry natural gas from the Medicine Hat, Milk River and Second White Specks formations. At December 31, 2005, GLJ estimates remaining Pengrowth Company Interest Total

Proved Plus Probable Reserves at 6.3 mmboe with a remaining reserve life of 36 years and a Reserve Life Index of 8.7 years. Pengrowth Company Interest production averaged 2,517 boepd in 2005 from 520 wells.

Development Activity

A successful infill drilling program in 2004 consisted of 154 wells and effectively downspaced the unit to eight wells per section. New field and central compression was added, along with main line looping to reduce back pressure on the existing wells. No development drilling occurred in 2005. In 2006, a 20 well refracture program will determine if the original well completions effectively opened all perforated intervals. A 10 well perforation/fracture stimulation program will determine if non-unitized formations contain pay that was by-passed. This could result in the unitization of additional formations within the Unit area. These initiatives, if successful, would add additional reserves and would be incorporated into a potential 100 well infill drilling program that would commence late in 2006.

McLeod River

The McLeod River property is located approximately 110 kilometres west of Edmonton. Production is obtained from the Rock Creek, Gething, Notikewin and Cardium formations.

At December 31, 2005, GLJ estimated remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 5.8 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 7.3 years. Pengrowth Company Interest production averaged 2,321 boepd in 2005.

Development Activity

McLeod River activity will consist of a minor drilling program. Future activity will include facility consolidation.

Bodo/Cactus Lake/Plover

The Bodo, Cactus and Plover heavy oil properties were purchased in the Murphy acquisition and straddle the Alberta-Saskatchewan border. The properties produce mainly 12° API oil from the McLaren and 15° API oil from the Lloydminster reservoirs. The fields have several batteries to treat oil to pipeline specification, as well as a number of compressor stations to process solution and non-associated gas. An active waterflood is underway in East Bodo Lloydminster sands. At December 31, 2005, GLJ estimated remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 13.1 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 8.9 years. Pengrowth Company Interest production averaged 4,330 boepd in 2005.

Pengrowth continues to review uphole gas potential on the acquired lands and has successfully added processing volumes in existing facilities by aggressively pursuing third party opportunities.

Development Activity

East Bodo was an active area in 2005 with three new drills. Four producers will be converted to injectors in the first quarter of 2006. These will increase the level of pressure support to the waterflood. Additionally, a polymer injection skid was commissioned in December 2005 for use in a pilot. Polymer will be used to enhance the waterflood with the potential to add significant incremental waterflood recovery. An additional nine horizontal wells are planned for the third quarter of 2006 in East Bodo (Alberta) and Cosine (Saskatchewan) which are in the same trend. One vertical well was drilled and cased in Cosine in the fourth quarter of 2005.

In South Bodo, a five well horizontal infill drilling program is planned for late in the second quarter of 2006 based on the success of the 2004 program. Three of these wells will be drilled closer to the water-oil-contact to take advantage of gravity drainage to increase the current recovery factor for the pool.

Three to five horizontal wells are planned for late in the fourth quarter of 2006 in Cactus Lake (Saskatchewan) which is the same channel trend as South Bodo (Alberta). A vertical step out well was drilled in late 2005 and cased for two gas horizons in the Plover area. This could also lead to further development.

The Company is actively pursuing various EOR technologies to maximize value. These include Alkaline Surfactant Flooding, Polymer Flooding, Toe to Heel Waterflooding, Solvent Flooding and Steam Assisted Gravity Drainage (SAGD).

Dunvegan Gas Unit No. 1

Pengrowth holds a 7.97 percent Working Interest in Dunvegan Gas Unit No. 1 located 430 kilometres northwest of Edmonton, Alberta in the Peace River area. The partner-operated Dunvegan natural gas field has approximately 180 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. At December 31, 2005, GLJ estimates remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 5.2 mmboe with a remaining reserve life of 39 years and a Reserve Life Index of 9.3 years. In 2005, Pengrowth Company Interest production averaged 1,442 boepd.

Development Activity

A successful infill drilling program that was first initiated in 2003 continued in 2005 with the drilling of 26 additional wells. Although 15 of the new wells remained to be tied-in at year end, results indicated an average production rate exceeding 1 mmcfpd and 1 bcf of gross Reserves per well. Based on the success of this infill program, an additional 23 wells are planned for 2006.

Twining

The Twining Field is located approximately 160 kilometres northeast of Calgary. The primary producing zone is the Pekisko with additional production from the Ellerslie, Glauconite and Belly River zones. At December 31, 2005, GLJ estimated remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 4.4 mmboe with a remaining reserve life of 45 years and a Reserve Life Index of 10.3 years. Pengrowth Company Interest production from the Twining Field averaged 1,360 boepd during 2005.

Pengrowth operates over 100 wells and four main battery facilities in the Twining area. The company also operates the Equity Gas Unit No. 1 and has Working Interests in four partner-operated units.

Development Activity

Since acquiring Murphy’s interests in the Twining area, Pengrowth has been evaluating potential drilling locations. A 3-D seismic program in the first quarter of 2005 helped identify locations for drilling which is expected to start in the second quarter of 2006.

Pengrowth is also monitoring CBM activity in the area including an existing program operated by MGV Energy Inc. on Pengrowth lands under a farmout agreement initiated by Murphy. Pengrowth (via the Murphy acquisition) receives a non-convertible royalty from the Twining Horseshoe Canyon farmout wells. Production commenced in July 2005 with peak production reaching 7.5 mmcfpd from 64 producing wells. MGV’s success has provided Pengrowth the confidence to initiate development on offsetting Working Interest lands. An initial 18 well program (11 net) will commence drilling in the first quarter of 2006 with first sales occurring by the third quarter of 2006. Up to 50 additional wells could be drilled in 2006 based on continued drilling success and pooling arrangements.

Kaybob Notikewin No. 1

Kaybob Notikewin Unit No. 1 produces natural gas and natural gas liquids from the Notikewin formation. Initial production began in 1962. Pengrowth’s ownership in this unit is 98.88 percent. At December 31, 2005, GLJ estimated remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 4.4 mmboe with a remaining reserve life of 40 years and a Reserve Life Index of 12.8 years.

Development Activity

No further activity has been planned for 2006 as the field has been fully developed with the current wells.

Tangleflags

Pengrowth holds a 50 percent Working Interest in the Canadian Natural Resources Limited operated 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.

The EOR project area contains horizontal producing wells along with both vertical and horizontal steam injection wells and commenced operation in the late 1980’s. As steam is injected into the reservoir and oil and water is withdrawn, a steam chamber is created which expands vertically and laterally, heating the reservoir and allowing the oil to drain more easily to the horizontal producing wells located near the base of the reservoir. Ultimately, it is expected that in excess of 70 percent of the original-oil-in-place will be recovered in the EOR project area. Recovery to date is approximately 50 percent. At December 31, 2005, GLJ estimates remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 4.3 mmboe with a remaining reserve life of 18 years and a Reserve Life Index of 6.8 years. Pengrowth Company Interest production averaged 1,806 boepd in 2005.

Development Activity

Five new infill wells are planned in 2006 as well as a hillside stability study on the 9-23 steam plant that has been on-going since 2005. Optimization activities continue in an effort to maintain production and maximize recovery.

Oak

The Oak area is located in northeast British Columbia, approximately 20 kilometres north of Fort St. John. The property consists of 43 operated oil and natural gas wells, eight injection wells and seven water source wells surrounding two batteries and three natural gas compressor facilities. The Corporation also holds a 20.6 percent Working Interest in the non-operated Oak Cecil I Unit No. 1. Production is obtained from the Halfway, Cecil, Baldonnel, Cadomin and Bluesky formations. Two vertical Baldonnel gas wells were drilled in 2005 with one tied-in and the other abandoned.

The Oak C simulation modeling was completed in 2005 to optimize the waterflood performance and resulted in drilling of one infill producer. The Oak B waterflood scheme was approved in early 2004 and water injection began in July, 2004. Since that time there has been significant waterflood response.

At December 31, 2005, GLJ estimated remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 4.0 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 10.9 years. Pengrowth Company Interest production averaged 1,014 boepd in 2005.

Development Activity

An Oak area Baldonnel gas play is proceeding with three proposed drilling locations and two recompletions planned for 2006, and potential follow-up locations based on the success in 2006. An additional infill well in the Oak C pool is also under consideration.

Quirk Creek

The Corporation holds a 68 percent Working Interest in three producing Rundle Formation deep plate gas wells, a 31 percent Working Interest in 10 producing Rundle upper plate gas wells, a 25 percent Working Interest in 3 producing gas wells in Millarville and a 30.5 percent Working Interest in the Quirk Creek natural gas plant located in the Quirk Creek area of Southern Alberta, approximately 30 kilometres southwest of Calgary.

Pengrowth Company Interest production for 2005 was approximately 3.8 mmcfpd of natural gas and 174 bblpd of natural gas liquids. GLJ estimates Pengrowth Company Interest Total Proved Plus Probable Reserves at December 31, 2005 to be 3.6 mmboe, consisting of 17.0 bcf of natural gas and 0.7 mmbbls of NGLs. GLJ estimated a remaining reserve life of 35 years and a Reserve Life Index of 11.9 years. Pengrowth Company Interest production averaged 807 boepd for 2005.

Development Activity

The Corporation is participating in one development Rundle deep plate well in 2006. The operator is evaluating the opportunity for additional third party gas processing revenue in the area. Third party processing revenues in 2005 made up 18 percent of gross revenues for the property.

Princess

The Pengrowth operated Princess property in southeast Alberta covers 38 sections of land with mostly 100 percent Working Interest ownership. The field produces sweet dry gas from stacked sands within the Milk River, Medicine Hat and Second White Specks sequence. The wells are typically low volume, long life producers. The field has two compressor stations with dehydration facilities servicing approximately 230 Pengrowth wells. At December 31, 2005, GLJ estimated remaining Pengrowth Total Proved Plus Probable Reserves of 3.6 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 9.0 years. Pengrowth Company Interest production averaged 796 boepd in 2005. Pengrowth Company Interest production averaged 4.8 mmcfpd of sales gas for the year, but with new wells coming on in November, the 2005 exit rate was 7.1 mmcfpd.

Development Activity

During 2005 Pengrowth drilled 44 infill wells with 100 percent success. Pengrowth has plans to drill another 20 infill wells in 2006 to complete down-spacing to eight wells per section. Further down-spacing will be assessed based on performance.

Enchant

The Enchant property is located approximately 200 kilometres southeast of Calgary. The property consists of four operated oil pools in which the Corporation holds an average 88 percent Working Interest. These pools produce 32°API oil from the Arcs formation.

The Corporation holds a 99 percent Working Interest in the largest pools (the J and VV pool) which consist of 33 producing and 10 injection wells with treating, water handling and gas conservation located at a central battery facility. Primary production commenced in 1992 and a waterflood project was implemented in 1995. As of December 31, 2005, GLJ estimates remaining Pengrowth Company Interest Total Proved Plus Probable Reserves to be 3.3 mmboe with a remaining reserve life of 50 years and a Reserve Life Index of 15.3 years. Pengrowth Company Interest production averaged 684 boepd for 2005.

In the Enchant Arcs Unit No. 2, where the Corporation converted a well to injection in mid-2000, pressure support is now apparent and initial expected water breakthrough is being observed in the oil producers.

Development Activity

The Corporation is currently evaluating drilling up to three potential oil wells in the Arcs Unit No. 2 in 2006 to capture bypassed reserves due to water breakthrough.

Rigel

The Rigel area is located in northeast British Columbia, approximately 40 kilometres north of Fort St. John. The Corporation holds an average 60 percent Working Interest in the property. The property consists of four Cecil oil pools containing 33 oil wells, 16 injection wells and a central battery facility.

Optimization of pumping equipment is ongoing and stimulation of selected injectors will continue to optimize waterflood performance. The Rigel I and H pools are targeted for modeling and simulation work to identify opportunities to optimize the existing waterfloods. At December 31, 2005, GLJ estimated remaining Pengrowth Company Interest Total Proved Plus Probable Reserves of 3.2 mmboe with a remaining reserve life of 21 years and a Reserve Life Index of 6.7 years. Pengrowth Company Interest production averaged 1,625 boepd in 2005.

Development Activity

Three new operated wells and one partner operated well are planned for 2006. One of the operated well targets is a gas cap location resulting from concurrent gas cap production approval obtained for the Rigel H pool in 2005.

Reserves

The effective date of the information in this section is December 31, 2005 and the preparation date of the information is January 16, 2006. The information in this section is based upon an evaluation by GLJ with an effective date of December 31, 2005 contained in the GLJ Report dated February 17, 2006. The information in this section summarizes the oil, liquids and natural gas reserves of Pengrowth Corporation and the net present values of future net revenue for these reserves using GLJ’s constant prices and costs and forecast prices and costs and conforms with requirements of NI 51-101. The Corporation 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 the Corporation’s reserves are in Canada in the provinces of Alberta, British Columbia, Saskatchewan and Nova Scotia (SOEP).

The following tables set forth certain information relating to the oil and natural gas reserves of the Corporation and the present value of the estimated future net cash flow associated with such reserves as at December 31, 2005. The information set forth below is derived from the GLJ Report which has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation 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. All evaluations of future net cash flow are stated prior to any provision for income taxes, interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

In 2003, the securities regulatory authorities in Canada (other than Québec) adopted NI 51-101 which imposed new oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. Under the new reserve categories, reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward based on:

	a.		analysis of drilling, geological, geophysical and engineering data;
	b.		the use of established technology; and
	c.		specified economic conditions.

Reserves are classified according to the degree of certainty associated with the estimates.

	a.		Proved Reserves are 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.
	b.		Probable Reserves are 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.

Reported reserves should target the following levels of certainty under a specific set of economic conditions:

	•		at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
	•		at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to the estimates prepared for the various reserve categories is desirable to provide an understanding of the associated risks and uncertainties. However, the majority of reserve estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

In addition, where there are reserve and future net revenue estimates for less than Pengrowth as a whole, 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.

The Corporation is entitled to claim Alberta Royalty Credits. The Alberta Royalty Credits program is based on a price-sensitive formula linked to crude oil prices. Credits vary from a high of 75 percent of the eligible Alberta Crown Royalties for a taxation year to a maximum of $1,500,000 (75 percent of $2,000,000) when the price of oil falls below U.S. $15 per barrel, to a low of 25 percent (maximum $500,000) when the price of oil rises above U.S. $30 per barrel. Although this program may be expected and is usually assumed to continue indefinitely, the credits are not included in the GLJ forecasts.

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 the Corporation together with an estimate of processing revenues less royalties (net of incentives), mineral taxes, field operating expenses and capital obligations. These net cash flows are not the same as the distributable cash reported by the Trust. The computation of distributable cash is described under the heading “Distributable Cash Distributions and Taxability of Distributions” in the Management’s Discussion and Analysis appearing on page 67 of the Trust’s Annual Report 2005. Significant factors to consider include:

	a.		the GLJ Report does not estimate general and administrative expenses, interest, management fees and holdbacks;
	b.		the GLJ Report does not estimate all abandonment or any reclamation liabilities;
	c.		for purposes of calculating distributable income, the Trust amortizes the cost of miscible flood injection fluids purchased from third parties over the period of expected future economic benefit arising from the injection of those fluids, which had been 30 months and was revised to 24 months for 2005 onward. The GLJ Report includes the full cost of purchased injection fluids ($34.7 million in 2005) in operating costs in the year incurred; and
	d.		the Corporation withholds certain amounts from distributable cash to fund capital.

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

SUMMARY OF OIL AND GAS RESERVES

CONSTANT PRICES AND COSTS

		OIL AND GAS RESERVES
		Light and Medium Oil												Heavy Oil												Natural Gas
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(bcf)				(bcf)				(bcf)
Proved Reserves
Proved Developed Producing			59,164				58,988				50,539				10,860				10,853				9,627				368.0				360.2				290.8
Proved Developed Non-Producing			368				368				311				62				62				57				24.5				24.1				18.5
Proved Undeveloped			18,761				18,748				15,574				1,673				1,673				1,402				31.2				29.3				24.2
Total Proved Reserves			78,292				78,104				66,424				12,595				12,588				11,086				423.7				413.6				333.5
Probable Reserves			21,361				21,324				17,820				3,118				3,117				2,651				94.4				91.1				72.7
Total Proved Plus Probable Reserves			99,653				99,427				84,245				15,713				15,705				13,737				518.1				504.7				406.2

		OIL AND GAS RESERVES
		Natural Gas Liquids												Total Oil Equivalent Basis
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mboe)				(mboe)				(mboe)
Proved Reserves
Proved Developed Producing			13,660				13,478				9,377				145,010				143,348				118,007
Proved Developed Non-Producing			642				633				462				5,149				5,071				3,920
Proved Undeveloped			1,157				1,106				821				26,788				26,419				21,834
Total Proved Reserves			15,459				15,217				10,660				176,948				174,838				143,761
Probable Reserves			3,631				3,552				2,604				43,839				43,180				35,193
Total Proved Plus Probable Reserves			19,090				18,768				13,264				220,788				218,019				178,954

		NET PRESENT VALUES OF FUTURE NET REVENUE
		CONSTANT PRICES AND COSTS BEFORE INCOME TAXES
Reserves Category		DISCOUNTED AT (%/YEAR)
		0% ($MM)				5% ($MM)				10% ($MM)				15% ($MM)				20% ($MM)
Proved Reserves
Proved Developed Producing			4,745.1				3,568.7				2,896.0				2,460.1				2,153.1
Proved Developed Non-Producing			183.2				134.0				106.0				87.7				74.8
Proved Undeveloped			770.4				499.3				342.5				243.7				177.4
Total Proved Reserves			5,698.7				4,202.0				3,344.5				2,791.5				2,405.3
Probable Reserves			1,587.6				904.8				608.7				449.6				351.6
Total Proved Plus Probable Reserves			7,286.3				5,106.8				3,953.2				3,241.1				2,756.9

TOTAL FUTURE NET REVENUE

CONSTANT PRICES AND COSTS

FUTURE NET

CAPITAL

REVENUE

OPERATING

DEVELOPMENT

ABANDONMENT

BEFORE

REVENUE

ROYALTIES

COSTS

COSTS

COSTS(1)

INCOME TAX

Reserves Category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Proved Reserves

10,453

1,988

2,348

318

99

5,699

Total Proved Plus Probable Reserves

13,082

2,523

2,791

379

101

7,286

Note:

FUTURE NET REVENUE

CONSTANT PRICES AND COSTS

				FUTURE NET REVENUE
		PRODUCTION GROUP		BEFORE INCOME TAXES
Reserves Category				(discounted at 10% yr) ($M)
Proved Reserves		Light and Medium Crude Oil (including solution gas and other by-products) (1)			1,666,575
		Heavy Oil (including solution gas and other by-products)(1)			122,962
		Natural Gas (including by-products but excluding solution gas from oil wells) (2)			1,554,956
Total Proved Plus Probable Reserves		Light and Medium Crude Oil (including solution gas and other by-products) (1)			1,977,086
		Heavy Oil (including solution gas and other by-products) (1)			148,256
		Natural Gas (including by-products but excluding solution gas from oil wells) (2)			1,827,831

Notes:

SUMMARY OF OIL AND GAS RESERVES

FORECAST PRICES AND COSTS

		OIL AND GAS RESERVES
		Light and Medium Oil												Heavy Oil												Natural Gas
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(mbbls)				(bcf)				(bcf)				(bcf)
Proved Reserves
Proved Developed Producing			58,219				58,060				49,693				10,924				10,916				9,621				366.2				358.5				289.4
Proved Developed Non-Producing			365				365				308				62				62				57				24.3				23.9				18.4
Proved Undeveloped			18,768				18,755				15,991				1,699				1,699				1,420				30.8				29.0				23.9
Total Proved Reserves			77,351				77,179				65,992				12,684				12,677				11,098				421.3				411.4				331.7
Probable Reserves			21,332				21,296				17,937				3,106				3,104				2,616				94.3				91.0				72.6
Total Proved Plus Probable Reserves			98,684				98,476				83,929				15,790				15,781				13,714				515.6				502.4				404.3

		OIL AND GAS RESERVES
		Natural Gas Liquids												Total Oil Equivalent Basis
		Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth				Pengrowth
		Company				Gross				Net				Company				Gross				Net
		Interest				Interest				Interest				Interest				Interest				Interest
Reserves Category		(mbbls)				(mbbls)				(mbbls)				(mboe)				(mboe)				(mboe)
Proved Reserves
Proved Developed Producing			13,566				13,385				9,334				143,741				142,103				116,877
Proved Developed Non-Producing			637				628				460				5,113				5,035				3,893
Proved Undeveloped			1,139				1,088				805				26,745				26,376				22,200
Total Proved Reserves			15,342				15,101				10,600				175,599				173,513				142,970
Probable Reserves			3,643				3,564				2,617				43,797				43,138				35,276
Total Proved Plus Probable Reserves			18,985				18,665				13,218				219,396				216,652				178,246

		NET PRESENT VALUES OF FUTURE NET REVENUE
		FORECAST PRICES AND COSTS BEFORE INCOME TAXES
Reserves Category		discounted at (%/year)
		0% ($MM)				5% ($MM)				10% ($MM)				15% ($MM)				20% ($MM)
Proved Reserves
Proved Developed Producing			3,676.7				2,871.1				2,401.0				2,089.9				1,865.9
Proved Developed Non-Producing			148.7				109.2				87.6				73.7				63.8
Proved Undeveloped			559.9				347.9				229.6				156.7				108.5
Total Proved Reserves			4,385.3				3,328.2				2,718.2				2,320.3				2,038.2
Probable Reserves			1,308.2				727.9				486.3				359.7				282.8
Total Proved Plus Probable Reserves			5,693.5				4,056.1				3,204.5				2,680.0				2,321.0

TOTAL FUTURE NET REVENUE

FORECAST PRICES AND COSTS

FUTURE NET

CAPITAL

REVENUE

OPERATING

DEVELOPMENT

ABANDONMENT

BEFORE

REVENUE

ROYALTIES

COSTS

COSTS

COSTS (1)

INCOME TAX

Reserves Category

($MM)

($MM)

($MM)

($MM)

($MM)

($MM)

Proved Reserves

9,302

1,712

2,735

335

134

4,385

Total Proved Plus Probable Reserves

11,818

2,186

3,390

402

147

5,694

Note:

FUTURE NET REVENUE

FORECAST PRICES AND COSTS

				FUTURE NET REVENUE
		PRODUCTION GROUP		BEFORE INCOME TAXES
Reserves Category				(discounted at 10% yr) ($M)
Proved Reserves		Light and Medium Crude Oil (including solution gas and other by-products) (1)			1,285,742
		Heavy Oil (including solution gas and other by-products) (1)			138,224
		Natural Gas (including by-products but excluding solution gas from oil wells) (2)			1,294,222
Total Proved Plus Probable Reserves		Light and Medium Crude Oil (including solution gas and other by-products) (1)			1,532,149
		Heavy Oil (including solution gas and other by-products)(1)			165,396
		Natural Gas (including by-products but excluding solution gas from oil wells) (2)			1,506,936

Notes:

SUMMARY OF PRICING ASSUMPTIONS

CONSTANT PRICES AND COSTS

EXCHANGE

OIL

NATURAL GAS

NATURAL GAS LIQUIDS(1)

RATE(2)

Edmonton

Cromer

LLB Crude

WTI Cushing

Par Price

Medium

Oil at

AECO

Oklahoma

400 API

29.30 API

Hardisty

Gas Price

Propane

Butane

Pentanes Plus

YEAR(3)

($US/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/mmbtu)

($Cdn/bbl)

($Cdn/bbl)

($Cdn/bbl)

($US/Cdn)

2005(4)

61.04

68.27

51.84

39.20

9.71

43.69

50.52

71.67

0.8577

Notes:

SUMMARY OF PRICING

FORECAST PRICES AND COSTS

																																		INFLATION				EXCHANGE
		OIL																NATURAL GAS				NATURAL GAS LIQUIDS(1)												RATES(2)				RATE(3)
						Edmonton Par				Cromer				Hardisty
		WTI Cushing				Price				Medium				Heavy				AECO
		Oklahoma				400 API				29.3 0 API				120 API				Gas Price				Propane				Butane				Pentanes Plus
Year		($US/bbl)				($Cdn/bbl)				($Cdn/bbl)				($Cdn/bbl)				($Cdn/mmbtu)				($Cdn/bbl)				($Cdn/bbl)				($Cdn/bbl)				(%/Year)				($US/Cdn)
2005(4)			56.60				69.11				57.07				34.14				8.58				42.55				51.41				69.45				2.20	%			0.825
2006			57.00				66.25				55.75				33.25				10.60				42.50				49.00				67.00				2.00	%			0.850
2007			55.00				64.00				55.25				32.75				9.25				41.00				47.25				65.25				2.00	%			0.850
2008			51.00				59.25				51.25				32.50				8.00				38.00				43.75				60.50				2.00	%			0.850
2009			48.00				55.75				48.25				32.50				7.50				35.75				41.25				56.75				2.00	%			0.850
2010			46.50				54.00				46.75				32.00				7.20				34.50				40.00				55.00				2.00	%			0.850
2011			45.00				52.25				45.25				33.50				6.90				33.50				38.75				53.25				2.00	%			0.850
2012			45.00				52.25				45.25				33.50				6.90				33.50				38.75				53.25				2.00	%			0.850
2013			46.00				53.25				46.00				34.00				7.05				34.00				39.50				54.25				2.00	%			0.850
2014			46.75				54.25				47.00				34.75				7.20				34.75				40.25				55.25				2.00	%			0.850
2015			47.75				55.50				48.00				35.25				7.40				35.50				41.00				56.50				2.00	%			0.850
2016			48.75				56.50				48.75				36.00				7.55				36.25				41.75				57.75				2.00	%			0.850
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					2.00	%			0.850

Notes:

RECONCILIATION OF NET RESERVES

FORECAST PRICES AND COSTS

		LIGHT AND MEDIUM OIL												NATURAL GAS												NATURAL GAS LIQUIDS
										Net												Net												Net
										Proved												Proved												Proved
		Net				Net				Plus				Net				Net				Plus				Net				Net				Plus
		Proved				Probable				Probable				Proved				Probable				Probable				Proved				Probable				Probable
Factors		(mbbls)				(mbbls)				(mbbls)				(bcf)				(bcf)				(bcf)				(mbbls)				(mbbls)				(mbbls)
December 31, 2004			63,572				16,871				80,443				341.4				74.0				415.4				10,974				2,845				13,819
Extensions			—				—				—				13.9				2.7				16.6				492				78				570
Improved Recovery			1,986				225				2,211				1.3				0.2				1.5				309				(116	)			193
Technical Revisions			(354	)			(1,107	)			(1,461	)			10.6				(9.6	)			1.0				591				(259	)			332
Discoveries			—				—				—				1.7				0.4				2.1				2				1				3
Acquisitions			7,769				2,183				9,952				15.2				6.1				21.3				260				73				333
Dispositions			(1,174	)			(235	)			(1,409	)			(3.9	)			(1.1	)			(5.0	)			(71	)			(4	)			(75	)
Economic Factors			—				—				—				—				—				—				—				—				—
Production			(5,807	)			—				(5,807	)			(48.6	)			—				(48.6	)			(1,957	)			—				(1,957	)
December 31, 2005			65,992				17,937				83,929				331.6				72.7				404.3				10,600				2,618				13,218