Pengrowth Energy (PGH) F-10 Registration of securities (Canada)

As filed with the Securities and Exchange Commission on October 17, 2002

Registration No. 333-                    

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM F-10

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

PENGROWTH ENERGY TRUST

(Exact name of Registrant as specified in its charter)

Alberta, Canada	1311	N/A
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

700 SunLife Plaza – East Tower 112 – 4th Avenue South West Calgary, Alberta T2P 0H3 Canada

Tel: (403) 233-0224

(Address and telephone number of registrant’s principal executive offices)

John K. Whelan, Esq.

Carter, Ledyard & Milburn, 2 Wall Street, New York, New York 10005

Tel: (212) 732-3200

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

Copies to:

Brad D. Markel, Esq.
Bennett Jones LLP
4500 Bankers Hall East
855 – 2nd Street S.W.
Calgary, Alberta T2P 4K7 Canada
Tel: (403) 298-3100 David Spencer, Esq.
Fraser Milner Casgrain LLP
30th Floor, Fifth Avenue Place
237 – 4th Avenue S.W.
Calgary, Alberta T2P 4X7 Canada
Tel: (403) 268-7000 Thomas P. Mason, Esq.
James M. Prince, Esq.
Vinson & Elkins LLP
1001 Fannin Street
Houston, Texas 77002 U.S.A.
Tel: (713) 758-3710

    Province of Alberta, Canada

(Principal jurisdiction regulating this offering (if applicable))

Approximate date of commencement of proposed sale to the public:As soon as possible after this registration statement becomes effective.

It is proposed that this filing shall become effective (check appropriate box)

A.	o	upon filing with the Commission, pursuant to Rule 467(a) (if in connection with an offering being made contemporaneously in the United States and Canada)
B.	x	at some future date (check the appropriate box below)
	1.	o  pursuant to Rule 467(b) on (date) at (time) (designate a time not sooner than 7 calendar days after filing).
	2.	o  pursuant to Rule 467(b) on (date) at (time) (designate a time 7 calendar or sooner days after filing) because the securities regulatory authority in the review jurisdiction has issued a receipt or notification of clearance on (date).
	3.	o  pursuant to Rule 467(b) as soon as practicable after notification of the Commission by the Registrant or the Canadian securities regulatory authority of the review jurisdiction that a receipt or notification of clearance has been issued with respect hereto.
	4.	x  after the filing of the next amendment to this Form (if preliminary material is being filed).

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to the home jurisdiction’s shelf prospectus offering procedures, check the following box. o

CALCULATION OF REGISTRATION FEE

		Proposed	Proposed maximum
Title of each class of securities	Amount to be	maximum offering	aggregate offering	Amount of
to be registered	registered(1)	price per unit(1)	price(1)	registration fee
Trust Units(2)	16,906,000	$9.28	$157,350,000	$14,477

(1)	Estimated solely for the purpose of determining the registration fee and calculated pursuant to Rule 457(c) on the basis of the average of the high and low prices of the Registrant’s Trust Units on the New York Stock Exchange on October 15, 2002.
(2)	Includes Trust Units that the Underwriters have an option to purchase to cover over-allotments, if any.

    The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Rule 467 under the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to Section 8(a) of the Securities Act of 1933, may determine.

TABLE OF CONTENTS

PART I INFORMATION REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS
IMPORTANT TERMS USED IN THIS PROSPECTUS
EXCHANGE RATE TABLE
PRESENTATION OF OUR FINANCIAL INFORMATION
PRESENTATION OF OUR RESERVE INFORMATION
FORWARD-LOOKING STATEMENTS
SUMMARY
RISK FACTORS
RECENT ACQUISITION
DISTRIBUTIONS
PRICE RANGE AND TRADING VOLUME OF TRUST UNITS
USE OF PROCEEDS
CAPITALIZATION OF PENGROWTH TRUST
SELECTED FINANCIAL INFORMATION
MANAGEMENT’S DISCUSSION AND ANALYSIS OF OPERATING RESULTS AND FINANCIAL CONDITION
BUSINESS
STRUCTURE AND ORGANIZATION OF PENGROWTH
DIRECTORS AND OFFICERS
CORPORATE GOVERNANCE AND CONFLICTS OF INTEREST
CERTAIN INCOME TAX CONSIDERATIONS
ERISA CONSIDERATIONS
UNDERWRITING
RELATIONSHIP BETWEEN PENGROWTH CORPORATION AND CERTAIN UNDERWRITERS
DOCUMENTS INCORPORATED BY REFERENCE
AVAILABLE INFORMATION
DOCUMENTS FILED AS PART OF THE U.S. REGISTRATION STATEMENT
AUDITORS, TRANSFER AGENT AND REGISTRAR
ELIGIBILITY FOR INVESTMENT
LEGAL MATTERS
INDEX TO FINANCIAL STATEMENTS
PRESENTATION OF OUR FINANCIAL INFORMATION
PURCHASER’S STATUTORY RIGHTS
CERTIFICATES OF PENGROWTH
CERTIFICATE OF THE UNDERWRITERS
PART II INFORMATION NOT REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS
EXHIBITS
PART III UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
	Item 1. Undertaking
	Item 2. Consent to Service of Process
SIGNATURES
POWER OF ATTORNEY
INDEX TO EXHIBITS
Renewal Annual Information Form Dated May 17, 2002
Financial Statements December 31, 2001 & 2000
Information Circular - Proxy Statement 03/15/2002
MD&A Six Months Ended June 30, 2002
Financial Statement Six Months June 30, 2002 & 200
Materal Change Report
Consent of Gilbert Lausten Jung Associates Ltd.
Amended & Restated Trust Indenture April 23, 2002
Amended & Restated Royalty Indenture April 23, 200
Amended & Restated Management Agreement
Amended & Restated Unanimous Shareholder Agreement

PART I

INFORMATION REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS

Explanatory Note

     This Registration Statement contains two forms of prospectus: one to be used in connection with the offering of Trust Units in the United States (the “U.S. Prospectus”) and one to be used in connection with the offering of Trust Units in Canada (the “Canadian Prospectus”). The two forms of prospectus are identical except that they contain different front covers, back covers and pages 1. In addition, the Canadian Prospectus includes certificates of the Registrant and the Underwriters and the section titled “Purchasers’ Statutory Rights”. The form of U.S. Prospectus is included herein and is followed by the pages to be used in the Canadian Prospectus that differ from those in the U.S. Prospectus.

The information in this Prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated October 16, 2002

PROSPECTUS

PENGROWTH ENERGY TRUST

Trust Units

All of the trust units offered hereby are being sold by Pengrowth Energy Trust (“Pengrowth Trust”) in the United States and Canada.

The trust units are listed on the New York Stock Exchange, Inc. under the symbol PGH and the Toronto Stock Exchange under the symbol PGF.UN. On October           , 2002, the closing sale price of the trust units was US$          per unit on the New York Stock Exchange and Cdn$ per unit on the Toronto Stock Exchange. See “Price Range and Trading Volume.”

Investing in the trust units involves significant risks. See “Risk Factors” beginning on page 20.

	Per Unit	Total
Public offering price	US$	US$160,000,000
Underwriting discounts and commissions	US$	US$
Proceeds to Pengrowth Trust (before expenses)	US$	US$

For trust units sold in the United States, the offering price is payable in U.S. dollars at the approximate U.S. dollar equivalent of the Canadian dollar offering price (Cdn$                    ) based on the inverse of the noon buying rate of the Federal Reserve Bank of New York on October      , 2002 of US$                    per Cdn$1.00.

Pengrowth Trust has granted the underwriters a 30-day option to purchase up to additional trust units on the same terms and conditions as set forth above to cover over-allotments, if any.

Pengrowth Trust has prepared this Prospectus in accordance with the disclosure requirements of Canada. You should be aware that these requirements are different from those of the United States. Pengrowth Trust prepares its consolidated financial statements in accordance with Canadian generally accepted accounting principles, and they are subject to Canadian auditing and auditor independence standards, and thus may not be comparable to financial statements of United States companies. In addition, some of the reserve information included in this prospectus is not comparable to the disclosure of reserves by United States oil and gas producers. See “Presentation of Our Reserve Information” on page 2.

Owning trust units may subject you to tax consequences both in the United States and in Canada. This Prospectus may not describe these tax consequences fully. You should read the tax discussion under the caption “Certain Income Tax Consequences.” You should also consult your own tax advisor with respect to your own particular circumstances.

Your ability to enforce civil liabilities under the United States federal securities laws may be affected adversely because Pengrowth Trust is organized under the laws of Alberta, Canada, the officers and directors of Pengrowth Corporation, its administrator, and Pengrowth Management, its manager, and the experts named in this Prospectus are Canadian residents, and most of the assets of Pengrowth Trust and of such other persons may be located in Canada.

Neither the Securities and Exchange Commission nor any state securities regulator has approved or disapproved these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Lehman Brothers and RBC Capital Markets, on behalf of the underwriters expect to deliver the trust units to purchasers on                     , 2002.

Joint Book-running Managers

LEHMAN BROTHERS RBC CAPITAL MARKETS

UBS WARBURG

MCDONALD INVESTMENTS INC. RAYMOND JAMES

October           , 2002

[Map of Pengrowth Principle Properties]

-ii-

     The underwriters, as principals, conditionally offer the trust units, subject to prior sale, if, as and when issued by Pengrowth Energy Trust and accepted by the underwriters in accordance with the conditions contained in the underwriting agreements referred to under “Underwriting” and subject to the approval of certain legal matters on behalf of Pengrowth Energy Trust by Bennett Jones LLP, Calgary, Alberta with respect to matters of Canadian law and Carter, Ledyard & Milburn, New York, New York with respect to matters of United States law and on behalf of the underwriters by Fraser Milner Casgrain LLP, Calgary, Alberta with respect to matters of Canadian law and Vinson & Elkins L.L.P., Houston, Texas with respect to matters of United States law.Pengrowth Energy Trust may be considered to be a connected issuer under Canadian securities laws to RBC Dominion Securities Inc., BMO Nesbitt Burns Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc., Scotia Capital Inc. and HSBC Securities (Canada) Inc. as they are subsidiaries of Canadian chartered banks which are lenders to Pengrowth Corporation and to which Pengrowth Corporation is presently indebted. See “Relationship Between Pengrowth Corporation and Certain Underwriters”.

     The underwriters may over-allot or effect transactions which stabilize or maintain the market price of the trust units at levels other than those which might otherwise prevail in the open market. See “Underwriting”.

     Subscriptions for the trust units will be received, subject to rejection or allotment in whole or in part, and the right is reserved to close the subscription books at any time without notice. It is expected that certificates evidencing the trust units will be available for delivery at the closing of this offering, which is expected to take place on or aboutl, 2002, or on such other date as may be agreed upon by Pengrowth Energy Trust and the underwriters, but in any event not later thanl, 2002.

     You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any jurisdiction where the offer is not permitted. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of this prospectus.

-iii-

IMPORTANT TERMS USED IN THIS PROSPECTUS

     We have avoided the use of technical defined terms in this prospectus whenever possible, but a few frequently recurring terms may be useful for you to have in mind:

     Corporate

•  we,us,our andPengrowth refer to Pengrowth Energy Trust and Pengrowth Corporation on a consolidated basis;

•  Pengrowth Trust refers to Pengrowth Energy Trust;

•  Pengrowth Management refers to Pengrowth Management Limited;

•  B.C. Asset Package refers to the northern British Columbia properties we acquired from Calpine Canada Natural Gas Partnership, prior to our sale of certain interests in those properties to Progress Energy Ltd.;

•  New B.C. Properties refers to the northern British Columbia properties we acquired from Calpine Canada Natural Gas Partnership, net of the interests sold to Progress Energy Ltd.;

•  Schedule of Revenue and Expenses refers to the Schedule of Revenue and Expenses associated with the northern British Columbia oil and natural gas assets acquired from Calpine Canada Natural Gas Partnership by Pengrowth Corporation for each of the years in the three year period ended December 31, 2001; and

•  unitholders refers to the holders of trust units issued by Pengrowth Trust.

     Engineering

•  GLJ July Report refers to the report, dated September 18, 2002, prepared by Gilbert Laustsen Jung Associates Ltd., independent petroleum engineers, on the following basis:

•  in respect of the New B.C. Properties, the report was prepared using detailed engineering evaluations made by Gilbert Laustsen Jung Associates Ltd. effective as of January 1, 2002, adjusted to take into account actual production, and the results of additional development activity, from January 1, 2002 to July 1, 2002;

•  in respect of our properties other than the New B.C. Properties, the report was prepared using detailed engineering evaluations made by Gilbert Laustsen Jung Associates Ltd. effective as of January 1, 2002, adjusted to take into account estimated production, and to reflect the acquisition and disposition of properties, from January 1, 2002 to July 1, 2002; and

•  in respect of each of the above two cases, the report was prepared using two different sets of price and cost assumptions, the first set of assumptions being the constant price and cost basis which assumes that costs remain constant at the costs estimated as at July 1, 2002 by Gilbert Laustsen Jung Associates Ltd. for 2002 and prices for production remain constant at the prices forecast for the fourth quarter of 2002 as set out in the “October 1, 2002 Gilbert Laustsen Jung Associates Ltd. Product Price and Market Forecasts for the Canadian Oil and Gas Industry” constituting part of the GLJ July Report, and the second set of assumptions being the escalated price and cost basis which assumes that prices for production and costs fluctuate in the future as set out in the “October 1, 2002 Gilbert Laustsen Jung Associates Ltd. Product Price and Market Forecasts for the Canadian Oil and Gas Industry” constituting part of the GLJ July Report, all as detailed in notes (7), (9) and (10) under “Business — Reserves — Notes to Reserves”;

•  proved reserves refers to those reserves estimated as recoverable under current technology and existing economic conditions, in the case of constant pricing, and anticipated economic conditions, in the case of escalated pricing, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir;

•  net proved reserves refers to Pengrowth’s working interest share of proved reserves after the deduction of royalties, based on constant price and cost assumptions;

-iv-

•  probable reserves refers to those reserves which an analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for a pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future;

•  risked probable reserves refers to probable reserves discounted by one-half to account for the additional risk of recovery for probable reserves;

•  established reserves refers to proved reserves plus risked probable reserves, before the deduction of royalties and based on escalated price and cost assumptions unless otherwise indicated;

•  gross refers to Pengrowth’s working interest or royalty interest share of reserves or production, as the case may be, 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;

•  reserve life refers to the estimated number of years for which a property will remain capable of economic production based on the established reserves of the property;

•  reserve life index refers to the number of years determined by dividing the established reserves of a property by the estimated annual production from the established reserves of the property unless we indicate thatreserve life index is based on net proved reserves, in which case reserve life index refers to the number of years determined by dividing the net proved reserves of a property by the estimated annual net production from the property;

•  working interest refers to the percentage of undivided interest held by a party in an oil and gas property;

•  royalty interest refers to an interest in an oil and gas property consisting of a royalty granted in respect of production from the property; and

•  unitization means 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.

     We also use the following abbreviations:

•  bbl,bbls,mbbls andmmbbls mean barrel, barrels, thousands of barrels and millions of barrels, respectively;

•  bblpd means barrels per day;

•  boe,mboe andmmboe mean 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, based upon general practice in the Canadian oil and natural gas industry;

•  boepd means barrels of oil equivalent per day;

•  mmbtu andmmbtupd mean million british thermal units and million british thermal units per day, respectively;

•  mcf,mmcf,bcf andtcf mean thousand cubic feet, million cubic feet, billion cubic feet and trillion cubic feet, respectively;

•  mcfpd andmmcfpd mean thousands of cubic feet per day and millions of cubic feet per day, respectively; and

•  NGLs means natural gas liquids.

-v-

EXCHANGE RATE TABLE

     All dollar amounts set forth in this prospectus are in Canadian dollars, except where otherwise indicated.

     The following table sets forth certain exchange rates based on the inverse of the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York. The rates are set forth as United States dollars per Cdn$1.00. On October 15, 2002, the inverse of the noon buying rate was US$0.6306 per Cdn$1.00.

											Six Months Ended
	Year Ended December 31,										June 30,
	1997		1998		1999		2000		2001		2001		2002
Rate at end of period	$	0.6999	$	0.6504	$	0.6925	$	0.6669	$	0.6279	$	0.6590	$	0.6583
Average rate during period		0.7197		0.6714		0.6745		0.6725		0.6444		0.6515		0.6378
High		0.7487		0.7105		0.6925		0.6969		0.6697		0.6697		0.6619
Low		0.6945		0.6341		0.6535		0.6410		0.6241		0.6333		0.6200

-vi-

TABLE OF CONTENTS

	Page
Important Terms Used in this Prospectus		iv
Exchange Rate Table		vi
Presentation of our Financial Information		1
Presentation of our Reserve Information		2
Forward-Looking Statements		3
Summary		4
Risk Factors		20
Recent Acquisition		30
Distributions		33
Price Range and Trading Volume of Trust Units		35
Use of Proceeds		36
Capitalization of Pengrowth Trust		36
Selected Financial Information		38
Management’s Discussion and Analysis of Operating Results and Financial Condition		41
Business		53
Structure and Organization of Pengrowth		77
Directors and Officers		84
Corporate Governance and Conflicts of Interest		88
Certain Income Tax Considerations		91
ERISA Considerations		104
Underwriting		106
Relationship Between Pengrowth Corporation and Certain Underwriters		110
Documents Incorporated by Reference		112
Available Information		113
Documents filed as part of the U.S. Registration Statement		113
Auditors, Transfer Agent and Registrar		113
Eligibility for Investment		114
Legal Matters		114
Index to Financial Statements		F-1

PRESENTATION OF OUR FINANCIAL INFORMATION

     Unless we indicate otherwise, financial information in this prospectus has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”).Canadian GAAP differs in some significant respects from U.S. GAAP and thus our financial statements may not be comparable to the financial statements of U.S. companies. The principal differences as they apply to us are summarized in note 13 to the audited annual consolidated financial statements of Pengrowth Trust beginning on page F-24, the Reconciliation of Interim Consolidated Financial Statements of Pengrowth Energy Trust for the six months ended June 30, 2002 to United States generally accepted accounting principles beginning on page F-19, note 4 to the unaudited pro forma consolidated financial statements of Pengrowth Energy Trust beginning on page F-2, and note 3 to the Schedule of Revenue and Expenses beginning on page F-50.

     We present our financial information in Canadian dollars. In this prospectus, except where we indicate otherwise, all dollar amounts are in Canadian dollars.References to “$” or “Cdn$” are to Canadian dollars and references to “US$” are to U.S. dollars. This prospectus contains a translation of some Canadian dollar amounts into U.S. dollars at specified exchange rates solely for your convenience. Unless we indicate otherwise, U.S. dollar amounts have been translated from Canadian dollars at US$0.6306 per Cdn$1.00, which was the inverse of the noon buying rate of the Federal Reserve Bank of New York on October 15, 2002.

     The pro forma consolidated balance sheet was prepared as if the (i) acquisition of the B.C. Asset Package, (ii) the disposition of a portion of the B.C. Asset Package to Progress Energy Ltd., (iii) the issuance of 17,123,287 trust units for net proceeds of $234.25 million in this offering, and (iv) the other transactions described in the notes to the pro forma financial statements, had occurred on June 30, 2002 and the pro forma combined statements of income and distributable income for the year ended December 31, 2001 and for the six months ended June 30, 2002 were prepared as if such transactions had occurred on the first day of the period presented.

1

PRESENTATION OF OUR RESERVE INFORMATION

     The United States Securities and Exchange Commission (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. Canadian securities laws permit oil and gas companies, 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 generally believed to be less likely to be accurately estimated or recovered than proved reserves. Because we are permitted to prepare this prospectus in accordance with Canadian disclosure requirements, we have disclosed in this prospectus and in the documents incorporated by reference reserves designated as “probable” and “established”. The SEC’s guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. Moreover, we have determined and disclosed estimated future net cash flow from our reserves using both constant and escalated prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. In addition, the estimates of reserves included in this prospectus based on constant prices and costs, as reflected in the GLJ July Report, were prepared using forecast prices for the fourth quarter of 2002, as set out in the “October 1, 2002 Gilbert Laustsen Jung Associates Ltd. Product Price and Market Forecasts for the Canadian Oil and Gas Industry” constituting part of the GLJ July Report, held constant for the economic life of the reserves, whereas the SEC guidelines would require that the reserve estimates be prepared using prices in effect as of July 1, 2002, the effective date of the GLJ July Report, held constant for the economic life of the reserves (the actual price of West Texas Intermediate crude oil at Cushing, Oklahoma at July 1, 2002 was US$26.83 whereas the forecast price of West Texas Intermediate crude oil at Cushing, Oklahoma for the fourth quarter of 2002 was US$28.00). For a description of these and additional differences between Canadian and U.S. standards of reporting reserves, see “Risk Factors — Canadian and United States practices differ in reporting reserves and production” and “Important Terms Used in This Prospectus”.

     References to pro forma reserves in this prospectus give pro forma effect the acquisition of the New B.C. Properties effective as of July 1, 2002.

     Reserve information contained in this prospectus, other than reserve information incorporated by reference in this prospectus, has been derived from the GLJ July Report dated September 18, 2002, prepared by Gilbert Laustsen Jung Associates Ltd., independent petroleum engineers, on the following basis: (i) in respect of the New B.C. Properties, the report was prepared using detailed engineering evaluations made by Gilbert Laustsen Jung Associates Ltd. effective as of January 1, 2002, adjusted to take into account actual production, and the results of additional development activity, from January 1, 2002 to July 1, 2002; (ii) in respect of our properties other than the New B.C. Properties, the report was prepared using detailed engineering evaluations made by Gilbert Laustsen Jung Associates Ltd. effective as of January 1, 2002, adjusted to take into account estimated production, and to reflect the acquisition and disposition of properties, from January 1, 2002 to July 1, 2002; and (iii) in respect of each of the foregoing two cases, the report was prepared using two different sets of price and cost assumptions, the first set of assumptions being the constant price and cost basis which assumes that costs remain constant at the costs estimated as at July 1, 2002 by Gilbert Laustsen Jung Associates Ltd. for 2002 and prices for production remain constant at the prices forecast for the fourth quarter of 2002 as set out in the “October 1, 2002 Gilbert Laustsen Jung Associates Ltd. Product Price and Market Forecasts for the Canadian Oil and Gas Industry” constituting part of the GLJ July Report, and the second set of assumptions being the escalated price and cost basis which assumes that prices for production and costs fluctuate in the future as set out in the “October 1, 2002 Gilbert Laustsen Jung Associates Ltd. Product Price and Market Forecasts for the Canadian Oil and Gas Industry” constituting part of the GLJ July Report, all as detailed in notes (7), (9) and (10) under “Business — Reserves — Notes to Reserves”. Please note that the escalated pricing assumptions include bothincreases anddecreases in future commodity prices and costs.

     In this prospectus, all estimates of reserves and production are before royalties, unless otherwise indicated.

2

     Although the definitions of proved reserves under United States Regulation S-X and Canadian National Policy 2-B are different, in the opinion of Gilbert Laustsen Jung Associates Ltd., estimates of net proved reserves using constant price and cost assumptions in this prospectus are, in all material respects, equivalent to those which would be determined under SEC Regulation S-X. This prospectus has not been, and will not be, reviewed by the SEC.

     All reserve evaluations have been stated prior to any provision for income taxes and general and administrative costs. The estimated present worth values of net production revenue contained in this prospectus may not be representative of the fair market value of the reserves. Actual reserves may be greater than or less than the estimates provided herein.

FORWARD-LOOKING STATEMENTS

     Certain statements contained in this prospectus, including certain documents incorporated by reference in this prospectus, constitute forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in our forward-looking statements. We believe the expectations reflected in those forward-looking statements are reasonable. However, we cannot assure you that these expectations will prove to be correct. You should not unduly rely on forward-looking statements included, or incorporated by reference, in this prospectus. These statements speak only as of the date of this prospectus or as of the date specified in the documents incorporated by reference in this prospectus, as the case may be.

     In particular, this prospectus, including the documents incorporated by reference, contains forward-looking statements pertaining to the following:

•	the size of our reserves;
•	projections of market prices and costs;
•	supply and demand for oil and natural gas;
•	expectations regarding the ability to raise capital and to continually add to our reserves through acquisitions and exploration and development; and
���	treatment under governmental regulatory regimes.

     Our actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this prospectus, including under “Risk Factors”:

•  volatility in market prices for oil and natural gas;

•  liabilities inherent in our oil and gas operations;

•  uncertainties associated with estimating reserves;

•  competition for, among other things, capital, reserves, undeveloped lands and skilled personnel;

•  incorrect assessments of the value of our acquisitions; and

•  geological, technical, drilling and processing problems.

     These factors should not be construed as exhaustive. We undertake no obligation to publicly update or revise any forward-looking statements.

3

SUMMARY

     This summary highlights selected information contained in greater detail elsewhere in this prospectus. You should read the entire prospectus carefully, including the audited consolidated, interim unaudited consolidated and unaudited pro forma consolidated financial statements, the Schedule of Revenue and Expenses and the notes to those financial statements. You should read “Risk Factors” beginning on page 19 for more information about important factors that you should consider before investing in our trust units. Please see “Important Terms Used in this Prospectus” for an explanation of certain terms used in this Prospectus.

     All dollar amounts set forth in this Prospectus are in Canadian dollars, except where otherwise indicated. In this prospectus, all estimates of reserves and production are before royalties, unless otherwise indicated.

Pengrowth Energy Trust

     Pengrowth Trust is one of the largest conventional oil and gas royalty trusts in North America with an enterprise value of approximately $1.9 billion as at October 1, 2002. We are an actively managed Canadian royalty trust that holds interests in oil and gas properties in the Western Canadian Sedimentary Basin and offshore eastern Canada. These properties are characterized by high working interests, established production histories and long life reserves relative to typical Canadian properties. Since inception in 1988, we have purchased approximately $1.8 billion of oil and natural gas interests in Canada in more than 48 separate transactions and have increased our production from 465 boepd in 1989 to 57,137 boepd (44,510 boepd net) forecast for the second half of 2002, including the New B.C. Properties, based on the GLJ July Report.

     Based on the GLJ July Report, Pengrowth Trust has pro forma established reserves of 232.3 mmboe and pro forma net proved reserves of 156.0 mmboe, in each case after giving effect to the acquisition of the New B.C. Properties. We have interests in approximately 70 properties. Our portfolio reserve life index is 9.5 years on a net proved reserves basis and 11.1 years on an established reserves basis. Approximately 59% of our established reserves and 70% of our net proved reserves are in the proved producing category. Based on the GLJ July Report, we have the following allocations of production and reserves, on a boe basis:

     Pengrowth Trust is a publicly traded Canadian oil and gas royalty trust created in 1988. The assets of Pengrowth Trust include 90.9% of the outstanding equity shares of Pengrowth Corporation and 99.98% of the outstanding royalty units of Pengrowth Corporation. Pengrowth Corporation acquires, owns and operates

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working interests and royalty interests in oil and natural gas properties. The royalty units of Pengrowth Corporation entitle the holders thereof to receive a 99% share of the royalty income related to the oil and natural gas interests of Pengrowth Corporation. Royalty income represents essentially all of the revenues received by Pengrowth Corporation from its oil and natural gas interests, less operating costs, royalties, general and administrative expenses, management fees, debt service charges, taxes, and any amount retained as a reserve. Pengrowth Trust’s share of royalty income, together with any lease, interest and other income of Pengrowth Trust, less general and administrative expenses, management fees, debt repayment, taxes and other expenses (provided that there is no duplication of expenses already deducted from royalty income), forms the distributable income of Pengrowth Trust. Pengrowth Trust distributes this distributable income on a monthly basis to the holders of trust units. See “Distributions”.

     Our Canadian royalty trust structure allows us to effectively acquire new oil and natural gas interests and to engage in operations to maximize the returns on our existing interests. Pengrowth Trust and Pengrowth Corporation generally do not pay income taxes, either in Canada or in the United States. Tax deductions available to Pengrowth Trust reduce the taxable component of distributions to Canadian resident unitholders as well as the proportion of distributions to unitholders other than Canadian residents which are subject to withholding taxes. Pengrowth Trust has elected to be treated as a partnership for United States income tax purposes which will also reduce the taxable component of distributions payable to unitholders resident in the United States. See “Certain Income Tax Considerations”.

     Pengrowth Trust and Pengrowth Corporation are managed by Pengrowth Management under a management agreement. Pengrowth Management earns a management fee based on net production revenue and an acquisition fee based on the cost of acquisitions. All expenses incurred by Pengrowth Management on behalf of Pengrowth are reimbursable by Pengrowth. All significant transactions undertaken by Pengrowth are subject to the approval of the board of directors of Pengrowth Corporation. The management agreement must be considered by unitholders every three years at the annual meeting, which will occur next in 2003, and may be terminated upon three years notice or amended upon agreement with Pengrowth Management. Our unitholders are entitled to elect a majority of the board of directors of Pengrowth Corporation at annual shareholder meetings and to exercise in excess of 99.98% of all of the voting rights at any meeting of the shareholders of Pengrowth Corporation.

     The following chart illustrates the organization and structure of Pengrowth:

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Business Strategy

     Our goal is to maximize cash distributions to our unitholders while maintaining the value of the trust units. We do not explore for oil and natural gas. Instead we focus on making effective acquisitions and maximizing the value of our mature property base by reducing operating costs, implementing applicable development technologies, including three dimensional seismic and tertiary recovery operations and implementing other operational efficiencies.

     Our business model is designed to increase distributions to our unitholders. Our ability to pay out distributions while enhancing unitholder value over time is dependent upon effective operations and our ability to make acquisitions which yield returns that exceed our estimated cost of capital. We evaluate acquisition opportunities based on the following general acquisition criteria:

Financial

•  Acquisitions should increase distributions on a per trust unit basis based upon current economics.

•  The aggregate purchase price of all properties acquired in a single transaction should not exceed the undiscounted aggregate projected net cash flow from the properties from the date of purchase plus a reasonable rate of return in the circumstances.

•  The oil and gas producing properties to be acquired should, in the context of the market, have an attractive rate of return and a low reserve cost.

Operational

•  Properties to be acquired should be high quality, proven producing properties in unitized areas which have long life reserves relative to typical Canadian properties. Pengrowth gives priority to properties with:

—  low capital expenditures relative to cash generation potential;

—  low operating costs or high margins;

—  experienced well-regarded operators or where operatorship may be assumed by Pengrowth;

—  favourable production history;

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

—  long reserve life; and

—  low environmental and site remediation risk.

Independent Verification

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

     Our structure, tax effectiveness and cost of capital allow us to bid competitively for oil and natural gas properties against 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 reward exploration and development activities, exiting the business, or fulfilling other strategic objectives.

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History of Growth

     Through the execution of our business strategy, we have increased our production and reserves each year over the 14-year history of Pengrowth. Cumulative cash distributions total $22.60 per trust unit from inception up to and including the October 15, 2002 distribution. Our initial public offering price in 1988 was $10.00 per trust unit.

     Based on the GLJ July Report, our forecast average daily production for the second half of 2002 is 57,137 boepd, including the New B.C. Properties, representing an annual increase on an annual compound basis of 45% since 1989.

(1)  Forecast average daily gross production for the second half of 2002, including the New B.C. Properties, based on the GLJ July Report.

     Based on the GLJ July Report our established reserves have increased from 3.4 mmboe on December 31, 1989 to 232.3 mmboe on July 1, 2002, including the New B.C. Properties, an annual increase on an annual compound basis of 40%.

(1)  As at July 1, 2002, including the New B.C. Properties, based on the GLJ July Report.

(1)	As of June 30, 2002.
(2)	Average daily closing price of West Texas Intermediate at Cushing, Oklahoma.

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(1)  Up to and including the October 15, 2002 distribution declared September 19, 2002.

(1)	Assumes the reinvestment of distributions and/or dividends.
(2)	The S&P 500 Energy Index began in September 1989 at the level of the S&P 500 Index due to the lack of historical data.
(3)	Based on weekly closing price of our trust units on the Toronto Stock Exchange, converted to US$ at the Bank of Canada exchange rate on such date.

(1)	Assumes the reinvestment of distributions and/or dividends.
(2)	Based on the weekly closing price of our trust units on the Toronto Stock Exchange.

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Recent Acquisition

     On October 1, 2002, with an effective date of July 1, 2002, we acquired substantially all of the oil and natural gas properties and related infrastructure held by Calpine Canada Natural Gas Partnership in northern British Columbia for $387.5 million, before adjustments. On October 4, 2002, we sold certain of these properties to Progress Energy Ltd. for $25.4 million, before adjustments. Our net purchase price following the sale to Progress Energy Ltd. was $345.6 million, after adjustments. Based on the GLJ July Report, forecast production for the New B.C. Properties for the second half of 2002 is 39.1 mmcfpd (29.5 mmcfpd net) of natural gas and 9,268 bblpd (6,975 bblpd net) of oil and NGLs for a total of 15,785 boepd (11,901 boepd net). Also based on the GLJ July Report, the acquisition of the New B.C. Properties increased our forecast daily production for the second half of 2002 by 38% from 41,352 boepd (32,466 boepd net) to 57,137 boepd (44,510 boepd net). Established reserves associated with the New B.C. Properties are estimated to be 36.1 mmboe, of which approximately 49% is natural gas, and net proved reserves are estimated to be 23.9 mmboe, of which 46% is natural gas, based on the GLJ July Report. Operating costs for the New B.C. Properties for the first half of 2002 were approximately $3.70 per boe, well below our average of $7.77 per boe for the first half of 2002 (see also “Business — Reserves” and “Recent Acquisition”).

     The New B.C. Properties are expected to provide us with several significant benefits. These properties allow us to expand our operations into northern British Columbia with a significant number of proved producing properties that will provide us with additional development opportunities. The relatively high production rates and shorter reserve lives associated with these properties provide a balance to our existing portfolio of properties that are characterized by relatively lower production rates and longer reserve lives. The New B.C. Properties have a reserve life index of approximately 6.3 years (5.3 years on a net proved reserves basis) and as a result our portfolio reserve life index decreased from 13.0 years (11.2 years on a net proved reserves basis) to approximately 11.1 years (9.5 years on a net proved reserves basis).

     The New B.C. Properties include 247,700 net undeveloped acres with farmout potential. On October 4, 2002, we farmed-out 30,500 net acres to Progress Energy Ltd. under terms which include a $10 million exploration commitment on this acreage over the next 18 months. Under this agreement Progress Energy Ltd. will be required to incur all of the exploration expenses in respect of 100% of the shared acreage to earn an interest in our share of this acreage. This farmout provides Pengrowth with upside exposure to high impact prospects without the associated exploration risk.

     Due to the relatively higher production rates from the New B.C. Properties and the current level of commodity prices that can be obtained for the production from these properties, we anticipate that in the near term this acquisition will allow us to increase distributions while establishing a reserve from funds retained in Pengrowth Corporation in an amount equivalent to approximately 10% of distributable income of Pengrowth Trust for future capital obligations and future distributions. This policy of withholding a portion of cash flow as a reserve will be reviewed by the board of directors of Pengrowth Corporation from time to time based on commodity prices and capital and other commitments.

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Properties

     Our portfolio of properties consists primarily of long life, unitized oil and gas properties with established production profiles. Approximately 68% of our total gross production in 2001 was derived from eight core areas located in the Provinces of Alberta and Saskatchewan and offshore the Province of Nova Scotia. In 2001, we increased our established reserves from 183 mmboe (123 mmboe on a net proved reserves basis) to 211 mmboe (146 mmboe on a net proved reserves basis) through drilling and other optimization strategies and we acquired 48.4 mmboe of new established reserves at an average cost of $5.72 per boe for an overall finding and development cost of $6.85 per boe. Substantially all of the reserves we acquired in 2001 related to interests in the Sable Offshore Energy Project, a large natural gas project located offshore the Province of Nova Scotia operated by ExxonMobil Canada Properties. We raised average production from 33,581 boepd in 2000 to 40,320 boepd in 2001, and to 57,137 boepd (44,510 boepd net) forecast for the second half of 2002, including the New B.C. Properties, based on the GLJ July Report, an increase of approximately 20% and 40%, respectively. Based on the GLJ July Report, our pro forma established reserves are 232.2 mmboe (156.0 mmboe on a net proved reserves basis), consisting of 553.2 bcf (368.6 bcf on a net proved reserves basis) of natural gas and 140.1 mmbbls (94.5 mmbbls on a net proved reserves basis) of oil and NGLs.

     On October 1, 2002, with an effective date of July 1, 2002, we acquired the New B.C. Properties, adding new established reserves of 36.1 mmboe at an average cost of $10.03 per boe (US$6.32) and net proved reserves of 23.9 mmboe at an average cost of $15.15 per boe (US$9.55). The New B.C. Properties have working interests averaging 65%, based on reserves, and are characterized by multi-zone potential at a moderate drilling depth and a mature marketing and transportation infrastructure for crude oil and natural gas. Based on the GLJ July Report, forecast production from the New B.C. Properties for the second half of 2002 is 39.1 mmcfpd (29.5 mmcfpd net) of natural gas and 9,268 bblpd (6,975 bblpd net) of crude oil and NGLs. For the second half of 2002, the New B.C. Properties are forecast to contribute 25% of our natural gas production and 30% of crude oil and NGL production, before royalties, based on the GLJ July Report.

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     The following table provides certain information relating to our principal properties based on the GLJ July Report.You should read the information below in conjunction with “Business — Reserves — Notes to Reserves”. For a description of certain differences between estimating reserves under U.S. reserve disclosure guidelines and Canadian reserve disclosure guidelines, please read “Presentation of Our Reserve Information.”

		Canadian Presentation										United States Presentation
					Established			July 1,		Estimated		Net Proved			July 1,			Estimated
		Remaining			Reserve			2002		Future		Reserve			2002			Future
		Reserve			Life			Established		Cash Flows(3)		Life			Net Proved			Cash Flows(5)
	Operated	Life(1)			Index(2)			Reserves		(PV-10)		Index(4)			Reserves			(PV-10)
Area	By	(years)			(years)			(mboe)		($000)		(years)			(mboe)			($000)
Principal Properties (before the New B.C. Properties were acquired)
Judy Creek BHL Unit	Pengrowth		50			14			47,911		302,773					32,176			408,103
Judy Creek West BHL Unit	Pengrowth		50			16			10,841		62,958					7,509			92,423
Weyburn Unit	EnCana Corporation		39			20			14,463		65,574					8,017			44,251
Swan Hills Unit No. 1	Devon Canada Corporation		50			22			14,303		64,840					9,617			93,471
Enchant	Pengrowth		50			19			6,939		33,440					5,147			43,837
Dunvegan Gas Unit No. 1	Devon Canada Corporation		50			16			6,863		35,289					4,280			30,478
McLeod River	Pengrowth		35			7			4,929		40,359					2,798			36,794
Nipisi Non-Unit	Pengrowth		23			8			3,783		31,268					2,607			43,627
Monogram Gas Unit	EnCana Corporation		38			10			4,683		46,825					3,913			44,770
Goose River Unit No. 1	Conoco Canada Resources Limited		31			5			3,832		31,992					2,284			37,323
Other(6)			50			13			77,688		528,290					53,567			554,305
Subtotal			50	(7)		13	(7)		196,235		1,243,608		11	(7)(8)		131,914			1,429,382
New B.C. Properties
Rigel	Pengrowth		29			4			6,558		92,549					4,300	(9)		109,200	(9)
Oak	Pengrowth		48			11			6,845		58,865					4,600	(9)		70,800	(9)
Bulrush	Pengrowth		43			9			1,923		17,035					1,200	(9)		17,300	(9)
Squirrel	Pengrowth		23			5			5,698		78,049					4,200	(9)		96,300	(9)
Tupper	Pengrowth		37			4			1,136		14,733					700	(9)		13,100	(9)
Other(10)	Pengrowth		50			9			13,944		123,408					8,800	(9)		126,000	(9)
Subtotal			50	(7)		6	(7)		36,104		384,639		5	(7)(8)		24,072	(9)		436,609	(9)
Total			50	(7)		11	(7)		232,339		1,628,247		10	(7)(8)		155,986			1,865,991

(1)	The estimated number of years for which a property will remain capable of economic production based on the established reserves of the property.
(2)	The number of years determined by dividing the established reserves as at July 1, 2002 of each property by the estimated annual production.
(3)	PV-10 is the present value of the estimated future cash flows to Pengrowth before income taxes from established reserves, discounted at 10% per year, calculated using escalated price and cost assumptions, as detailed in note (7) under “Business — Reserves — Notes to Reserves”. PV-10 is not necessarily indicative of actual future cash flows.

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(4)	The net proved reserve life index has not been determined by area.
(5)	PV-10 is the present value of the estimated future net cash flows to Pengrowth before income taxes from net proved reserves, discounted at 10% per year, calculated using constant price and cost assumptions, based on the GLJ July Report. The constant prices used consist of oil at US$28.00 per bbl for WTI at Cushing, Oklahoma FOB and at $42.75 per bbl for light, sweet crude oil at Edmonton FOB and gas at $4.85 per mcf for natural gas (Alberta average) and $43.25, $24.75 and $30.75 per bbl of condensate, propane and butane, respectively, at Edmonton FOB. PV-10 is not necessarily indicative of actual future cash flows.
(6)	Includes Pengrowth Corporation’s 99.99% royalty interest in the 8.4% working interest in the Sable Offshore Energy Project held by Emera Offshore Incorporated (a subsidiary of Emera Inc.) and 28 other properties. In accordance with the confidentiality agreement between Pengrowth Corporation, Emera Offshore Incorporated and the other Sable Offshore Energy Project owners, Pengrowth Corporation is precluded from presenting certain information with respect thereto except on a consolidated basis.
(7)	Average calculated on a weighted basis based on boe reserves.
(8)	The number of years determined by dividing the net proved reserves as at July 1, 2002 by the estimated annual net production.
(9)	The net proved reserves and the estimated future cash flows presented using constant price and cost assumptions for the New B.C. Properties by area are approximate and the sum of the reserves and cash flows presented by area do not equal the respective subtotals which represent the aggregate net proved reserves and estimated future cash flows, respectively, for the New B.C. Properties.

(10)  Includes 26 properties.

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The Offering

Trust units offered by Pengrowth Trust	l trust units
Over-allotment option	l trust units
Trust units outstanding after the offering	l trust units (l trust units if the over-allotment option is exercised in full)
Use of Proceeds	The net proceeds from this offering will be provided by Pengrowth Trust to Pengrowth Corporation and will be used by Pengrowth Corporation to repay existing outstanding indebtedness pursuant to interim facilities obtained to fund the acquisition of the New B.C. Properties. RBC Dominion Securities Inc. and RBC Dain Rauscher Inc. are subsidiaries of the lender that provided these interim facilities, and which will receive the net proceeds of this offering to repay all, or a portion, of these additional facilities. See “Underwriting” and “Relationship between Pengrowth Corporation and Certain Underwriters”.
Toronto Stock Exchange Symbol	PGF.UN
New York Stock Exchange Symbol	PGH
Cash Distributions	We pay cash distributions on the 15th day of each month to our unitholders of record on the 10th business day immediately proceeding the payment date. The first distribution to which subscribers for trust units in this offering will be entitled will be payable on December 15, 2002.
Estimated ratio of taxable income to distributions (Canada)	We estimate that approximately 30% to 35% of distributions paid in 2002 will be taxable to Canadian residents for 2002 based on distributions paid in 2002, including the October 15, 2002 distribution declared September 19, 2002, current commodity prices, forecast production for the remainder of 2002 based on the GLJ July Report, including the New B.C. Properties, and the receipt of net proceeds of $234.25 million pursuant to this offering. See “Certain Income Tax Considerations — Certain Canadian Income Tax Considerations”.
Estimated ratio of taxable income to distributions (United States)	We estimate that subscribers resident in the United States who hold the trust units purchased in this offering through December 31, 2003, will be able to reduce the component of their distributions which are subject to United States federal taxable income for that period by approximately US$0.68 for depreciation and depletion based upon a hypothetical issuance price equal to the closing price of the trust units of US$9.07 on the New York Stock Exchange on October 10, 2002. See “Certain Income Tax Considerations — Certain United States Income Tax Considerations”.

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Selected Historical and Pro Forma Financial and Operating Data

     The following table presents summary consolidated historical financial data for the years ended December 31, 1999, 2000 and 2001 and for the six month periods ended June 30, 2001 and 2002, in each case derived from the consolidated financial statements of Pengrowth Trust at each of these dates and for the periods then ended, as well as the Reconciliation of Interim Consolidated Financial Statements of Pengrowth Energy Trust for the six months ended June 30, 2002 to United States generally accepted accounting principles and from the unaudited pro forma consolidated balance sheet of Pengrowth Trust at June 30, 2002 and the unaudited pro forma combined statements of income and distributable income of Pengrowth Trust for the year ended December 31, 2001 and for the six months ended June 30, 2002. The unaudited pro forma consolidated balance sheet was prepared as if the (i) acquisition of the B.C. Asset Package, (ii) the disposition of a portion of the B.C. Asset Package to Progress Energy Ltd., (iii) the issuance of 17,123,287 trust units for net proceeds of $234.25 million and (iv) the other transactions described in the notes to the pro forma financial statements, had occurred on June 30, 2002 and the pro forma combined statements of income and distributable income for the year ended December 31, 2001 and for the six months ended June 30, 2002 were prepared as if such transactions had occurred on the first day of the period presented. The consolidated financial statements of Pengrowth Trust as at and for the years ended December 31, 1999, 2000 and 2001 have been audited by KPMG LLP. The pro forma consolidated financial statements of Pengrowth Trust have not been audited but have been reviewed, as to compilation only, by KPMG LLP. See “Comments for United States Readers on Differences between Canadian and United States Reporting Standards” included in the pro forma consolidated financial statements.

     You should read the following data along with “Management’s Discussion and Analysis of Operating Results and Financial Condition” and the consolidated financial statements and related notes of Pengrowth Trust, as well as the Reconciliation of Interim Consolidated Financial Statements of Pengrowth Energy Trust for the six months ended June 30, 2002 to United States generally accepted accounting principles, included in this prospectus. You should also read the pro forma information together with the unaudited pro forma consolidated financial statements and related notes of Pengrowth Trust included in this prospectus.

																				Pro Forma
														Six Months Ended						Six Months
		Years Ended December 31,									Pro Forma			June 30,						Ended
											Year Ended									June 30,
		1999			2000			2001			December 31, 2001			2001			2002			2002
		(In thousands of Canadian dollars, except per unit amounts)
INCOME AND DISTRIBUTABLE INCOME STATEMENT DATA
Revenues:
	Oil and gas sales		252,408			416,228			469,929			717,542			264,004			203,178			284,652
	Processing and other income		3,715			5,520			7,071			7,071			3,359			3,036			3,036
	Royalties and mineral taxes		(31,886	)		(76,588	)		(71,960	)		(116,102	)		(45,940	)		(27,439	)		(45,118	)
	Operating Revenues, after royalties		224,237			345,160			405,040			608,511			221,423			178,775			242,570
	Interest and other income		1,144			5,788			1,348			1,348			1,063			(525	)		(525	)
	Net Revenue		225,381			350,948			406,388			609,859			222,486			178,250			242,045
Expenses:
	Operating		57,642			65,195			104,943			134,777			43,790			58,057			68,618
	Amortization of injectants for miscible floods		13,964			32,463			47,448			47,448			22,518			23,454			23,454
	General and administrative		5,972			7,081			7,467			7,467			3,627			5,219			5,219
	Management fee		4,490			6,873			7,120			11,461			4,714			3,140			4,471
	Depletion, depreciation and future site restoration		80,981			96,865			132,737			192,040			60,304			67,872			98,729
	Interest		10,882			17,354			18,806			26,380			9,929			6,165			8,126
	Capital taxes and other		1,227			1,902			2,717			3,175			1,852			297			490
	Total Expenses		175,158			227,733			321,238			422,748			146,734			164,204			209,107

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																				Pro Forma
														Six Months Ended						Six Months
		Years Ended December 31,									Pro Forma			June 30,						Ended
											Year Ended									June 30,
		1999			2000			2001			December 31, 2001			2001			2002			2002
		(In thousands of Canadian dollars, except per unit amounts)
Net Income:			50,223			123,215			85,150			187,111			75,752			14,046			32,938
Add: depletion, depreciation and future site restoration			80,981			96,865			132,737			192,040			60,304			67,872			98,729
Deduct: remediation expenses and other			(3,032	)		(1,740	)		(2,100	)		(2,100	)		(590	)		(659	)		(659	)
Distributable income			128,172			218,340			215,787			377,051	(1)		135,466			81,259			131,008	(1)
Net Income per unit:
	Basic		$0.98			$2.21			$1.20			$2.13			$1.15			$0.17			0.33
	Diluted		$0.98			$2.19			$1.20			$2.12			$1.14			$0.17			0.33
Distributable income per unit:
	Based on weighted average units outstanding		$2.50			$3.92			$3.04			$4.28	(1)		$2.06			$0.97			1.30	(1)
	Based on actual distributions paid or declared		$2.49			$3.79			$3.01						$1.97			$0.95
US GAAP(2)
Net Income			78,741			150,654			110,748			215,933			87,974			26,170			46,983
Net Income per unit:
	Basic		1.54			2.71			1.56			2.45			1.34			0.31			0.47
	Diluted		1.54			2.67			1.56			2.45			1.33			0.31			0.47

														Pro Forma
										Six Months Ended				Six Months
		Years Ended December 31,						Pro Forma		June 30,				Ended
								Year Ended						June 30,
		1999		2000		2001		December 31, 2001		2001		2002		2002
		(In thousands of Canadian dollars, except per unit amounts and operating data)
OTHER FINANCIAL DATA
	Distributions to Unitholders		114,163		197,826		241,590		—		142,115		72,420		—
	EBITDA(3)		143,313		239,336		239,410		408,706		147,837		88,380		140,283
OPERATING DATA
Daily gross production
	Oil (bblpd)		17,570		17,599		19,726		28,658		20,039		18,302		27,588
	Gas (mcfpd)		61,494		70,098		91,764		146,303		74,709		106,936		142,353
	Natural gas liquids (bblpd)		3,927		4,205		5,258		6,262		4,385		5,176		5,820
	Oil equivalent (boepd)		31,821		33,581		40,320		59,346		36,933		41,312		57,145

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		As at December 31,
								As at June		Pro Forma as at
		1999		2000		2001		30, 2002		June 30, 2002
		(In thousands of Canadian dollars, except per unit amounts and ratios)
BALANCE SHEET DATA
Assets:
	Current assets		27,269		46,145		34,343		36,689		36,689
	Remediation Trust Fund		3,785		5,515		6,470		6,808		6,808
	Property, Plant and Equipment and other assets		826,860		1,038,823		1,208,526		1,145,197		1,493,897
			857,914		1,090,483		1,249,339		1,188,694		1,537,394
Liabilities and Unitholders’ Equity:
	Current Liabilities		50,447		90,900		54,089		64,455		64,455
	Long-term debt		230,333		286,823		345,456		219,123		333,573
	Future site restoration costs		18,544		25,285		32,591		37,903		37,903
	Future income taxes		—		45,510		—		—		—
	Trust Unitholders’ Equity		558,590		641,965		817,203		867,213		1,101,463
			857,914		1,090,483		1,249,339		1,188,694		1,537,394
US GAAP(2)
	Trust Unitholders’ Equity		208,739		319,553		520,899		583,033		817,283
OTHER BALANCE SHEET DATA
Debt to total book capitalization(4)			29.3%		30.9%		29.7%		20.4%		23.4%
US GAAP(2)
	Debt to total book capitalization(4)		52.5%		47.3%		39.9%		27.3%		29.2%

(1)	Pro forma distributable income for the year ended December 31, 2001 and the six months ended June 30, 2002 does not take into account the reserve to be established in Pengrowth Corporation. See “Distributions.”
(2)	Please see note 13 to the consolidated financial statements as at and for the years ended December 31, 2000 and 2001, note 13 to the consolidated financial statements as at and for the years ended December 31, 1999 and 2000, the U.S. GAAP Reconciliation in respect of the interim consolidated financial statements as at June 30, 2002 and for the six months ended June 30, 2001 and 2002, and note 4 to the unaudited pro forma consolidated financial statements for the periods ended December 31, 2001 and June 30, 2002.
(3)	EBITDA represents earnings before interest expense, taxes, depreciation and amortization. We have calculated EBITDA as net income plus the following expenses: interest, capital taxes and other, and depletion, depreciation and future site restoration. EBITDA is presented because we believe it is frequently used by security analysts and others in evaluating companies and their ability to service debt. However, EBITDA should not be considered as an alternative to net revenue as a measure of liquidity or as an alternative to net income as an indicator of our operating performance or any other measure of performance in accordance with Canadian GAAP or United States GAAP. EBITDA, as we use the term herein, may not be comparable to EBITDA as reported by other entities.
(4)	Long-term debt divided by long-term debt plus trust unitholders’ equity.

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Selected Reserve Information

     The following tables show selected oil and natural gas reserve data for the New B.C. Properties as well as Pengrowth on a pro forma basis as at July 1, 2002 including the New B.C. Properties. We have derived the following tables from the GLJ July Report.These tables should be read together with the information set out under “Business — Reserves” and, in particular, the notes set out under “Business — Reserves — Notes to Reserves”. The bold face information in the following tables indicates the information ordinarily disclosed in accordance with U.S. reserves disclosure guidelines. For a description of certain differences between estimating reserves under U.S. reserve disclosure guidelines and Canadian reserve disclosure guidelines, please read “Presentation of Our Reserve Information.”

     The tables below summarize the reserves as at July 1, 2002 associated with the New B.C. Properties.

New B.C. Properties Reserves

Constant Prices and Costs(1)

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		10,593		1,157		58.7		21,530		8,712		920		45.5		17,216		457		337		321		300		283
Proved Non-Producing		3,664		273		26.8		8,411		3,054		216		20.4		6,663		176		96		87		77		68
Total Proved		14,257		1,430		85.5		29,941		11,766		1,136		65.9		23,879		633		433		408		377		351
Risked Probable		2,550		302		21.1		6,367		2,050		240		16.2		4,999		133		67		61		54		47
Total Established		16,807		1,732		106.6		36,308		13,861		1,376		82.1		28,878		766		500		469		431		398

(1)  Assuming prices remain constant for oil at US$28.00 per bbl for West Texas Intermediate at Cushing, Oklahoma FOB and at $42.75 per bbl for light, sweet crude oil at Edmonton FOB and for gas at $4.85 per mcf for natural gas (Alberta average) and $43.25, $24.75 and $30.75 per bbl of condensate, propane and butane respectively, at Edmonton FOB.

New B.C. Properties Reserves

Escalated Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		10,499		1,150		58.3		21,369		8,636		915		45.3		17,094		346		264		253		239		226
Proved Non-Producing		3,668		273		26.9		8,422		3,064		216		20.3		6,674		133		69		63		55		49
Total Proved		14,167		1,423		85.2		29,791		11,700		1,131		65.6		23,768		479		334		316		294		275
Risked Probable		2,514		301		21.0		6,313		2,016		239		16.2		4,949		103		51		46		41		36
Total Established		16,681		1,724		106.2		36,104		13,716		1,370		81.8		28,717		582		385		362		334		311

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     The tables below summarize our pro forma reserves as at July 1, 2002, including the New B.C. Properties.

Pro Forma Reserves

(Including the New B.C. Properties)

Constant Prices and Costs(1)

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		68,630		14,155		316.8		135,592		57,060		10,267		251.1		109,185		2,390		1,424		1,330		1,214		1,122
Proved Non-Producing		26,290		7,279		148.2		58,269		21,643		5,575		117.5		46,801		924		442		389		326		275
Total Proved		94,920		21,434		465.0		193,861		78,703		15,842		368.6		155,986		3,314		1,866		1,719		1,540		1,397
Risked Probable		19,912		4,228		83.6		38,063		15,834		3,056		62.9		29,373		711		261		229		191		163
Total Established		114,832		25,662		548.6		231,924		94,537		18,898		431.5		185,359		4,025		2,127		1,948		1,731		1,560

(1)  Assuming prices remain constant for oil at US$28.00 per bbl for West Texas Intermediate at Cushing, Oklahoma FOB and at $42.75 per bbl for light, sweet crude oil at Edmonton FOB and for gas at $4.85 per mcf for natural gas (Alberta average) and $43.25, $24.75 and $30.75 per bbl of condensate, propane and butane respectively, at Edmonton FOB.

Pro Forma Reserves

(Including the New B.C. Properties)

Escalated Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		68,161		14,478		323.0		136,471		57,380		10,488		254.6		110,306		1,783		1,126		1,059		977		910
Proved Non-Producing		26,180		7,165		146.1		57,694		22,671		5,481		115.6		47,416		655		299		261		213		176
Total Proved		94,341		21,643		469.1		194,165		80,051		15,969		370.2		157,722		2,438		1,425		1,320		1,190		1,086
Risked Probable		19,896		4,257		84.1		38,174		16,276		3,083		63.3		29,905		575		203		177		147		125
Total Established		114,237		25,900		553.2		232,339		96,327		19,052		433.5		187,627		3,013		1,628		1,497		1,337		1,211

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Risk Factors

     Investing in our trust units involves certain risks. See “Risk Factors” beginning on page 19.

Certain Income Tax Considerations

     Owning the trust units may subject you to tax consequences. See the tax discussion under “Certain Income Tax Considerations”. You should also consult your tax advisor.

Certain Canadian Income Tax Considerations

     Unitholders who are resident in Canada will generally be required to include, in computing income for the year, the portion of the net income of Pengrowth Trust that is paid or payable to the unitholder in the year. An amount will be considered payable to a unitholder in a particular year if the unitholder becomes entitled to enforce payment of the amount in that year. Amounts paid or payable to a unitholder in a taxation year in excess of the unitholder’s proportionate share of Pengrowth Trust’s net income will generally not be included in a unitholder’s income, however, such amount will reduce the adjusted cost base of the unitholder’s trust unit. If the adjusted cost base of a unitholder’s trust unit is negative, such negative amount will be considered a capital gain realized by the unitholder. Unitholders who dispose of a trust unit will generally realize a capital gain (or capital loss) to the extent that the proceeds of disposition are greater (or less) than the aggregate of the unitholder’s adjusted cost base of the trust unit and any reasonable costs associated with the disposition. One-half of any capital gain will be included in a unitholder’s income. Provided that Pengrowth Trust maintains its status as a mutual fund trust, the trust units will be qualified investments for trusts governed by RRSPs, RRIFs, RESPs or DPSPs.

     Unitholders who are not resident in Canada will generally be subject to a 25% withholding tax on distributions of net income from Pengrowth Trust unless such rate is reduced by a tax treaty between Canada and the unitholder’s jurisdiction of residence. Unitholders residing in the United States will generally be subject to a 15% Canadian withholding tax on distributions of net income from Pengrowth Trust. To the extent that Canadian withholding tax is applied to the non-taxable portion of a distribution, unitholders should generally be entitled to a refund thereof if a tax form is filed within certain time limits. A non-resident unitholder will not be subject to tax on the disposition of a trust unit unless such trust unit constitutes taxable Canadian property to the unitholder.

     See “Certain Income Tax Considerations — Certain Canadian Federal Income Tax Considerations”.

Certain United States Income Tax Considerations

     We have elected to be treated as a partnership for United States income tax purposes. Unitholders resident in the United States will be required to include their share of our taxable income (or, subject to limitations, our loss) on their income tax returns, regardless of cash distributions. Unitholders will be entitled to a depletion allowance based upon their purchase price for their trust units. On disposition of trust units, the depletion deductions are subject to recapture. Because the trust units will be publicly traded, Pengrowth Trust will not be treated as a corporation for United States federal income tax purposes only if 90% or more of its gross income consists of qualifying income. Although Pengrowth Trust expects to satisfy the 90% requirement at all times, if it fails to satisfy this requirement, it will be treated as a foreign corporation, and could be treated as a passive foreign investment company for United States federal income tax purposes. Pengrowth Trust may not be an appropriate investment for certain types of entities, such as tax-exempt organizations and regulated investment companies.

     See “Certain Income Tax Consequences — Certain United States Federal Income Tax Considerations”.

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RISK FACTORS

     You should carefully consider the risks and uncertainties described below and all other information contained in this prospectus before making an investment decision. You should also refer to the other information included or incorporated by reference in this prospectus, including our financial statements and the related notes and the risks described under “Risk Factors” in the Renewal Annual Information Form of Pengrowth Trust dated May 17, 2002.

     If any of the following risks occur, our production, revenues and financial condition could be materially harmed, with a resulting decrease in distributions on, and the market price of, our trust units. As a result, the trading price of our trust units could decline, and you could lose all or part of your investment.

Our distributions are sensitive to the volatility of crude oil and natural gas prices.

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

•  political conditions in the Middle East;

•  worldwide economic conditions;

•  weather conditions;

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

•  the level of consumer demand;

•  the price and availability of alternative fuels;

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

•  the effect of worldwide energy conservation measures; and

•  government regulation.

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

Our distributions are affected by production and development costs and capital expenditures.

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

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

Our actual results will vary from our reserve estimates, and those variations could be material.

     The value of the trust units will depend upon, among other things, Pengrowth Corporation’s reserves. In making strategic decisions, we generally rely upon reports prepared by our independent reserve engineers. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the underlying properties will vary from estimates and those variations could be material. Changes in the prices of,

20

and markets for, oil and natural gas from those anticipated at the time of making such assessments will affect the return on, and value of, our trust units. The reserve and cash flow information contained in this prospectus or contained in the documents incorporated by reference represent estimates only. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:

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

•  the assumed effect of government regulation;

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

•  initial production rates;

•  production decline rates;

•  ultimate recovery of reserves;

•  marketability of production; and

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

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

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

Our reserves will be depleted over time and our level of distributable income and the value of our trust units could be reduced if reserves are not replaced.

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

Our operation of oil and natural gas wells could subject us to environmental claims and liability.

     The oil and natural gas industry is subject to extensive environmental regulation, which imposes restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and gas industry operations. In addition, Canadian legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of this or other legislation may

21

result in fines or the issuance of a clean-up order. Ongoing environmental obligations will be funded out of our cash flow and could therefore reduce distributable income payable to our unitholders.

We may be unable to successfully compete with other companies in our industry.

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

Incorrect assessments of value at the time of acquisitions could adversely affect the value of our trust units and our distributions.

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

Our level of debt could have a material adverse effect on our ability to pay distributions to our unitholders.

     Pengrowth Corporation has a $425 million revolving credit facility syndicated among nine financial institutions having a 364 day revolving period and, should the period not be extended, a three year amortization period as well as a $35 million demand operating line of credit. We draw upon these credit facilities from time to time to make acquisitions of oil and natural gas properties and to fund capital investments in our properties. In addition, as interim financing for the acquisition of the New B.C. Properties, Pengrowth Corporation has obtained an aggregate of $285 million in additional credit facilities. We pay interest at fluctuating rates with respect to a portion of our outstanding debt under our existing credit facilities. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount Pengrowth is required to apply to service its debt. Certain covenants in the agreements with our lenders may also limit the amount of the royalty paid by Pengrowth Corporation to Pengrowth Trust and the distributions paid by us to our unitholders. We cannot assure you that the amount of our credit facility will be adequate for our future financial obligations or that we will be able to obtain additional funds. If we become unable to pay our debt service charges or otherwise cause an event of default to occur, our lenders may foreclose on or sell the properties. The net proceeds of any such sale will be allocated firstly, to the repayment of our lenders and other creditors and only the remainder, if any, would be payable to Pengrowth Trust by Pengrowth Corporation in respect of the royalty.

Loss of our key management and other personnel could impact our business.

     Our unitholders are entirely dependent on the management of Pengrowth Management and Pengrowth Corporation with respect to the acquisition of oil and gas properties and assets, the development and acquisition of additional reserves, the management and administration of all matters relating to properties and the administration of Pengrowth Trust. The loss of the services of key individuals who currently comprise the management team of Pengrowth Management and Pengrowth Corporation could have a detrimental effect on Pengrowth Trust. In addition, increased activity within the oil and gas sector can increase the cost of goods and services and make it more difficult to have and retain qualified professional staff.

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Trust distributions are affected by marketability of production.

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

The operation of a significant portion of our properties is largely dependent on the ability of third party operators, and harm to their business could cause delays and additional expenses in our receiving revenues.

     The continuing production from a property, and to some extent the marketing of production, is dependent upon the ability of the operators of our properties. Currently 42% of our properties are operated by third parties, based on daily production. If, in situations where we are not the operator, the operator fails to perform these functions properly or becomes insolvent, then revenues may be reduced. Revenues from production generally flow through the operator and, where we are not the operator, there is a risk of delay and additional expense in receiving such revenues.

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

Our distributions could be adversely affected by unforeseen title defects.

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

Fluctuations in foreign currency exchange rates could adversely affect our business.

     World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/ United States dollar exchange rate which fluctuates over time. A material increase in the value of the Canadian dollar may negatively impact our net production revenue. To the extent that we have engaged, or in the future engage, in risk management activities related to commodity prices and foreign exchange rates, through entry into oil or natural gas price hedges and forward foreign exchange contracts or otherwise, we may be subject to unfavourable price changes and credit risks associated with the counterparties with which we contract.

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

Our insurance coverage could be inadequate.

     We are exposed to a number of risks and maintain liability insurance, where available, in amounts consistent with industry standards. However, we may become liable for damages arising from events against

23

which we cannot insure, or against which we may elect not to insure because of high premium costs or other reasons. The costs to repair such damage or pay such liabilities could reduce distributable income. Our operations are subject to all of the risks normally associated with drilling for, and the production and transportation of oil and natural gas. Such risks and hazards include encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injury, loss of life, property damage and environmental damage. Although we have safety and environmental policies in place to protect operators and employees, as well as to meet regulatory requirements, and although we have liability insurance policies in place, we cannot fully insure against all such risks. Costs incurred to repair such damage or pay such liabilities will reduce payments made by Pengrowth Corporation to Pengrowth Trust.

Being a limited purpose trust makes Pengrowth Trust largely dependent upon the operations and assets of Pengrowth Corporation.

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

The Sable Offshore Energy Project properties may present challenges and risks that we have not faced in the past.

     The Sable Offshore Energy Project properties are offshore and we have had no other experience with offshore projects. Moreover, they are in an earlier stage of development than most of our previous acquisitions have been and have not been on production for an extended period of time. As a result, the Sable Offshore Energy Project properties may present challenges and risks that Pengrowth has not faced in the past. Furthermore, because of the early stage of development and relatively brief production history of these properties, events which could materially adversely affect our interests are more likely to occur.

The New B.C. Properties carry different risks from those associated with many of our past acquisitions.

     The New B.C. Properties have a reserve life index of 6.3 years compared to our portfolio reserve life index of 13.0 years prior to the acquisition of the New B.C. Properties. Accordingly, the commercial benefits we expect to receive from the acquisition of the New B.C. Properties are highly dependent on near-term commodity prices, interest rates and exchange rates. Our ability to enhance value will be dependant upon our ability to enter into future transactions with competent industry partners upon comprehensive terms. There can be no assurance that we will be successful in entering into such transactions on favourable terms.

We may be required to use a portion of our revenue to fund further development of the New B.C. Properties which could reduce the amount of distributions to our unitholders.

     Gilbert Laustsen Jung Associates Ltd. forecasts that total capital investment in respect of the New B.C. Properties required to achieve anticipated cash flows will be $21.3 million over the next five years (in respect of established reserves). Additional capital may be required to effectively develop the New B.C. Properties and to tie-in proven undeveloped reserves to existing production infrastructure. These capital expenditures may reduce the amount of our distributable income.

Management may have conflicts of interest.

     Pengrowth Management provides advisory, management and administrative needs of Pengrowth Trust and Pengrowth Corporation in consideration for a management fee which is currently based in part on net

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production revenue of Pengrowth Corporation. This arrangement may create an incentive for Pengrowth Management to maximize the net production revenue of Pengrowth Corporation, rather than maximizing its distributable income, which is the primary basis for calculating distributions available to unitholders. Pengrowth Management also receives an acquisition fee which is based, in part, upon the aggregate dollar amount of the completed acquisitions in each year. This arrangement may create an incentive for Pengrowth Management to maximize the number of completed acquisitions notwithstanding that such acquisitions may be contrary to the interests of unitholders.

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

     Any expenses which Pengrowth Management incurs in relation to the business of Pengrowth Corporation and Pengrowth Trust are required to be paid by Pengrowth Corporation. These expenses are not subject to a limit other than as may be provided under a periodic review by the board of directors of Pengrowth Corporation and, as a result, there may not be an incentive for Pengrowth Management to minimize these expenses.

We may incur material costs to comply with, or as a result of, health, safety and environmental laws and regulations.

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

Lower oil and gas prices increase the risk of write-downs of our oil and gas property investments.

     Under Canadian accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” which is based, in part, upon estimated future net cash flows from reserves. If the net capitalized costs exceed this limit, we must charge the amount of the excess against earnings. As oil and gas prices decline, our net capitalized cost may approach and, in certain circumstances, exceed this cost ceiling, resulting in a charge against earnings. Under United States accounting rules, the cost ceiling is generally lower than under Canadian rules because the future net cash flows used in the United States ceiling test are discounted to a present value. Accordingly, we would have more risk of a ceiling test write-down in a declining price environment if we reported under United States generally accepted accounting principles. While these write-downs would not affect cash flow, the charge to earnings could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in our current or future credit agreements or other debt instruments.

Changes in Canadian legislation could adversely affect the value of our trust units.

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

The investment eligibility of our trust units could be adversely affected if Pengrowth Trust ceases to qualify as a mutual fund trust.

     If Pengrowth Trust ceases to qualify as a mutual fund trust under Canadian tax legislation, the trust units will cease to be qualified investments for trusts governed by RRSPs, RRIFs, RESPs and DPSPs. Where at the end of any month a RRSP, RRIF, RESP or DPSP holds trust units that are not qualified investments, the RRSP, RRIF, RESP or DPSP must, in respect of that month, pay a tax under Part XI.1 of the Tax Act

25

(Canada) equal to 1% of the fair market value of the trust units at the time those trust units were acquired by the RRSP, RRIF, RESP or DPSP. In addition, trusts governed by a RRSP and a RRIF will be subject to tax on the income attributable to the holding of non-qualified investments and on full capital gains, if any, realized on the disposition of trust units. Where a trust governed by a RRSP or a RRIF acquires trust units that are not qualified investments, the value of the investment will be included in the income of the annuitant for the year of the acquisition. Trusts governed by a RESP which hold trust units that are not qualified investments may have their registration revoked by the Canada Customs and Revenue Agency.

     If Pengrowth Trust ceases to qualify as a mutual fund trust, it will be required to pay a tax under Part XII.2 of theIncome Tax Act(Canada). The payment of Part XII.2 tax by Pengrowth Trust may have adverse income tax consequences for certain unitholders including non-resident persons and RRSPs, RRIFs, RESPs or DPSPs that acquire an interest in Pengrowth Trust directly or indirectly from another unitholder.

     If, at any particular time, Pengrowth Trust may reasonably be considered to be established or maintained primarily for the benefit of non-residents of Canada, or any of the conditions described under the heading “Certain Income Tax Considerations — Certain Canadian Federal Income Tax Considerations” cease to be met, it will lose its status as a mutual fund trust. There can be no assurance that Pengrowth Trust will always be able to satisfy these requirements and will not lose its status as a mutual fund trust.

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

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

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

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

The trust units are not equivalent to shares.

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

     Trust units will have no value when reserves from the properties can no longer be economically produced or marketed and, as a result, cash distributions do not represent a “yield” in the traditional sense as they

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represent both return of capital and return on investment. Subscribers for trust units will have to obtain the return of capital invested out of cash flow derived from their investments in the trust units during the period when reserves can be economically recovered. Accordingly, we give no assurances that the distributions you receive over the life of your investment will meet or exceed your initial capital investment.

You may experience substantial future dilution given that the success of the trust is dependent upon raising capital.

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

The limited liability of unitholders is uncertain.

     The trust indenture between Pengrowth Corporation and Computershare Trust Company of Canada, as trustee, provides that no unitholder will be subject to any personal liability in connection with Pengrowth Trust or its obligations and affairs, and the satisfaction of claims of any nature arising out of or in connection therewith is only to be made out of Pengrowth Trust’s assets. Additionally, the trust indenture states that no unitholder is liable to indemnify or reimburse Computershare for any liabilities incurred by Computershare with respect to any taxes payable by or liabilities incurred by Pengrowth Trust or Computershare, and all such liabilities will be enforceable only against, and will be satisfied only out of, Pengrowth Trust’s assets. It is intended that the operations of Pengrowth Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the unitholders for claims against Pengrowth Trust. Notwithstanding the foregoing, because of uncertainties in the law relating to trusts such as Pengrowth Trust, there is a risk that a unitholder could be held personally liable for obligations of Pengrowth Trust to the extent that claims are not satisfied by Pengrowth Trust.

Canadian and United States practices differ in reporting reserves and production.

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

     We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the United States Securities and Exchange Commission and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves; however, we separately estimate our reserves using prices and costs held constant at the date of the reserve report in accordance with the Canadian reserve reporting requirements. These requirements are similar to the constant pricing reserve methodology utilized in the United States, except that, in lieu of utilizing actual prices for production at July 1, 2002 held constant for the economic life of the reserves as would be required by the United States reporting requirements, we utilize forecast prices for the fourth quarter of 2002, as set forth in the “October 1, 2002 Gilbert Laustsen Jung Associates Ltd. Product Price and Market Forecast for the Canadian Oil and Gas Industry” constituting part of the GLJ July Report, held constant for the economic life of the reserves (the actual price of West Texas Intermediate crude oil at Cushing, Oklahoma at July 1, 2002 was US$26.83 whereas the forecast price of West Texas Intermediate crude oil at Cushing, Oklahoma for the fourth quarter of 2002 was US$28.00).

     We include in this prospectus estimates of probable reserves along with estimates of proved reserves. The United States Securities and Exchange Commission generally prohibits the inclusion of estimates of probable reserves in filings made with it. This prohibition does not apply to Pengrowth Trust because it is a Canadian foreign private issuer that is filing this prospectus under the multi-jurisdictional disclosure system.

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

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

Unitholders who are United States persons face income tax risks.

     You are urged to read “Material United States Federal Income Tax Considerations” for a more complete discussion of the following United States federal income tax risks related to owning and disposing of our trust units, including the following:

•  Because the trust units will be publicly traded, Pengrowth Trust will not be treated as a corporation for U.S. federal income tax purposes only if 90% or more of its gross income consists of qualifying income. Although Pengrowth Trust expects to satisfy the 90% requirement at all times, if it fails to satisfy this requirement, it will be treated as a foreign corporation. If Pengrowth Trust were treated as a corporation, it could be a passive foreign investment company or “PFIC”. Treatment of Pengrowth Trust as a PFIC could result in a material reduction in the after-tax return to the unitholders, likely causing a substantial reduction in the value of the trust units.

•  A successful U.S. Internal Revenue Service (“IRS”) contest of the federal income tax positions we take or have taken may adversely affect the market for our trust units. For example, the IRS could challenge our position that the royalty from Pengrowth Corporation should be treated as a non-operating, non-working interest. We have not requested a ruling from the IRS with respect to this or any other matter affecting us other than relating to the timeliness of our election to be treated as a partnership. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take or have taken. It may be necessary to resort to administrative or court proceedings to sustain our counsel’s conclusions or those positions. A court may not concur with our counsel’s conclusions or the positions we take or have taken. Any contest with the IRS may materially and adversely impact the U.S. federal income tax consequences to unitholders and, therefore, the market for our trust units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne by us and indirectly by the unitholders.

•  Tax gain or loss on disposition of trust units could be different from expected. If you sell your trust units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in the trust units. Prior distributions in excess of the total net taxable income you were allocated, which decreased your tax basis in the trust units, will, in effect, become taxable income to you if the trust units are sold at a price greater than your tax basis in those trust units, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. Should the IRS successfully contest some positions we take, you could recognize more gain on the sale of trust units than would be the case under those positions, without the benefit of decreased income in prior years. Also, if you sell trust units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

•  We have registered with the IRS as a “tax shelter.” This may increase the risk of an IRS audit of us or a unitholder. The tax laws require that some types of entities register as “tax shelters” in response to the perception that they claim tax benefits that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in our unitholders’ tax returns and may lead to audits of unitholders’ tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.

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•  We will treat each owner of trust units as having the same tax benefits without regard to the specific trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of our trust units. Because we cannot match transferors and transferees of our trust units, we will adopt depletion, depreciation and amortization positions that do not conform with all aspects of final Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of trust units and could have a negative impact on the value of our trust units or result in audit adjustments to your tax returns.

•  Pengrowth Trust may not be an appropriate investment for certain types of entities. For example, there is a risk that some of Pengrowth Trust’s income could be unrelated business taxable income with respect to tax-exempt organizations. Furthermore, we anticipate that substantially all of Pengrowth Trust’s gross income will not be “qualifying income” for purposes of the rules relating to regulated investment companies.

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RECENT ACQUISITION

     On October 1, 2002, with an effective date of July 1, 2002, we acquired substantially all of the oil and natural gas assets held by Calpine Canada Natural Gas Partnership in northern British Columbia for $387.5 million, before adjustments, with the consideration consisting of cash and the tendering of debt securities of Calpine Corporation and its subsidiaries purchased by us on the open market. On October 4, 2002, we sold to Progress Energy Ltd. for $25.4 million, before adjustments, seven producing properties and a 50% interest in 61,000 acres (30,500 acres net) of undeveloped oil and natural gas rights from the B.C. Asset Package, which properties are located outside of our core areas in the New B.C. Properties. These sold assets have approximately 1,000 boepd of associated production and 3.0 mmboe of proved oil and natural gas reserves. Our net purchase price for the New B.C. Properties, after taking into account purchase price adjustments and the sale to Progress Energy Ltd., was $345.6 million. Based on the GLJ July Report, forecast production from the New B.C. Properties for the second half of 2001 is 39.1 mmcfpd (29.5 mmcfpd net) of natural gas and 9,268 bblpd (6,975 bblpd net) of oil and NGLs for a total of approximately 15,785 boepd (11,901 boepd net). Pengrowth’s working interest share of established reserves associated with the New B.C. Properties is estimated to be 36.1 mmboe (23.9 mmboe on a net proved reserves basis), comprised of gross proved reserves of 29.8 mmboe and risked probable reserves of 6.3 mmboe (5.3 mmboe net), of which approximately 49% (46% on a net proved reserves basis) is natural gas, based on the GLJ July Report (see also “Business — Reserves”).

     The New B.C. Properties constitute a new focus area for us that complements our current interests in the Alberta and Saskatchewan sector of the Western Canadian Sedimentary Basin and in the Sable Offshore Energy Project located offshore Nova Scotia. This acquisition provides us with a significant property base in British Columbia, with 144,700 net developed acres and 247,700 net undeveloped acres. We also expect that Pengrowth will have additional upside through development opportunities on the acquired properties pursuant to farmouts of exploration prospects on the undeveloped acreage.

     We operate substantially all of the New B.C. Properties, which include 10 oil batteries, 17 gas compressors and approximately 186 net producing wells. Calpine Canada Natural Gas Partnership will retain ownership of certain properties in the Province of British Columbia totaling approximately 40,000 net undeveloped acres. Pengrowth will receive a 2% royalty on these acres, and Calpine will retain a 2% royalty over a similar amount of selected acreage acquired by us which has deep natural gas potential. Pengrowth has entered into a marketing agreement with Calpine whereby Pengrowth has granted Calpine the right to purchase the oil and gas production from the New B.C. Properties on market terms.

     We expect that this acquisition will provide us with several significant benefits. The New B.C. Properties allow us to expand our operations into northern British Columbia with a significant number of proved producing properties that will provide us additional development opportunities. The relatively high production rates and shorter reserve lives associated with these properties provide a balance to our existing portfolio of properties that are characterized by relatively lower production rates and longer reserve lives. The New B.C. Properties have a reserve life index of approximately 6.3 years and, as a result, our portfolio reserve life index decreased from 13.0 years (11.2 on a net proved reserves basis) to approximately 11.1 years (9.5 on a net proved reserves basis). However, due to the relatively higher production rates from the New B.C. Properties and the current level of commodity prices that can be obtained for the production from these properties, we anticipate that in the near term this acquisition will allow us to increase distributions and also retain funds within Pengrowth Corporation in an amount equivalent to approximately 10% of distributable income of Pengrowth Trust as a reserve for future capital obligations and future distributions. This policy of withholding a portion of cash flow as a reserve will be reviewed from time to time by the board of directors of Pengrowth Corporation based on commodity prices and capital and other commitments, and may be changed from time to time as circumstances warrant.

     We have increased our level of risk management in conjunction with the acquisition of the New B.C. Properties. In contemplation of the acquisition of the New B.C. Properties, we put in place the following additional financial hedges: 6,000 bblpd of crude oil for 2003 at a price averaging $41.09 per bbl (WTI basis) and 5,500 bblpd of crude oil for 2004 at $37.90 per bbl. See “Business — Current Marketing and Hedging Activities”. Both of these positions are at a premium to the Gilbert Laustsen Jung Associates Ltd. price forecast effective for October 1, 2002. The application of this price forecast to the engineering evaluation

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proposed by Gilbert Laustsen Jung Associates Ltd. was an important consideration in our evaluation of the New B.C. Properties. Our increased hedging position also allows us to manage the risks associated with fluctuating prices for production from the New B.C. Properties which have relatively higher production rates than the balance of our portfolio, and hence the realized value will be influenced to a larger degree by short term fluctuations in commodity prices. See “Business — Current Marketing and Hedging Activities”.

     Our acquired undeveloped lands of approximately 247,700 net undeveloped acres will provide us with significant farmout potential. As a first step in developing this farmout potential, we have entered into a farmout agreement with Progress Energy Ltd. in respect of a one-half interest in 61,000 net undeveloped acres that we share in the Fort St. John block of the B.C. Asset Package. Under this agreement Progress Energy Ltd. will be required to incur all of the exploration expenses in respect of 100% of the shared acreage to earn an interest in our share of this acreage. Progress Energy Ltd. will be required to spend a minimum of $10 million on exploration on this acreage over the next 18 months to drill approximately 15 wells. On that portion of our acreage in which Progress Energy Ltd. earns an interest by drilling, we will retain a 10% overriding royalty which will not require us to make additional capital expenditures. This farmout provides Pengrowth with upside exposure to high impact prospects without the associated exploration risk.

     We do not typically conduct exploration activities. Therefore, our ability to enhance the value of undeveloped acreage will depend in part on our ability to enter into effective farmout arrangements with industry partners. Our agreement with Progress Energy Ltd. is the first example of this type of agreement. We will seek other farmout opportunities for our undeveloped lands.

     The following are important facts concerning the acquisition of the New B.C. Properties:

•  The acquisition increased our forecast average daily production for the second half of 2002 by 38% from approximately 41,352 boepd (32,466 boepd net) to 57,137 boepd (44,510 boepd net), based on the GLJ July Report.

•  The properties generate annualized cash flow of approximately $100 million prior to capital expenditures, based on actual operating and financial results for the first six months of 2002. See the table “Estimated Cash Flows from Pengrowth’s Working Interest Shares of Pro Forma Established Revenues” under “Business — Reserves.”

•  The combination of expected increased cash flow per trust unit, current commodity prices, and our hedging program should permit us to increase distributions while establishing a reserve within Pengrowth Corporation for future capital expenditures or distributions. See “Distributions — Distribution Policy”.

•  The acquisition is geographically focused, with approximately 50% of the value of the New B.C. Properties in three producing properties and 85% of the value in the largest ten properties.

•  The New B.C. Properties are characterized by high percentage working interests, with production comprised substantially of high gravity crude oil and natural gas with liquids.

•  Operating costs for the New B.C. Properties were approximately $3.70 per boe for the first six months of 2002, well below our average of $7.77 per boe for the first half of 2002. As a result, we expect the addition of the New B.C. Properties to have a positive impact on our average operating costs and netbacks.

•  Gilbert Laustsen Jung Associates Ltd. forecasts capital expenditures totalling $21.7 million on the New B.C. Properties through the end of 2007 in respect of established reserves.

     We have assumed operatorship of most of the fields comprising the New B.C. Properties, allowing Pengrowth to control operating costs and general and administrative costs, and to enhance productivity from the properties acquired. We have hired former Calpine Canada Natural Gas Partnership operating personnel

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to conduct field operations and have retained additional technical personnel from Calpine’s office staff to enable us to manage the assets and to identify new opportunities.

     We expect the acquisition of the New B.C. Properties to result in the payment of an acquisition fee of approximately $2.3 million by Pengrowth to Pengrowth Management.

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DISTRIBUTIONS

     Subscribers for trust units in this offering will be eligible to receive distributions on the trust units commencing December 15, 2002.

     Our structure was established to provide an efficient mechanism to distribute, to our unitholders, the royalty income received by Pengrowth Trust from Pengrowth Corporation. Pengrowth Corporation acquires, owns and operates working interests and royalty interests in oil and natural gas properties. The assets of Pengrowth Trust include 99.98% of the outstanding royalty units of Pengrowth Corporation. The royalty units of Pengrowth Corporation entitle the holders thereof to receive a 99% share of the royalty income related to the oil and natural gas interests of Pengrowth Corporation. Royalty income represents essentially all of the revenues received by Pengrowth Corporation from its oil and natural gas interests, less operating costs, royalties, general and administrative expenses, management fees, debt service charges, taxes and any amount retained as a reserve to fund future capital obligations and future payments of royalty income to Pengrowth Trust. Pengrowth Trust’s share of royalty income, together with any lease, interest and other income of Pengrowth Trust, less general and administrative expenses, management fees, debt repayment, taxes and other expenses (provided that there is no duplication of expenses already deducted from royalty income), forms the distributable income of Pengrowth Trust.

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

     Distributable income for the six months ended June 30, 2002, as well as the total distributable income for each of the five fiscal years are as follows:

	Distributable Income Per Trust Unit(1)(2)
	1997		1998		1999		2000		2001		2002
Total	$	2.02	$	1.53	$	2.49	$	3.79	$	3.01	$	0.95	(3)

(1)	Based on actual distributions paid or declared.
(2)	Note that distributable income may be different than distributions paid primarily because distributions are paid in the month following computation of distributable income. In the future funds may be retained by Pengrowth Trust to even out distributions and offset the impact of volatility in commodity prices and other factors.
(3)	For the six months ended June 30, 2002.

     All amounts distributed to Canadian resident unitholders from the inception of Pengrowth Trust to December 31, 2001 have been treated as a return of capital for Canadian income tax purposes, except that in 1996, 1999, 2000 and 2001, Pengrowth Trust had taxable income per trust unit of $0.2044, $0.6742, $1.9831 and $1.7951, respectively, which was allocated to unitholders representing 12.2%, 30.4%, 55.8% and 51.4% of total cash distributions for 1996, 1999, 2000 and 2001, respectively. For Canadian residents, amounts which are treated as a return of capital generally are not required to be included in a unitholder’s income, but such amounts will reduce the adjusted cost base to the unitholder of the trust units.

     Distributions of Pengrowth Trust’s distributable income to a non-resident of Canada are subject to a 25% Canadian withholding tax at source unless such rate of tax is reduced under an applicable tax treaty (as it would be in the case of a U.S. resident). Under current practises, Computershare Trust Company of Canada, as trustee, remits Canadian withholding tax on behalf of the registered non-resident unitholders and broker-nominees remit Canadian withholding tax on behalf of non-registered non-resident unitholders on the full amount of all distributions. In approximately March of each year, Pengrowth Trust will determine the portion of its distributions for the prior year which are non-taxable and communicate this information to the withholding agents such as Computershare. To the extent that a withholding agent has withheld Canadian

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withholding tax on the non-taxable portion of a distribution, such agent may, on behalf of unitholders, apply for a refund by filing Canada Customs and Revenue Agency form NR7-R “Application for Refund of Non-Resident Tax Withheld”.

     Distributions to unitholders resident in the United States are subject to Canadian withholding tax at the reduced rate of 15%. Withholding taxes are generally refundable to residents of the United States on the non-taxable portion of distributions on the same basis as described above. Based upon distributions paid in 2002, including the October 15, 2002 distribution declared September 19, 2002, current commodity prices, forecast production for the remainder of 2002 based on the GLJ July Report, including the New B.C. Properties, and the receipt of net proceeds of $234.25 million pursuant to this offering, we estimate that the taxable component of distributions for 2002 holders of trust units resident in Canada will be 30% to 35%. The balance of Canadian withholding taxes can generally be credited or may be claimed as a deduction against income taxes payable by unitholders resident in the United States.

     Based on the GLJ July Report and the closing price of the trust units on the New York Stock Exchange of US$9.07 on October 11, 2002 we estimate that the amount which purchasers of trust units resident in the United States can claim for depreciation and depletion will be US$0.68 in 2003.

     See “Certain Income Tax Considerations” for a description of income tax consequences to both Canadian resident and United States resident unitholders. Subscribers should consult their own tax advisors.

     It has been our consistent policy to pay out substantially all of the distributable income of Pengrowth Trust to our unitholders. Distributable income is typically paid in the form of distributions in the month following the month in which they are earned. From time to time, the board of directors of Pengrowth Corporation may determine, on behalf of Pengrowth Trust, to cause Pengrowth Trust to withhold a portion of the distributable income in periods of high commodity prices in order to reduce the variability of distributions payable to unitholders resulting from commodity price fluctuations.

     At the special meeting of the holders of royalty units of Pengrowth Corporation held on April 23, 2002, the holders of royalty units amended the royalty indenture to permit the board of directors of Pengrowth Corporation to establish a reserve, within Pengrowth Corporation, of up to 20% of its gross revenue if the board of directors of Pengrowth Corporation determines that it would be advisable to do so in accordance with prudent business practices to provide for the payment of future capital expenditures or for the payment of royalty income in any future period. Subsequent to this unitholder action, the board of directors of Pengrowth Corporation authorized the establishment of a reserve to fund future capital obligations and future payments of royalty income to Pengrowth Trust. The reserve will be comprised of funds retained within Pengrowth Corporation in an amount equivalent to approximately 10% of the distributable income of Pengrowth Trust calculated as if the reserve had not been established. The reserve for future capital will offset some of our obligations in respect of capital for the next phase of development of the Sable Offshore Energy Project and the capital commitments which we have on an ongoing basis for our unitized reserves in western Canada.

     Based upon the anticipated near term cash flow from the New B.C. Properties, present commodity prices and the hedges we established in anticipation of completing the acquisition of the New B.C. Properties, the board of directors of Pengrowth Corporation determined that the reserve could be established by Pengrowth Corporation while nonetheless increasing near term distributions to unitholders. We will periodically consider our policy in respect of contributions to the reserve based upon prevailing commodity prices, anticipated capital expenditures, the magnitude of abandonment, reclamation and other liabilities, and the existence of other factors at the time.

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PRICE RANGE AND TRADING VOLUME OF TRUST UNITS

     Our trust units are traded on the Toronto Stock Exchange under the symbol “PGF.UN” and on the New York Stock Exchange under the symbol “PGH”. Our trust units began trading on the New York Stock Exchange on April 10, 2002. The following table sets forth the high and low trading prices, the total trading volume of the trust units on each of the New York Stock Exchange and the Toronto Stock Exchange and the combined trading volume of the trust units on the New York Stock Exchange and the Toronto Stock Exchange, for the periods indicated.

		New York Stock Exchange						Toronto Stock Exchange
															Combined
						Total							Total		Total
						Trading							Trading		Trading
		High		Low		Volume		High			Low		Volume		Volume
Period		(US$)		(US$)		(000s)		(Cdn$)			(Cdn$)		(000s)		(000s)
2000
	First Quarter								17.50			15.00		4,554		4,554
	Second Quarter								19.25			16.50		6,838		6,838
	Third Quarter								20.35			18.00		4,790		4,790
	Fourth Quarter								20.30			18.25		5,312		5,312
2001
	First Quarter								21.25			18.70		8,784		8,784
	Second Quarter								21.95			17.11		10,049		10,049
	Third Quarter								19.50			14.05		9,471		9,471
	Fourth Quarter								17.20			12.80		12,945		12,945
2002										��
	First Quarter								16.23			13.25		11,395		11,395
	April		10.90		9.50		657		17.00			14.90		3,988		4,645
	May		10.58		9.80		540		16.40			15.09		4,430		4,970
	June		10.40		9.53		587		15.48			14.60		4,170		4,757
	July		10.25		8.40		525		15.55			13.01		3,035		3,560
	August		9.99		9.07		231		15.63			14.46		2,505		2,727
	September		9.97		9.26		385		15.25			14.65		3,827		4,212
	October (through October 15)		9.47		9.05		197		14.99			14.31		1,901		2,098

     On October 15, 2002, the closing price of the trust units on the New York Stock Exchange was US$9.34 and on the Toronto Stock Exchange was Cdn$14.78.

35

USE OF PROCEEDS

     The gross proceeds of this offering will be approximately $250 million and the net proceeds of this offering will be approximately $234.25 million (after deducting the underwriting discounts and commissions of $13.75 million and the expenses of this offering estimated to be $2.0 million). The estimated net proceeds will increase to $l million if the underwriters exercise the over-allotment option in full.The net proceeds from this offering will be paid by Pengrowth Trust to Pengrowth Corporation all or primarily through the subscription for additional royalty units of Pengrowth Corporation, with any remainder to be paid by Pengrowth Trust to Pengrowth Corporation as a loan or otherwise provided to Pengrowth Corporation, to be determined based on the relevant tax balances in Pengrowth Corporation. Pengrowth Corporation will, in turn, use such funds to repay existing outstanding indebtedness of Pengrowth Corporation pursuant to interim facilities obtained by Pengrowth Corporation to fund the acquisition of the New B.C. Properties. RBC Dominion Securities Inc. and RBC Dain Rauscher Inc. are subsidiaries of the lender that provided these interim facilities, and which will receive the net proceeds of this offering to repay all, or a portion, of these additional facilities. If the over-allotment option is exercised, the aggregate net proceeds may exceed the amount outstanding pursuant to these interim facilities; any remaining proceeds after the repayment of these interim facilities will be used for capital expenditures or future acquisitions. See “Underwriting” and “Relationship between Pengrowth Corporation and Certain Underwriters”.

CAPITALIZATION OF PENGROWTH TRUST

     The following table sets forth the consolidated capitalization of Pengrowth Trust at December 31, 2001, and as at June 30, 2002, both actual and as adjusted to give effect to the acquisition of the New B.C. Properties and the issuance of 17,123,287 trust units in this offering for estimated net proceeds of $234.25 million and the application of net proceeds as described in “Use of Proceeds”. This table has been presented in Canadian dollars and is based on financial statements that have been prepared in accordance with Canadian GAAP. This table should be read in conjunction with the audited consolidated financial statements of Pengrowth Trust for the year ended December 31, 2001, the unaudited interim consolidated financial statements of Pengrowth Trust for the six months ended June 30, 2002 and the notes thereto, and the unaudited pro forma consolidated financial statements of Pengrowth Trust for the six months ended June 30, 2002 and the notes thereto.

							As at
							June 30, 2002, Pro
							Forma for the
							Acquisition of the
	As at			As at			New B.C. Properties
Description and Amount Authorized	December 31, 2001			June 30, 2002			and this Offering
	(audited,			(unaudited,			(unaudited,
	in thousands)			in thousands)			in thousands)
Long-term Debt(1)	$	345,456		$	219,123	(2)	$	333,573	(2)(4)(5)
Unitholders’ Equity	$	817,203	(3)	$	867,213	(2)(3)	$	1,101,463	(2)(3)(4)(6)
Trust Units (500,000,000 maximum)		82,240	(3)		90,347	(2)(3)		107,470	(2)(3)(4)(7)

(1)

Pengrowth Corporation has a $425 million revolving credit facility syndicated among nine financial institutions with an extendible 364 day revolving period and, should the period not be extended, a three year amortization period as well as a $35 million demand operating line of credit. As interim financing for the acquisition of the New B.C. Properties, Pengrowth Corporation has also obtained an aggregate of $285 million in additional credit facilities, which are completely drawn. All of the foregoing facilities are currently reduced by outstanding letters of credit in the amount of approximately $33.4 million. Pengrowth Corporation is in compliance with the terms of its credit facilities.

(2)

On June 4, 2002, Pengrowth Trust issued 8,000,000 trust units at a price of $15.40 per trust unit for total gross proceeds of $123.2 million.

36

(3)	As at December 31, 2001 and June 30, 2002, Pengrowth Trust had outstanding options to acquire an aggregate 3,106,635 and 4,156,451 trust units, respectively, pursuant to the Trust Unit Option Plan of Pengrowth Trust.
(4)	Based on the issuance of 17,123,287 trust units by Pengrowth Trust in this offering for estimated net proceeds of $234.25 million, after deducting the underwriting discounts and commissions of $13.75 million and the other expenses of the issue estimated to be $2.0 million.
(5)	$l if the over-allotment option is exercised in full.
(6)	$l if the over-allotment option is exercised in full.
(7)	$l if the over-allotment option is exercised in full.

37

SELECTED FINANCIAL INFORMATION

     The following table presents summary consolidated historical financial data for the years ended December 31, 1999, 2000 and 2001 and for the six month periods ended June 30, 2001 and 2002, in each case derived from the consolidated financial statements of Pengrowth Trust at each of these dates and for the periods then ended, as well as the Reconciliation of Interim Consolidated Financial Statements of Pengrowth Energy Trust for the six months ended June 30, 2002 to United States generally accepted accounting principles and from the unaudited pro forma consolidated balance sheet of Pengrowth Trust at June 30, 2002 and the unaudited pro forma combined statements of income and distributable income of Pengrowth Trust for the year ended December 31, 2001 and for the six months ended June 30, 2002. The unaudited pro forma consolidated balance sheet was prepared as if (i) the acquisition of the B.C. Asset Package, (ii) the disposition of a portion of the B.C. Asset Package to Progress Energy Ltd., (iii) the issuance of 17,123,287 trust units for net proceeds of $234.25 million and (iv) the other transactions described in the notes the pro forma financial statements, had occurred on June 30, 2002 and the pro forma combined statements of income and distributable income for the year ended December 31, 2001 and for the six months ended June 30, 2002 were prepared as if such transactions had occurred on the first day of the period presented. The consolidated financial statements of Pengrowth Trust as at and for the years ended December 31, 1999, 2000 and 2001 have been audited by KPMG LLP. The pro forma consolidated financial statements of Pengrowth Trust have not been audited but have been reviewed, as to compilation only, by KPMG LLP. See “Comments for United States Readers on Differences between Canadian and United States Reporting Standards” included in the pro forma consolidated financial statements.

     You should read the following data along with “Management’s Discussion and Analysis of Operating Results and Financial Condition” and the consolidated financial statements and related notes of Pengrowth Trust, as well as the Reconciliation of Interim Consolidated Financial Statements of Pengrowth Energy Trust for the six months ended June 30, 2002 to United States generally accepted accounting principles, included in this prospectus. You should also read the pro forma information together with the unaudited pro forma consolidated financial statements and related notes of Pengrowth Trust included in this prospectus.

																				Pro Forma
											Pro Forma			Six Months Ended						Six Months
		Years Ended December 31,									Year Ended			June 30,						Ended
											December 31,									June 30,
		1999			2000			2001			2001			2001			2002			2002
		(In thousands of Canadian dollars, except per unit amounts)
INCOME AND DISTRIBUTABLE INCOME STATEMENT DATA
Revenues:
	Oil and gas sales		252,408			416,228			469,929			717,542			264,004			203,178			284,652
	Processing and other income		3,715			5,520			7,071			7,071			3,359			3,036			3,036
	Royalties and mineral taxes		(31,886	)		(76,588	)		(71,960	)		(116,102	)		(45,940	)		(27,439	)		(45,118	)
	Operating Revenues, after royalties		224,237			345,160			405,040			608,511			221,423			178,775			242,570
	Interest and other income		1,144			5,788			1,348			1,348			1,063			(525	)		(525	)
	Net Revenue		225,381			350,948			406,388			609,859			222,486			178,250			242,045
Expenses:
	Operating		57,642			65,195			104,943			134,777			43,790			58,057			68,618
	Amortization of injectants for miscible floods		13,964			32,463			47,448			47,448			22,518			23,454			23,454
	General and administrative		5,972			7,081			7,467			7,467			3,627			5,219			5,219
	Management fee		4,490			6,873			7,120			11,461			4,714			3,140			4,471
	Depletion, depreciation and future site restoration		80,981			96,865			132,737			192,040			60,304			67,872			98,729
	Interest		10,882			17,354			18,806			26,380			9,929			6,165			8,126
	Capital taxes and other		1,227			1,902			2,717			3,175			1,852			297			490
	Total Expenses		175,158			227,733			321,238			422,748			146,734			164,204			209,107

38

																				Pro Forma
											Pro Forma			Six Months Ended						Six Months
		Years Ended December 31,									Year Ended			June 30,						Ended
											December 31,									June 30,
		1999			2000			2001			2001			2001			2002			2002
		(In thousands of Canadian dollars, except per unit amounts)
Net Income:			50,223			123,215			85,150			187,111			75,752			14,046			32,938
Add: depletion, depreciation and future site restoration			80,981			96,865			132,737			192,040			60,304			67,872			98,729
Deduct: remediation expenses and other			(3,032	)		(1,740	)		(2,100	)		(2,100	)		(590	)		(659	)		(659	)
Distributable income			128,172			218,340			215,787			377,051	(1)		135,466			81,259			131,008	(1)
Net Income per unit:
	Basic		$0.98			$2.21			$1.20			$2.13			$1.15			$0.17			$0.33
	Diluted		$0.98			$2.19			$1.20			$2.12			$1.14			$0.17			$0.33
Distributable income per unit:
	Based on weighted average units outstanding		$2.50			$3.92			$3.04			$4.28	(1)		$2.06			$0.97			$1.30	(1)
	Based on actual distributions paid or declared		$2.49			$3.79			$3.01						$1.97			$0.95
US GAAP(2)
Net Income			78,741			150,654			110,748			215,933			87,974			26,170			46,983
Net Income per unit:
	Basic		1.54			2.71			1.56			2.45			1.34			0.31			0.47
	Diluted		1.54			2.67			1.56			2.45			1.33			0.31			0.47

														Pro Forma
										Six Months Ended				Six Months
		Years Ended December 31,						Pro Forma		June 30,				Ended
								Year Ended						June 30,
		1999		2000		2001		December 31, 2001		2001		2002		2002
		(In thousands of Canadian dollars, except per unit amounts and operating data)
OTHER FINANCIAL DATA
	Distributions to Unitholders		114,163		197,826		241,590		—		142,115		72,420		—
	EBITDA(3)		143,313		239,336		239,410		408,706		147,837		88,380		140,283
OPERATING DATA
Daily gross production
	Oil (bblpd)		17,570		17,599		19,726		28,658		20,039		18,302		27,588
	Gas (mcfpd)		61,494		70,098		91,764		146,303		74,709		106,936		142,353
	Natural gas liquids (bblpd)		3,927		4,205		5,258		6,262		4,385		5,176		5,820
	Oil equivalent (boepd)		31,821		33,581		40,320		59,346		36,933		41,312		57,145

39

		As at December 31,
								As at		Pro Forma as at
		1999		2000		2001		June 30, 2002		June 30, 2002
		(In thousands of Canadian dollars, except per unit amounts and ratios)
BALANCE SHEET DATA
Assets:
	Current assets		27,269		46,145		34,343		36,689		36,689
	Remediation Trust Fund		3,785		5,515		6,470		6,808		6,808
	Property, Plant and Equipment and other assets		826,860		1,038,823		1,208,526		1,145,197		1,493,897
			857,914		1,090,483		1,249,339		1,188,694		1,537,394
Liabilities and Unitholders’ Equity:
	Current Liabilities		50,447		90,900		54,089		64,455		64,455
	Long-term debt		230,333		286,823		345,456		219,123		333,573
	Future site restoration costs		18,544		25,285		32,591		37,903		37,903
	Future income taxes		—		45,510		—		—		—
	Trust Unitholders’ Equity		558,590		641,965		817,203		867,213		1,101,463
			857,914		1,090,483		1,249,339		1,188,694		1,537,394
US GAAP(2)
	Trust Unitholders’ Equity		208,739		319,553		520,899		583,033		817,283
OTHER BALANCE SHEET DATA
Debt to total book capitalization(4)			29.3%		30.9%		29.7%		20.4%		23.4%
US GAAP(2)
	Debt to total book capitalization(4)		52.5%		47.3%		39.9%		27.3%		29.2%

(1)	Pro forma distributable income for the year ended December 31, 2001 and the six months ended June 30, 2002 does not take into account the reserve to be established in Pengrowth Corporation. See “Distributions.”
(2)	Please see note 13 to the consolidated financial statements as at and for the years ended December 31, 2000 and 2001, note 13 to the consolidated financial statements as at and for the years ended December 31, 1999 and 2000, the U.S. GAAP Reconciliation in respect of the interim consolidated financial statements as at June 30, 2002 and for the six months ended June 30, 2001 and 2002, and note 4 to the unaudited pro forma consolidated financial statements for the periods ended December 31, 2001 and June 30, 2002.
(3)	EBITDA represents earnings before interest expense, taxes, depreciation and amortization. We have calculated EBITDA as net income plus the following expenses: interest, capital taxes and other, and depletion, depreciation and future site restoration. EBITDA is presented because we believe it is frequently used by security analysts and others in evaluating companies and their ability to service debt. However, EBITDA should not be considered as an alternative to net revenue as a measure of liquidity or as an alternative to net income as an indicator of our operating performance or any other measure of performance in accordance with Canadian GAAP or United States GAAP. EBITDA, as we use the term herein, may not be comparable to EBITDA as reported by other entities.
(4)	Long-term debt divided by long-term debt plus trust unitholders’ equity.

40

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

OPERATING RESULTS AND FINANCIAL CONDITION

     The following management’s discussion and analysis of operating results and financial condition should be read in conjunction with the audited consolidated comparative financial statements as at and for the year ended December 31, 2001 and the interim unaudited consolidated comparative financial statements at and for the six months ended June 30, 2002. See “Selected Financial Information”.

     Information provided herein for the period following June 30, 2002 is based on assumptions regarding future events and is subject to risks and uncertainties that may cause actual results to vary materially from these estimates. Certain statements contained in this management’s discussion and analysis of operating results and financial condition constitute forward-looking statements. See “Forward-Looking Statements”.

     Unless we indicate otherwise, financial information in this prospectus has been prepared in accordance with Canadian GAAP. See “Presentation of Our Financial Information”. For information related to a reconciliation to U.S. GAAP of certain financial information prepared in accordance with Canadian GAAP, please see note 13 to the audited annual consolidated financial statements of Pengrowth Trust as at and for the years ended December 31, 2000 and 2001, note 13 to the audited annual consolidated financial statements of Pengrowth Trust as at and for the years ended December 31, 1999 and 2000, the Reconciliation of Interim Consolidated Financial Statements of Pengrowth Trust for the six months ended June 30, 2002 to United States generally accepted accounting principles, and note 4 to the unaudited pro forma consolidated financial statements of Pengrowth Trust as at June 30, 2002 and for the periods ended December 31, 2001 and June 30, 2002.

Results of Operations

     Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001

     Production.Total production increased 11% in the second quarter of 2002 compared to the second quarter of 2001. For the six months ended June 30, 2002, total production was 12% higher than the same period of 2001.

	Three Months Ended						Six Months Ended
Daily Production	June 30, 2001		June 30, 2002		% Change		June 30, 2001		June 30, 2002		% Change
Crude oil (bblpd)		19,650		18,096		-8%		20,039		18,302		-9%
Natural gas (mcfpd)		75,753		103,856		37%		74,709		106,936		43%
NGLs (bblpd)		4,418		5,350		21%		4,385		5,176		18%
Sulphur (long tonnes)		147		16				57		11
Total boepd		36,840		40,771		11%		36,933		41,312		12%

     Crude oil production was 8% lower in the second quarter of 2002 compared to the second quarter of 2001, and declined 9% in the first six months of 2002 compared to the first six months of 2001. This decline is attributable to dispositions of non-core properties in the first half of 2002 and in 2001, as well as natural production declines at existing properties, offset in part by production additions from development activities.

     Natural gas production increased 37% in the second quarter of 2002 compared to the second quarter of 2001. This increase was mainly attributable to the acquisition of a royalty interest in a 8.4% working interest in the Sable Offshore Energy Project in June, 2001. The acquisition of other natural gas properties including Quirk Creek in May 2002, and Kaybob Notikewin in March 2001 also contributed to the increase in natural gas volumes. The disposition of the Portage Gas Unit in April 2001, production declines at other properties, as well as an increase in gas volumes required for the miscible flood at Judy Creek partially offset the incremental volumes from recent acquisitions. For the first six months of 2002 natural gas production increased 43% over the same period in 2001.

41

     NGLs production increased 21% in the second quarter of 2002 compared to the second quarter of 2001, due mainly to the acquisition of the interest in the Sable Offshore Energy Project. For the first six months of 2002, NGLs production increased 18% over the same period in 2001.

     For the first six months of 2002, Pengrowth’s production was comprised of 44% crude oil, 43% natural gas and 13% NGLs.

     Prices and Product Marketing. Pengrowth’s average crude oil price was 11% lower in the first six months of 2002 compared to the first six months of 2001. This decline was due to a 13% decrease in the WTI benchmark price for crude oil after adjusting for the weaker Canadian exchange rate in 2002. Pengrowth’s average crude oil price for the first six months of 2002 included a hedging loss of $0.11 per bbl compared to a hedging loss of $0.66 per bbl in the first six months of 2001.

     Pengrowth’s average natural gas price for the first six months of 2002 fell by 53% to $3.29 per mcf compared to $6.98 per mcf over the same period in 2001. By comparison, the AECO and Nymex average prices fell by 57% and 53%, respectively, in the first six months of 2002 as compared to the same period in 2001. Included in the net realized price for natural gas for the period is a hedging loss of $0.03 per mcf for the first six months of 2002, compared to a hedging loss of $1.09 per mcf for the first six months of 2001.

     The combined effect of the decline in realized crude oil, natural gas and NGLs prices resulted in an average price of $30.06 per boe in the second quarter of 2002, down 17% from the second quarter of 2001. For the first six months of 2002, Pengrowth’s average realized price was down 31% from the same period in 2001.

	Three Months Ended						Six Months Ended
Average Price	June 30, 2001		June 30, 2002		% Change		June 30, 2001		June 30, 2002		% Change
Crude oil (per bbl)	$	39.44	$	38.63		-2%	$	39.90	$	35.61		-11%
Natural gas (per mcf)	$	5.72	$	3.75		-34%	$	6.98	$	3.29		-53%
Natural gas liquids (per boe)	$	34.42	$	28.04		-19%	$	37.64	$	25.48		-32%
Total per boe	$	36.11	$	30.06		-17%	$	39.49	$	27.17		-31%

     In the first six months of 2002, Pengrowth realized a net hedging loss of $0.5 million related to fixed price gas contracts (as compared to monthly AECO average spot prices) and natural gas financial swap contracts, compared to a hedging loss of $14.8 million in the same period in 2001. Net hedging losses realized on crude oil price swap transactions were $0.4 million compared to a $2.4 million hedging loss in the first six months of 2001.

     Royalties.Royalties, including crown and freehold royalties, were 12.8% of oil and gas sales in the three months ended June 30, 2002, compared to 13.7% in the second quarter of 2001. For the six-month period, royalties were 13.6% and 17.5% in 2002 and 2001, respectively. The decline in the royalty percentage in 2002 over 2001 is due to lower commodity prices in 2002 (particularly natural gas), a reduction in hedging losses realized in 2002, and lower royalties on revenues from the Sable Offshore Energy Project, offset in part by lower injection credits in 2002.

     Operating Expenses.Operating expenses increased to $30.5 million (or $8.22/boe) for the second quarter of 2002, compared to $22.2 million (or $6.62/boe) for the second quarter of 2001. For the six months ended June 30, 2002, operating costs were $58.1 million ($7.77/boe), compared to $43.8 million ($6.55/boe) for the first six months of 2001. The increase in operating costs is attributable mainly to property acquisitions over the last year, offset in part by property dispositions. The acquisition of our interest in the Sable Offshore Energy Project has increased Pengrowth’s average operating cost per boe, since Pengrowth pays processing fees to the owners of the offshore platforms and the gathering and processing facilities. Enhanced oil recovery projects at Goose River and Weyburn also contribute to higher operating costs per boe.

     Amortization of Injectants for Miscible Floods.Amortization of injectants for the second quarter of 2002 was $11.3 million, down 4% from $11.8 million for the second quarter of 2001. For the first six months of

42

2001, amortized injectant costs were $23.4 million compared to $22.5 million for the same period of 2001. Injectant costs are amortized over a 30-month period, based on the estimated period of economic benefit.

     On-going initiatives to maximize the use of on-site solvents at Judy Creek and reduce the requirement for purchased injectants have been successful. As a result of the reduction in purchased injectant volumes, coupled with a much lower ethane price in 2002, Pengrowth’s total solvent purchases in the second quarter were reduced to $4.1 million, compared to $22.0 million for the same period in 2001. Third party solvent purchases were $7.4 million for the first six months of 2002, compared to $40.1 million in the first six months of 2001.

     Interest Expense.Interest expense in the second quarter of 2002 was $3.1 million compared to $5.1 million in the second quarter of 2001. For the first six months of 2002, interest expense was $6.2 million compared to $9.9 million for the first six months of 2001. This reduction is due in part to lower interest rates in 2002 as well as lower average debt in 2002.

     General and Administrative Expenses.General and administrative expenses were $3.0 million in the second quarter of 2002 compared to $1.5 million for the second quarter of 2001. The increase in 2002 includes incremental costs related to drafting, printing and mailing of the annual report and information circular. These costs were substantially higher in 2002 due to the much larger size of the information circular document and a larger number of mail-outs due to an increase in the number of unitholders, as well as legal costs to revise agreements relating to our structure for consideration by trust and royalty unitholders. Administrative costs associated with our interest in the Sable Offshore Energy Project have also increased general administrative expenses.

     For the six months ended June 30, 2002, general administrative expenses were $5.2 million compared to $3.6 million for the same period last year. On a per boe basis, general administrative expenses for the first six months of 2002 were $0.70 per boe, compared to $0.54 per boe for the same period in 2001.

     Management Fees.Management fees were $1.7 million for the second quarter of 2002 compared to $1.9 million for the second quarter of 2001. For the six-month period ended June 30, 2002, management fees were $3.1 million compared to $4.7 million for the same period in 2001. On a per boe basis, management fees for the first six months of 2002 were $0.42 per boe, compared to $0.71 per boe in 2001.

     Taxes.Pengrowth anticipates that between approximately 30 to 35% of 2002 distributions will be taxable for unitholders resident in Canada; this estimate is subject to change depending on the level of commodity prices, acquisitions, dispositions, and new equity offerings.

     Depletion and Depreciation.Depletion and depreciation for the second quarter of 2002 was $31.7 million, a 14% increase from $27.9 million for the second quarter of 2001. For the six months ended June 30, 2002, depletion and depreciation was $62.1 million, a 10% increase over the same period last year. This increase is in line with production increases over the same period. On a per boe basis, depletion and depreciation was $8.31 per boe for the first six months of 2002, down 2% from $8.49 per boe in the first half of 2001.

     Net Income.Net income for the second quarter of 2002 was $13.6 million or $0.16 per trust unit compared to $33.8 million ($0.50 per trust unit) for the second quarter of 2001. For the six months ended June 30, 2002, net income was $14.0 million ($0.17 per trust unit) compared to $75.8 million ($1.15 per trust unit) for the similar period last year. Most of this decline is attributable to lower commodity prices and higher operating expenses and depletion, offset in part by a 12% increase in production volumes in 2002.

     Acquisitions and Dispositions.On January 17, 2002, Pengrowth sold the Virginia Hills Unit for proceeds of $4.5 million, prior to adjustments.

     On May 23, 2002 Pengrowth acquired additional interests in the Quirk Creek area of southwest Alberta for a total purchase price of $32.7 million, before adjustments. The acquisition included an additional 55.9% working interest in three producing gas wells and an additional 26.4% working interest in ten producing gas wells. Pengrowth also acquired an additional 25.9% working interest in the Quirk Creek gas plant. Prior to this

43

acquisition, Pengrowth held an average working interest of 5.5% in 13 producing gas wells at Quirk Creek and a 4.6% working interest in the gas plant.

     As at May 10, 2002, Gilbert Laustsen Jung Associates Ltd. estimated the established reserves attributable to the acquired Quirk Creek assets to be 2.9 million boe. Also as at May 10, 2002, Gilbert Laustsen Jung Associates Ltd. estimated 2002 proved producing production volumes attributable to the acquired Quirk Creek assets to be 4 mmcfpd of gas and 193 bblpd of liquids for a total of 856 boepd. The acquisition also provides significant natural gas processing revenue.

     The Quirk Creek purchase represents an add-on interest for Pengrowth with potential opportunity for additional future gas development and processing services in the immediate area.

     On April 30, 2002, Pengrowth closed the sale of non-core properties including interests in Strachan, North Pembina Cardium Unit, Minehead and Niton for total proceeds of $40.2 million, before adjustments.

     Capital Expenditures.Capital expenditures for the six months ended June 30, 2002, totalled $25.4 million of which $19.2 million was spent on drilling, completion and tie-ins, and $6.2 million was spent on facilities. Expenditures in 2002 included $11.0 million at Judy Creek, $4.5 million at the Sable Offshore Energy Project, $2.0 million at Goose River, $1.7 million at McLeod River and $1.4 million at Weyburn.

     Equity Issue.On June 4, 2002, Pengrowth successfully completed a public offering of 8.0 million trust units at $15.40 per trust unit to raise total gross proceeds of $123.2 million and net proceeds of approximately $116 million. The net proceeds from this issue were used to repay bank indebtedness incurred to fund prior acquisitions of oil and natural gas properties.

     Financial Resources.Pengrowth’s long-term debt at June 30, 2002, was $219.1 million, compared to $345.5 million at December 31, 2001. The following is a reconciliation of long-term debt for the first six months of 2002:

Long-term Debt Continuity	Millions
Balance at December 31, 2001	$	345.5
Difference between solvent purchases and expenses		(16.0	)
Acquisitions, net of adjustments		34.0
Dispositions, net of adjustments		(44.6	)
Capital expenditures, excluding acquisitions		25.4
Proceeds from the issue of trust units including option exercises and the distribution re-investment program		(117.2	)
Change in working capital and Remediation Trust Fund		(8.0	)
Balance at June 30, 2002	$	219.1

     The ratio of debt to trailing 12-month distributable income as at June 30, 2002, was 1.4, compared to 1.6 at December 31, 2001. The ratio of long-term debt to long-term debt plus equity has declined to 20% from 30% at year-end 2001. Distributable income covered interest expense by 12 times in the first six months of 2002. These favourable ratios reflect the successful debt-reduction initiatives over the last eight months, including the disposition of non-core assets and the completion of public equity offerings in December 2001 and June 2002.

     Distributable income.Distributable income declined by 24% from $63.4 million for the second quarter of 2001 to $48.1 million for the second quarter of 2002. However, distributable income increased 45% compared to the first quarter of 2002. Distributable income per trust unit was $0.54 per unit in the second quarter of 2002, compared to $0.83 per trust unit in the second quarter of 2001. For the six months ended June 30, 2002, Pengrowth recorded $81.2 million in distributable income or $0.95 per trust unit, compared to $135.5 million or $1.97 per trust unit in the first six months of 2001. The lower distributable income in 2002 compared to the same period in 2001 was mainly due to lower average commodity prices, offset in part by a 12% increase in total production.

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     Year Ended December 31, 2001 Compared with Year Ended December 31, 2000

          2001 Overview.

•  Distributable income of $215.8 million was earned, 1% below 2000’s record level of $218.3 million.

•  Distributable income per trust unit was $3.01 per trust unit, the second highest amount in Pengrowth’s history.

•  2001 production increased 20% to average 40,320 boepd.

•  Net income decreased 31% from $123.2 million in 2000 to $85.2 million in 2001.

•  Established reserves increased 15% to 210.5 mmboe at December 31, 2001.

•  48.4 mmboe of established reserves were purchased in 2001 for total net cash consideration of $277.1 million, replacing 329% of production at an average cost of $5.72 per boe.

•  Pengrowth diversified its oil and gas property portfolio through the acquisition of a royalty interest in an 8.4% working interest on the natural gas and NGLs production from the Sable Offshore Energy Project located offshore Nova Scotia.

•  Pengrowth completed two public trust unit offerings, issuing 17,622,500 trust units at a weighted average price of $17.70 to raise a total of $312 million in gross proceeds. These financings represented the largest amount of new equity raised by a Canadian oil and gas issuer in 2001.

     Production.Average daily production increased 20% to 40,320 boepd in 2001 compared to 33,581 boepd in 2000. This increase is attributable mainly to the acquisition of properties, including the Sable Offshore Energy Project royalty interest in June 2001, Kaybob Notikewin in March 2001, and a full year’s production from properties acquired in the fourth quarter of 2000. In addition, development programs at several major properties were successful in adding production volumes to help offset normal production declines.

	Daily Production Volumes
	2000		2001		% Change
Crude oil (bblpd)		17,599		19,726		12%
Natural gas (mcfpd)		70,098		91,764		31%
NGLs (bblpd)		4,205		5,258		25%
Total daily sales volumes (boepd)		33,581		40,320		20%

     Pengrowth’s total 2001 production was 49% crude oil, 38% natural gas and 13% NGLs. Following the addition of the royalty interest in the Sable Offshore Energy Project in June 2001, Pengrowth’s production portfolio was more evenly weighted with approximately 43% of production coming from natural gas, 43% from crude oil, and the remaining 14% from NGLs. The exit production rate for December, 2001 was approximately 43,000 boepd.

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     Pricing and Product Marketing.The tables below illustrate the average crude oil and average natural gas prices realized by Pengrowth for the years indicated.

     Pengrowth’s average crude oil price fell 8% in 2001 to $37.26 per bbl for 2001 compared to $40.37 in 2000. This price difference reflected a 14% drop in the WTI benchmark crude price, from US$30.20 per bbl in 2000 to US$25.90 per bbl in 2001, mitigated by Pengrowth’s oil hedges and the Canadian/ U.S. exchange rate differential.

     Pengrowth markets approximately 80% of its crude oil production on a direct sales basis, on the Pembina Rainbow and Peace pipeline systems in Alberta. Sales are made to refiners and marketing companies. The remainder of Pengrowth’s crude oil is sold at the well site.

     In 2001 Pengrowth hedged 2,844 bblpd, or 14% of crude oil production, at an average base price of $38.23 per bbl (before transportation and quality differential). Pengrowth’s hedging program resulted in a total hedging loss on crude oil for the year of $0.6 million or $0.09 per bbl, compared to a loss of $18.1 million or $2.81 per bbl in the prior year. Hedging losses are recorded as a component of oil and gas sales.

	Pengrowth’s Average Realized
	Prices
	(Adjusted for Hedging)
	2000		2001		% Change
Crude oil ($/bbl)		40.37		37.26		-8%
Natural gas ($/mcf)		4.34		4.48		3%
NGL ($/bbl)		33.56		30.68		-9%
Total oil and gas sales ($/boe)		33.87		31.93		-6%

     Pengrowth’s average natural gas price increased 3% from $4.34 per mcf in 2000 to $4.48 per mcf in 2001. In comparison, the average AECO and Nymex benchmark gas prices increased 26% and 10% respectively. In the early part of the year, spot prices reached unprecedented highs before falling to significantly lower levels during the second half of the year. Pengrowth’s average gas price did not increase as rapidly as spot prices, due to Pengrowth’s aggregator based sales and direct fixed price sales. As well, the addition of revenues from the Sable Offshore Energy Project for the second half of the year, which comprise approximately 26% of Pengrowth’s total gas sales volumes for the year, reduced the overall weighted average price since gas prices were substantially lower in the second half compared to the first half of the year. Natural gas from our interest in the Sable Offshore Energy Project comprised approximately 43% of Pengrowth’s total natural gas production as of December 31, 2001. Approximately 30% of Pengrowth’s natural gas is sold to aggregators that provide a basket of fixed and floating index-based prices, as well as exposure to various regions in the United States. The remainder of Pengrowth’s natural gas is sold on a direct basis with reference to AECO or Nymex price indices.

     During 2001 Pengrowth sold 4.8 bcf of gas at an average price of $2.97 per mcf under fixed price contracts. As spot prices exceeded this hedged position, an opportunity cost of $16.1 million or $0.48 per mcf (relative to the monthly AECO index) is included in Pengrowth’s gas sales for 2001.

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     Pengrowth’s average price for NGLs fell 9% to $30.68 in 2001, reflecting lower average prices for condensate. The weighted average NGLs price was also reduced by the impact of increased sales volumes from the Sable Offshore Energy Project when overall NGLs prices were lower compared to the first half of the year.

	Oil and Gas Sales (Millions)
	2000			2001			% Change
Crude oil	$	260.0		$	268.3			3%
Natural gas		111.4			150.2			35%
NGLs		51.6			58.9			14%
Sulphur		0.5			0.1			-80%
Less GORR royalties(1)		(10.1	)		(9.9	)		-2%
Gas marketing and brokering income		2.8			2.3			-18%
Total oil and gas sales	$	416.2		$	469.9			13%

(1)  Gross overriding royalty interests.

     Pengrowth’s oil and gas sales increased 13% to $469.9 million in 2001. This increase in revenue is attributable to acquisitions over the last year and a higher average gas price, offset in part by lower crude oil and NGLs prices. The following table illustrates the effect of changes in prices and volumes on oil and gas sales for the year 2001.

	Oil and Gas Sales — Price and Volume Analysis (Millions)
	Oil			Gas		NGL			GORR(1)			Other			Total
Year ended December 31, 2000	$	260.0		$	111.4	$	51.6		$	(10.1	)	$	3.3		$	416.2
Effect of change in sales volumes		30.6			34.0		12.8									77.4
Effect of increase (decrease) in product price		(22.3	)		4.8		(5.5	)								(23.0	)
Other										0.2			(0.9	)		(0.7	)
Year-end December 31, 2001	$	268.3		$	150.2	$	58.9		$	(9.9	)	$	2.4		$	469.9

(1)  Gross overriding royalty interests.

     Royalties.Crown royalties, freehold royalties and mineral taxes decreased to $72.5 million or 15% of oil and gas sales in 2001 compared to $77.1 million or 19% of oil and gas sales in 2000. The reduction in royalties, despite an increase in oil and gas revenues, is due in part to the acquisition of the interest in the Sable Offshore Energy Project in June 2001, which has a current effective royalty rate of 1%. In addition, Crown royalty injection credits realized from miscible floods increased as a result of higher injectant costs in 2001. Pengrowth records all injection credits received as a reduction of royalties in the period received.

     Operating Expenses.Operating expenses increased to $104.9 million in 2001 compared to $65.2 million in 2000, mainly as a result of additional properties acquired in the past year. Operating costs per boe increased 34% to $7.13 per boe compared to $5.30 per boe in 2000. The increase in operating costs per boe is attributable to a number of factors including recent acquisitions with higher average per boe operating costs, higher electrical power rates in Alberta during the first half of the year, increased well workover activity during 2001, and higher costs for the Weyburn carbon dioxide flood which commenced in late 2000. (Pengrowth includes the costs of injected carbon dioxide directly in operating costs — $2.1 million in 2001).

     Amortization of Injectants for Miscible Floods.The cost of injectants (primarily ethane and methane) purchased for injection in miscible flood programs is amortized over the period of expected future economic benefit, which is currently 30 months. In 2001, the total cost of purchased injectants was $56.4 million ($46.8 million in 2000), with $47.4 million amortized and deducted from distributable income ($32.5 million in 2000). As at December 31, 2001, Pengrowth had deferred injectant costs of $63.0 million, which will be amortized and charged against distributable income in future periods. The value of Pengrowth’s proprietary

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injectants is not recorded until reproduced from the flood and sold, although the cost of producing these injectants is included in operating costs.

     Interest Expense.Interest expense increased 8% to $18.8 million in 2001 from $17.4 million in 2000, as a result of higher average debt outstanding during the year offset in part by lower interest rates. Distributable income covered interest expense by 11 times in 2001 (12 times in 2000). Pengrowth’s average interest rate for 2001 was 5.2% compared to 6.8% in 2000. As at June 30, 2002 Pengrowth had entered into interest rate swaps on $125 million of its long-term debt for three year periods ending in November 2004 ($75 million), December 2004 ($25 million) and March 2005 ($25 million), at an average interest rates of 4.09% (before stamping fees).

     General and Administrative Expenses.General and administrative expenses increased marginally from $7.1 million in 2000 to $7.5 million in 2001. General and administrative expenses per boe decreased from $0.58 per boe to $0.51 per boe, as a result of incremental production acquired during the year. Pengrowth includes the administrative costs associated with its Calgary-based operations team in operating expense. These costs totalled $3.0 million in 2001 ($2.9 million in 2000).

     Management Fees.Management fees paid to Pengrowth Management were $7.1 million in 2001 compared to $6.9 million in 2000. On a unit of production basis, management fees decreased to $0.48 per boe in 2001, compared to $0.56 per boe in 2000. In 2001, $2.2 million ($1.2 million in 2000) was paid to Pengrowth Management for acquisition fees. Acquisition fees paid to Pengrowth Management are capitalized as part of the cost of the acquired properties.

     Taxes.Capital taxes of $2.7 million in 2001 ($1.8 million in 2000) consist of the federal large corporations tax and the Saskatchewan capital tax and resource surcharge. At December 31, 2001 the tax basis of property, plant and equipment exceeded the net book value of property, plant and equipment by $132 million, primarily as a result of tax pools acquired in conjunction with the acquisition of our interest in the Sable Offshore Energy Project. As a result, the future tax liability of $45 million recorded in 2000 has been eliminated in 2001.

     In determining its taxable income, Pengrowth Corporation deducts royalty payments to Pengrowth Trust, and historically, along with other deductions this has been sufficient to reduce taxable income to nil. Pengrowth Trust paid $3.49 per trust unit as cash distributions during the 2001 calendar year. For Canadian tax purposes 51.4% of these distributions or $1.7951 per trust unit was taxable income to unitholders for the 2001 tax year. The remaining 48.6% or $1.6949 per trust unit was a tax deferred return of capital which reduces the unitholder’s cost base of the trust unit for purposes of calculating a capital gain or loss upon the ultimate disposition of the trust units. At December 31, 2001, Pengrowth Trust had, subject to certification by tax authorities, unused tax deductions of $11.06 per trust unit ($10.61 in 2000).

     Depletion and Ceiling Test.Depletion and depreciation of property, plant and equipment is provided on the unit of production method based on total proved reserves, with the conversion of gas to oil using the relative energy content (6 mcf gas:1 boe). The provision for depletion and depreciation increased 39% in 2001 to $124.2 million from $89.3 million in 2000, due to a larger depletable asset base and higher production. On a unit-of production basis, depletion increased to $8.44 per boe in 2001 from $7.26 per boe in 2000.

     Pengrowth places a limit on the carrying value of the property, plant and equipment and other assets (the ceiling test). The cost of these assets, less accumulated depletion, is limited to the estimated future net revenue from proved reserves (based on unescalated prices and costs at the balance sheet date) less estimated future general and administrative costs, financing costs, and management fees. There was a significant surplus in the ceiling test at December 31, 2001.

     Future Site Restoration.An engineering estimate of the future costs for restoration and abandonment of well sites and facilities is updated annually. This cost estimate is amortized over the life of the properties on a unit of production basis. The provision for future site restoration costs increased to $8.5 million in 2001 from $7.6 million in 2000, primarily as a result of properties acquired over the past year with associated future site restoration costs.

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     Remediation Expenses and Trust Fund Contributions.Pengrowth has established a trust fund for certain reclamation obligations of the Judy Creek and Swan Hills properties. Pengrowth made contributions of $1.0 million to this fund in 2001, compared to $2.5 million in 2000. Effective for 2001 and future years, the required lump-sum contribution to the fund is $0.25 million annually, compared to the $1.75 million required in 2000. An additional contribution of $0.10 per boe of production is also required under the terms of the fund.

     Pengrowth also incurred $1.1 million in reclamation expenditures that were not covered by the trust fund, in comparison to $0.1 million in 2000.

     Netbacks. The following table illustrates our netbacks per boe of production.

	Year Ended
	December 31
	2000			2001
Oil and gas sales	$	33.87		$	31.93
Crown and freehold royalties		(6.28	)		(4.93	)
Other income and Alberta royalty credit		1.03			0.60
Operating costs		(5.30	)		(7.13	)
Amortization of injectants		(2.64	)		(3.22	)
Operating netback		20.68			17.25
Interest		(1.41	)		(1.28	)
General and administrative		(0.58	)		(0.51	)
Management fees		(0.56	)		(0.48	)
Capital taxes		(0.15	)		(0.18	)
Remediation costs and trust contributions		(0.21	)		(0.14	)
Distributable income per boe	$	17.77		$	14.66

     As illustrated in the chart above, Pengrowth earned distributable income of $14.66 for every boe produced in 2001. This netback per boe realized in 2001 is $3.11 per bbl less than 2000, mainly as a result of lower prices and higher operating and injectants costs.

     Acquisitions and Dispositions.On June 15, 2001, Pengrowth acquired a 99.99% royalty interest in the reserves and production associated with an 8.4% working interest held by Emera Offshore Incorporated (a subsidiary of Emera Inc.) in the Sable Offshore Energy Project. Pengrowth is responsible for associated capital and operating costs in proportion to its working interest. Through this transaction, Pengrowth acquired established reserves of 216 bcf of gas and 9.4 mmbbls of NGLs (after adjustment for the reserve reduction announced by Pengrowth in February 2002). The total net purchase price of this acquisition was approximately $256 million including the acquisition of additional oil and natural gas interests completed in December 2001. On March 9, 2001 Pengrowth acquired a 43.5% working interest in the Kaybob Notikewin Unit for $21 million, after adjustments. Pengrowth now holds a 64.5% interest in this property and assumed operatorship in April.

     In total, Pengrowth acquired 48.4 mmboe of established reserves in 2001, with an average reserve life index of 14 years at a price of $5.72 per boe to replace 329% of production. During 2001, Pengrowth sold non-core properties for total aggregate proceeds of $23.6 million, after adjustments. Subsequent to year-end, Pengrowth sold an additional non-core property, a 2.67% interest in the Virginia Hills Unit, for $3.8 million, net of adjustments.

     Capital Expenditures. Pengrowth spent $74.0 million in capital expenditures in 2001, compared to $59.8 million in 2000. Of this amount, $59.5 million was spent on development drilling, completions and tie-ins, and $14.5 million was spent on facilities.

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		Year Ended December 31
		(Millions)
		2001						2000
		Development				Total Capital		Total Capital
Property		Drilling		Facilities		Expenditures		Expenditures
Judy Creek		$	24.1	$	3.7	$	27.8	$	28.9
Sable(1)			6.7		0.8		7.5		—
McLeod River			5.3		0.6		5.9		9.2
Weyburn			3.1		2.2		5.3		4.8
Monogram			3.3		0.9		4.2		1.6
House Mountain			3.0		1.0		4.0		—
Nipisi			2.4		0.6		3.0		—
Minnehik			0.7		1.5		2.2		—
Strachan			1.8		0.2		2.0		1.3
Swan Hills			1.5		0.5		2.0		2.1
Enchant			1.6		0.1		1.7		3.0
Goose River			0.5	��	0.9		1.4		—
Dunvegan			1.1		0.2		1.3		0.7
Other			4.4		1.3		5.7		8.2
	Total	$	59.5	$	14.5	$	74.0	$	59.8

(1)  Relates only to Pengrowth’s royalty share of capital expenditures.

     At Judy Creek, development drilling included four producing oil wells and three solvent injection wells. In addition, by drilling new wells and working over existing suspended wells, Pengrowth placed eight natural gas wells on production in 2001. Facilities expenditures included optimizing processing at the gas plant complex which permitted one plant to be shut down. We expect that this will result in annual cost savings of over $500,000 net to Pengrowth while the plant remains shut down.

     At the Sable Offshore Energy Project, the Venture 2 well was placed onstream in August 2001 and current raw gas production (based on January 2002 average) is 74.5 mmcfpd (6.2 mmcfpd net to Pengrowth). The Thebaud 6 well commenced production in December 2001 with January 2002 raw gas production averaging 37.3 mmcfpd (3.1 mmcfpd net to Pengrowth).

     At McLeod River, two new producing gas wells were drilled in which Pengrowth has 100% and 87.5% working interests respectively. Current production from these two wells totals approximately 1.6 mmcfpd net to Pengrowth.

     At Weyburn, development activities included additional infill drilling, injection wells and infrastructure to support the carbon dioxide miscible flood project. Positive response from the carbon dioxide injection commenced in the third quarter of 2001, with incremental oil production increasing to approximately 2,000 bblpd (195 bblpd net to Pengrowth) by December 31, 2001.

     At Monogram, Pengrowth participated in a 40 well shallow gas infill program and two successful non-unit wells.

     At House Mountain, development activities included four new horizontal oil wells, reactivation of three existing oil wells, and acid frac stimulations on five wells.

     At Nipisi, Pengrowth drilled one producing oil well (100% Pengrowth), which is currently producing 82 bblpd, and one water injector, which is awaiting regulatory approval to commence water injection.

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Financial Resources and Liquidity

     Pengrowth’s long-term debt increased by $58.6 million at December 31, 2001 to $345.5 million at December 31, 2001. The increase was attributable to property acquisitions and capital spending and an increase in working capital and deferred injectants, offset by proceeds of equity offerings and property dispositions.

		Continuity of
		Long-term Debt
		(millions)
		2000			2001
Beginning balance, January 1		$	230		$	287
Less: Net Equity Proceeds			(179	)		(306	)
Property dispositions			—			(24	)
Add: Property acquisitions			182			280
	Capital expenditures		60			74
	Deferred injectants (temporarily debt financed)		14			9
Change in working capital			(20	)		25
Ending balance, December 31		$	287		$	345

Financial Leverage and Coverage

	2000		2001
Distributable income to interest expense (times)		12		11
Long-term debt to distributable income (times)		1.3		1.6
Long-term debt to long-term debt plus equity		31%		30%

     Capital spending and acquisitions are generally debt financed and credit capacity is replenished by issuing equity when appropriate. Although it has not been required in the past, management has the ability to retain a portion of the cash flow to repay debt and/or contribute to capital spending in the future.

     The Canadian Institute of Chartered Accountants (CICA) has issued EIC 122, “Balance Sheet Classification of Callable Debt Obligations and Debt Obligations Expected to be Refinanced”, which is effective January 1, 2002. This abstract addresses classification as current or long-term of certain debt agreements where the debt is callable or scheduled to mature within one year but expected to be refinanced on a long term basis. Beginning in 2002, under these new guidelines, a portion of Pengrowth’s bank debt may be classified as current since renewal of the facility is at the bank’s option.

Risk Management Program

     Pengrowth uses forward and futures contracts to manage its exposure to commodity price fluctuations. (See “Business — Current Marketing and Hedging Activities”).

Trust Unit Information

     Pengrowth had 82,240,069 trust units outstanding at December 31, 2001, compared to 63,852,198 trust units at December 31, 2000. The weighted average number of units during the year was 70,910,746. On May 31, 2001, Pengrowth completed a public offering of 10,895,000 trust units at $20.70 per trust unit to raise total gross proceeds of $225.5 million. In December 2001, Pengrowth completed another public offering, issuing an additional 6,727,500 trust units at $12.85 per trust unit for gross proceeds of $86.4 million. During 2001, Pengrowth also issued 628,828 trust units pursuant to the exercise of trust unit options for proceeds of $10.1 million, and 136,543 trust units were issued pursuant to our distribution reinvestment program for proceeds of $2.6 million.

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     The Accounting Standards Board of the CICA has recently approved new standards for accounting for stock options and other stock-based plans. The new rules will require companies to measure and record compensation expense for employee stock options in many circumstances. The new standard would also require compensation expense in the income statement for any plans that allow for settlement in cash. In addition, companies will be required to measure the fair value of all stock awards granted subsequent to January 1, 2002 using an option pricing model (such as Black-Scholes), in order to present pro-forma earnings and earnings per share amounts in the notes to the financial statements. These new rules will be effective for fiscal years commencing January 1, 2002, however the CICA has granted a six-month period in which companies may implement changes to existing stock based compensation plans pursuant to the new rules.

Sensitivity Analysis

     The following table estimates the impact that changes to crude oil and natural gas prices, may have on distributions to unitholders in 2003. This analysis is based on forecast prices and costs, royalty rates, production levels and exchange rates for 2003 in the GLJ July Report for pro forma reserves (including the New B.C. Properties), Pengrowth’s hedging contracts as at October 11, 2002, and 107,470,565 trust units outstanding (assuming the issuance of 17,123,287 trust units pursuant to this offering). The per trust unit amounts shown in this table are approximations only, and readers should not place undue reliance on these estimates.

	Effect on
	Pengrowth Distributions
	(per trust unit)
The first increase of US$1.00 per barrel in the price of crude oil	$	0.08 increase
The first increase of Cdn$0.10 per mcf in the price of natural gas	$	0.03 increase

     The foregoing sensitivity analysis assumes that:

•  for each hypothetical case set forth in the table, the only item that varies from the forecast contained in the GLJ July Report is the item identified in that hypothetical case,

•  all other items of revenue and expense remain constant at 2002 levels.

•  Pengrowth makes no acquisitions or dispositions from the date of this prospectus through the end of 2003,

•  there are no changes in tax laws or other laws or regulations that could negatively impact our business or our distributable income, and

•  we do not suffer any adverse change or development to our business, properties or financial condition.

     The foregoing table supersedes the information contained under the heading “Sensitivity Analysis” in the Management’s Discussion and Analysis for the year ended December 31, 2001, contained on pages 32 to 43, inclusive, of the 2001 Annual Report of Pengrowth Trust, incorporated by reference in this prospectus. See “Documents Incorporated by Reference”. Accordingly, the information contained under the heading “Sensitivity Analysis” in the Management’s Discussion and Analysis for the year ended December 31, 2001 shall not be deemed to constitute a part of this prospectus.

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BUSINESS

Introduction

     Pengrowth Trust was formed in 1988 to acquire and manage a portfolio of producing oil and natural gas properties. Since inception, we have purchased approximately $1.8 billion of oil and gas interests in more than 48 separate transactions. Pengrowth Trust is the second largest conventional oil and natural gas royalty trust (excluding oil sands trusts) in North America based on enterprise value. The properties held by Pengrowth are primarily unitized, long life, mature working interests. We presently hold interests in approximately 70 properties. Our portfolio reserve life index is approximately 11.1 years following the acquisition of the New B.C. Properties. Approximately 59% of our established reserves and 70% of our net proved reserves are in the proved producing category.

     Pengrowth Trust, the issuer of the trust units, is a trust governed by the laws of the Province of Alberta. Pengrowth Corporation is an Alberta corporation that holds oil and natural gas properties, royalties and other assets. Pengrowth Management provides management services to Pengrowth Trust and Pengrowth Corporation subject to the authority of the board of directors of Pengrowth Corporation. Pengrowth Management has the right to appoint two members to the board of directors of Pengrowth Corporation, but the majority of the members are appointed by our unitholders. At present the holders of trust units exercise in excess of 99.98% of the voting rights of Pengrowth Corporation.

     Pengrowth Corporation has issued royalty units which entitle the holders thereof to an undivided interest in 99% of the income relating to the oil and natural gas properties and royalties held by Pengrowth Corporation. More than 99.98% of the outstanding royalty units of Pengrowth Corporation are held by Pengrowth Trust. Pengrowth Trust also holds property interests in facilities located in the Swan Hills and Judy Creek areas that it acquired under a sale lease back transaction with Pengrowth Corporation.

     Since 1988, we have completed 14 public distributions and one private placement of our trust units for aggregate gross proceeds in excess of $1.4 billion. The net proceeds of these public distributions and private placements have been used to fund the acquisition of properties and repay indebtedness incurred in connection with property acquisitions. Since inception, we have paid aggregate distributions of $22.60 per trust unit (including the October 15, 2002 distribution). The current market capitalization of Pengrowth Trust is $1.3 billion based upon the closing price of the trust units on the Toronto Stock Exchange on October 15, 2002 of $14.78, and the enterprise value of Pengrowth Trust is approximately $1.9 billion (market capitalization at October 15, 2002, plus long-term debt net of working capital (current assets minus current liabilities) as at June 30, 2002, plus the net purchase price of the New B.C. Properties of $345.6 million). All of the foregoing demonstrates our ability to add accretively to reserves while paying out distributions to holders of trust units.

Business Strategy and Strengths

     Our goal is to maximize cash distributions to our unitholders while maintaining the value of the trust units. Pengrowth does not explore for oil and natural gas. Instead, we focus on making effective acquisitions and maximizing the value of our mature property base by reducing operating costs, implementing new development technologies, including three dimensional seismic and tertiary recovery operations, and implementing other operational efficiencies.

     Our business model is designed to increase distributions to our unitholders. Our ability to pay out distributions while enhancing unitholder value over time is dependent upon effective operations and our ability

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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 distributions on a per trust unit basis based upon current economics.

•  The aggregate purchase price of all properties acquired in a single transaction should not exceed the undiscounted aggregate projected net cash flow from the properties from the date of purchase plus 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 and a low reserve cost.

     Operational

•  Properties to be acquired should be high quality, long life, proven producing properties primarily in unitized areas. Pengrowth Corporation gives priority to properties with:

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

—  low operating costs or high margins;

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

—  favourable production history;

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

—  long reserve life; and

—  low environmental and site remediation risk.

     Independent Verification

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

     Our structure, tax effectiveness and cost of capital allow us to bid competitively for oil and natural gas properties against 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

     Pengrowth’s first purchase was the acquisition of a 2.6507% interest in the Dunvegan Gas Unit No. 1 located near Fairview, Alberta in December of 1988. Pengrowth financed the acquisition by issuing 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 by Pengrowth Trust to subscribe for 1,243,500 royalty units of Pengrowth Corporation. Pengrowth Corporation issued an additional 6,500 royalty units to subscribers other than Pengrowth Trust for proceeds of $65,000.

     Commencing in 1991, we adopted a plan to build value through accretive acquisitions and related financings. In 1991, 760,218 trust units were issued upon the exercise of rights to acquire trust units, at a price of $5.00 per trust unit for gross proceeds of $3,801,090. This equity issue was followed by a private placement in 1992 and two rights offerings in 1993 at $5.00, $5.50 and $7.75, respectively, to raise aggregate gross proceeds of $33,891,174. These proceeds were used by us to complete acquisitions and repay bank debt incurred to acquire additional oil and natural gas unit interests.

     We completed a series of equity offerings in 1994 and 1995 to fund various property acquisitions. In this period, three equity issues were completed at $10.50, $11.65 and $15.50 per trust unit, respectively, to raise

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aggregate gross proceeds of $105,583,798. The proceeds were applied to purchase working interests in unitized oil and gas properties located in Western Canada.

     In 1997, we acquired a 98.11% working interest in the Judy Creek Beaverhill Lake Unit, a 94.58% working interest in the Judy Creek West Beaverhill Lake Unit, and a 9.58% working interest in the Swan Hills Unit No. 1, from Imperial Oil Resources Limited for $496.1 million. We financed this acquisition through an offering of 23,928,572 trust units on an instalment receipt basis for gross proceeds of $508 million. On April 15, 1998, we assumed operatorship of the Judy Creek Units from Imperial Oil Resources.

     Oil and natural gas prices declined in 1998 and there was an associated decline in the market-trading price of our trust units and the number of acquisitions completed by Pengrowth Corporation. In 1999 and 2000, in conjunction with the recovery of commodity markets, Pengrowth Corporation resumed acquisition activities. Two fully marketed equity issues were completed at $12.75 and $19.00 per trust unit, respectively, to raise gross proceeds of $234,435,000.

     In 2001, we completed equity offerings at $20.70 and $12.85 per trust unit for aggregate gross proceeds of $311,974,875. In the same year, we completed various transactions including the acquisition of a royalty representing substantially all of the beneficial interest in the natural gas and liquids production from an 8.4% working interest in the Sable Offshore Energy Project from Nova Scotia Resources Venture Limited for $265 million (net adjusted price of $228.4 million). Pengrowth completed an equity issue at $15.40 per trust unit for gross proceeds of $123,200,000 in May 2002.

Principal Properties

     Our portfolio of properties consists primarily of long life, unitized oil and gas properties with established production profiles. Approximately 68% of our total gross production in 2001 was derived from eight core areas located in the Provinces of Alberta and Saskatchewan and offshore the Province of Nova Scotia. In 2001, we increased our established reserves from 183 mmboe (123 mmboe on a net proved reserves basis) to 211 mmboe (146 mmboe on a net proved reserves basis) through drilling and other optimization strategies and we acquired 48.4 mmboe of new established reserves at an average cost of $5.72 per boe for an overall finding and development cost of $6.85 per boe. Substantially all of the reserves we acquired in 2001 related to interests in the Sable Offshore Energy Project, a large natural gas project located offshore the Province of Nova Scotia operated by ExxonMobil Canada Properties. We also raised average production from 33,581 boepd in 2000 to 40,320 boepd in 2001, and to 57,137 boepd (44,510 boepd net) forecast for the second half of 2002, including the New B.C. Properties, based on the GLJ July Report, an increase of approximately 20% and 40%, respectively. Based on the GLJ July Report, our pro forma established reserves are 232.2 mmboe (156.0 mmboe on a net proved reserves basis), consisting of 553.2 bcf (368.6 bcf on a net proved reserves basis) of natural gas and 140.1 mmbbls (94.5 mmbbls on a net proved reserves basis) of oil and NGLs.

     On October 1, 2002, with an effective date of July 1, 2002, we acquired the New B.C. Properties, adding new established reserves of 36.1 mmboe at an average cost of $10.03 per boe (US$6.32) and net proved reserves of 23.9 mmboe at an average cost of $15.15 per boe (US$9.55). The New B.C. Properties have working interests averaging 65%, based on reserves, and are characterized by multi-zone potential at a moderate drilling depth and a mature marketing and transportation infrastructure for crude oil and natural gas. Based on the GLJ July Report, production from the New B.C. Properties for the second half of 2002 is 39.1 mmcfpd (29.5 mmcfpd net) of natural gas and 9,268 bblpd (6,975 bblpd net) of crude oil and NGLs. For the second half of 2002, the New B.C. Properties are forecast to contribute 25% of our natural gas production and 30% of crude oil and NGL production, before royalties, based on the GLJ July Report.

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     The following table provides certain information relating to our principal properties based on the GLJ July Report.You should read the information below in conjunction with “Business — Reserves — Notes to Reserves”. For a description of certain differences between estimating reserves under U.S. reserve disclosure guidelines and Canadian reserve disclosure guidelines, please read “Presentation of Our Reserve Information.”

			Canadian Presentation										United States Presentation
						Established			July 1,		Estimated		Net Proved			July 1,			Estimated
			Remaining			Reserve			2002		Future		Reserve			2002			Future
			Reserve			Life			Established		Cash Flows(3)		Life			Net Proved			Cash Flows(5)
	Operated		Life(1)			Index(2)			Reserves		(PV-10)		Index(4)			Reserves			(PV-10)
Area	By		(years)			(years)			(mboe)		($000)		(years)			(mboe)			($000)
Principal Properties (before the New B.C. Properties were acquired)
Judy Creek BHL Unit		Pengrowth		50			14			47,911		302,773					32,176			408,103
Judy Creek West BHL Unit		Pengrowth		50			16			10,841		62,958					7,509			92,423
Weyburn Unit		EnCana		39			20			14,463		65,574					8,017			44,251
Swan Hills Unit No. 1		Devon		50			22			14,303		64,840					9,617			93,471
Enchant		Pengrowth		50			19			6,939		33,440					5,147			43,837
Dunvegan Gas Unit No. 1		Devon		50			16			6,863		35,289					4,280			30,478
McLeod River		Pengrowth		35			7			4,929		40,359					2,798			36,794
Nipisi Non-Unit		Pengrowth		23			8			3,783		31,268					2,607			43,627
Monogram Gas Unit		EnCana		38			10			4,683		46,825					3,913			44,770
Goose River Unit No. 1		Conoco		31			5			3,832		31,992					2,284			37,323
Other(6)				50			13			77,688		528,290					53,567			554,305
Subtotal				50	(7)		13	(7)		196,235		1,243,608		11	(7)(8)		131,914			1,429,382
New B.C. Properties
Rigel		Pengrowth		29			4			6,558		92,549					4,300	(9)		109,200	(9)
Oak		Pengrowth		48			11			6,845		58,865					4,600	(9)		70,800	(9)
Bulrush		Pengrowth		43			9			1,923		17,035					1,200	(9)		17,300	(9)
Squirrel		Pengrowth		23			5			5,698		78,049					4,200	(9)		96,300	(9)
Tupper		Pengrowth		37			4			1,136		14,733					700	(9)		13,100	(9)
Other(10)		Pengrowth		50			9			13,944		123,408					8,800	(9)		126,000	(9)
Subtotal				50	(7)		6	(7)		36,104		384,639		5	(7)(8)		24,072	(9)		436,609	(9)
Total				50	(7)		11	(7)		232,339		1,628,247		10	(7)(8)		155,986			1,865,991

(1)	The estimated number of years for which a property will remain capable of economic production based on the established reserves of the property.
(2)	The number of years determined by dividing the established reserves as at July 1, 2002 of each property by the estimated annual production.
(3)	PV-10 is the present value of the estimated future cash flows to Pengrowth before income taxes from established reserves, discounted at 10% per year, calculated using escalated price and cost assumptions, as detailed in note (7) under “Business — Reserves — Notes to Reserves”. PV-10 is not necessarily indicative of actual future cash flows.
(4)	The net proved reserve life index has not been determined by area.
(5)	PV-10 is the present value of the estimated future net cash flows to Pengrowth before income taxes from net proved reserves, discounted at 10% per year, calculated using constant price and cost assumptions, based on the GLJ July Report. The constant prices used consist of oil at US$28.00 per bbl for WTI at Cushing, Oklahoma FOB and at $42.75 per bbl for light, sweet crude oil at Edmonton FOB and gas at $4.85 per mcf for natural gas (Alberta average) and $43.25, $24.75 and $30.75 per bbl of condensate,

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	propane and butane, respectively, at Edmonton FOB. PV-10 is not necessarily indicative of actual future cash flows.
(6)	Includes Pengrowth Corporation’s 99.99% royalty interest in the 8.4% working interest in the Sable Offshore Energy Project held by Emera Offshore Incorporated (a subsidiary of Emera Inc.) and 28 other properties. In accordance with the confidentiality agreement between Pengrowth Corporation, Emera Offshore Incorporated and the other Sable Offshore Energy Project owners, Pengrowth Corporation is precluded from presenting certain information with respect thereto except on a consolidated basis.
(7)	Average calculated on a weighted basis based on boe reserves.
(8)	The number of years determined by dividing the net proved reserves as at July 1, 2002 by the estimated annual net production.
(9)	The net proved reserves and the estimated future cash flows presented using constant price and cost assumptions for the New B.C. Properties by area are approximate and the sum of the reserves and cash flows presented by area do not equal the respective subtotals which represent the aggregate net proved reserves and estimated future cash flows, respectively, for the New B.C. Properties.

(10)  Includes 26 properties.

     Principal Properties (before the New B.C. Properties were acquired)

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

     We hold a 100% working interest in the Judy Creek Beaverhill Lake Unit (the “Judy Creek A Pool”) and a 94.6% working interest in the Judy Creek Beaverhill West 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 155.4 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 totalled 815 mmbbls of oil in the Judy Creek A Pool, making it one of the largest oil pools discovered in Western Canada. To December 31, 2001, 341.4 mmbbls has been produced from the Judy Creek A Pool. Remaining established reserves at December 31, 2001 are estimated at 49.6 mmboe (39.6 mmboe on a net proved reserves basis). Original oil in place at the Judy Creek B Pool totalled 262 mmbls and, as at December 31, 2001, 112.9 mmbbls had been produced. Gilbert Laustsen Jung Associates Ltd. estimates our working interest share of the remaining established reserves at December 31, 2001 for the July Creek B Pool are 11.2 mmboe (9.3 mmboe on a net proved reserves basis). Average production for Judy Creek in 2001 was 12,956 boepd and the remaining producing reserve life is 50 years and the reserve life index is 15 years.

     We operate both the Judy Creek A and B Pools. An enhanced oil recovery program was initiated at Judy Creek in 1985 and is continuing. In the Judy Creek hydrocarbon miscible flood program, oil production is increased by injecting a light, hydrocarbon-based solvent (ethane and methane) into the reservoir. In 2001, solvent was injected at 12 solvent injection wells and we anticipate increased oil production from up to 32 offsetting production wells.

     New development continued in 2001 with the drilling of four oil wells and three water/solvent injection wells in the Judy Creek A Pool. At year-end, oil production from the development program was in excess of 600 bblpd, with associated reserves of approximately 1.6 mmbbls. In 2002 we plan to drill at least three oil wells and two vertical injection wells. We will also carry out additional stimulations following a successful 2001 acid fracture in a lower deliverability oil well.

     In addition to oil development, we pursued natural gas opportunities in shallower reservoirs in Judy Creek. By drilling new wells and working-over existing suspended wells, we placed eight natural gas wells on production in 2001, achieving year-end working interest natural gas production rates of 4.4 mmcfpd (3.2 mmcfpd net). This was an internally-generated opportunity the value of which was not included in the engineering appraisal for the property when it was acquired by us. There may be other methods of enhancing

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future production in Judy Creek including the use of carbon dioxide as a solvent, potentially reducing solvent costs, or developing the coal bed methane. In Canada, coal bed methane technology is still in the developmental stage, but is being researched by a number of major oil and gas companies. The technology is more advanced in the United States where coal bed methane resources have been successfully harnessed for economic gas production.

     During 2001, we also focussed on reducing operating costs at Judy Creek, particularly in the area of piping. Stainless steel pipe was installed in various facilities to minimize failures and increase safety. We also optimized the use of onsite solvent to minimize the cost of solvent purchases.

     Swan Hills Unit No. 1

     We hold a 10.45% working interest in the Swan Hills Unit No. 1 located approximately 180 kilometres northwest of Edmonton in north-central Alberta. The Swan Hills Beaverhill Lake A and B pools were discovered and placed on production in 1957. The pools were unitized in 1963 to facilitate the implementation of a line drive waterflood project. Swan Hills Unit No. 1 is the second largest producing crude oil unit in Canada, producing an average of 16,794 boepd in 2001, and is operated by Devon Canada Corporation.

     Our working interest share of unit production for 2002 is estimated to be 1,772 boepd (1,282 boepd net) of oil from 200 oil wells (20.9 net wells). Gilbert Laustsen Jung Associates Ltd. estimates that Pengrowth’s remaining established reserves at December 31, 2001 are 11.4 mmbls of oil and 8.4 bcf of natural gas with a remaining producing life of 50 years and a reserve life index of 22.6 years. Development activities in the Swan Hills Unit No. 1 during 2001 included the drilling of three wells in the east platform and five wells in the reef margin.

     Dunvegan Gas Unit No. 1

     We hold a 7.97% working interest in the Dunvegan Gas Unit No. 1 located near Fairview, Alberta, approximately 430 kilometres northwest of Edmonton. The Dunvegan natural gas field is operated by Devon Canada Corporation, has 120 producing natural gas wells (9.5 net wells) and covers an area of approximately 213 square kilometres. Approximately 95% of the Dunvegan Unit’s identified natural gas reserves are contained in the Mississippian Debolt formation at a depth of approximately 1,465 meters. A natural gas processing plant, a gathering system and satellite facilities were built in 1973. A deep cut facility was completed in 1987 for the purpose of extracting propane, butane, and heavier natural gas liquids from the raw natural gas stream. Sour gas processing facilities were added in 1996. A natural gas storage project has also been implemented in the Dunvegan Unit.

     Gilbert Laustsen Jung Associates Ltd. estimates that established reserves of 393 bcf of natural gas and 23.2 mmbbls of NGLs remain to be produced from the Dunvegan Unit as at December 31, 2001 and that it has a remaining life of 50 years and a reserve life index of 17 years. Our working interest share of these reserves are 31.4 bcf (22.9 bcf on a net proved reserves basis) of natural gas and 1.9 mmbbls (1.3 mmbbls on a net proved reserves basis) of NGLs. Current production from Dunvegan Unit is obtained from five zones. In 2002, our working interest share of production is estimated to average 1,170 boepd (771 boepd net). The majority of unit gas is currently being sold under contract to Progas Limited with the remainder going to Pan-Alberta Gas Ltd. and other direct marketers. Development activities in 2001 included drilling four wells and an additional six recompletions.

     Weyburn Unit

     Pengrowth Corporation holds a 9.75% working interest in the Weyburn Unit located approximately 80 miles southeast of Regina in southeast Saskatchewan. The unit encompasses approximately 216 square kilometres. Production commenced from the Midale formation, within the unitized area, in 1955 under primary depletion (solution gas expansion). The Weyburn Unit was formed in 1963 for the purpose of implementing an inverted nine-spot waterflood pressure maintenance scheme. Commencing in 1985, the operator, EnCana Corporation, embarked on an extensive infill drilling and waterflood reconfiguration program. In recent years horizontal wells have been extensively used to arrest production declines. Produced

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oil averages 31 API (American Petroleum Institute at 60F) and contains approximately 2% sulphur. Gilbert Laustsen Jung Associates Ltd. estimates remaining established reserves for the Weyburn Unit at December 31, 2001 at 149 mmbbls of oil with a remaining producing life of 38 years and a reserve life index of 19.5 years, of which our working interest share was 14.6 mmbbls (11.8 mmbbls on a net proved reserves basis) of oil. In 2001, production from the Weyburn Unit averaged 20,800 boepd from 653 oil wells, of which our working interest share was 2,028 boepd (1,719 boepd net) of oil from 63.7 net wells.

     A carbon dioxide miscible flood project was initiated in the fall of 2000. Carbon dioxide injection has been initiated in seventeen of nineteen patterns in phase 1A of the flood with injection rates reaching the targeted 90 to 95 mmcfpd per day in September 2001. The 2002 program includes the addition of four more injection patterns. Incremental oil production to date from the carbon dioxide project has ranged from 1,887 to 2,295 bblpd and the incremental rates are expected to increase to 7,500 bblpd during 2002, of which our working interest share is 731 bblpd (620 bblpd net).

     McLeod River

     Pengrowth holds on average 48% working interest in the McLeod River property which is located approximately 70 miles from Edmonton. Production is obtained from the Rock Creek, Gething and Cardium formations. We drilled two gas wells during 2001, with working interests of 87.5 and 100%, respectively. Both wells are tied in and are on production. A compressor package was also installed on a well to reduce back pressure and maintain production. Our working interest share of production for 2001 averaged 1,972 boepd (1,291 boepd net).

     We have drilled and placed one additional well on production in March, 2002 and we expect to drill at least three additional gas wells in 2002. Wellhead compression will be installed on one or two wells to maintain production.

     Enchant

     The Enchant property is located approximately 120 miles southeast of Calgary. The property consists of four operated oil pools in which we hold an average 88% working interest. These pools produce 32 API (American Petroleum Institute at 60F) oil from the Nisku formation.

     We hold a 100% working interest in the largest pool (the J and VV pool) which consists of 33 producing and 9 injection wells with treating, water handling and gas conservation handled at a central battery. Primary production commenced in 1992 and a waterflood project was implemented in 1995. Our working interest share of established reserves is estimated at 6.6 mmbbls (5.9 mmbbls net) of oil and 2.9 bcf (2.0 bcf on a net proved reserves basis) of natural gas with our estimated 2002 average working interest share of production being 933 bblpd (805 bblpd net) of oil and 0.4 mmcfpd (0.3 mmcfpd net) of natural gas. Gilbert Laustsen Jung Associates Ltd. estimates that the Enchant property has a reserve life of 50 years and a reserve life index of 19.4 years.

     We drilled one 100% oil well during 2001 in the J and VV Pool. During 2001, we also completed a stimulation on a zone of bypassed pay, which increased production by 25 bblpd. Another producing oil well was converted from a rod pump to high volume submersible pump, which increased production by 50 bblpd. A third well was converted to an injection well to provide pressure support in the interior portion of the pool. In the Enchant Arcs Unit No. 2, where we converted a well to injection in mid-2000, pressure support is now apparent and consequently no production decline is anticipated in 2002. We expect to drill one potential oil well in the J and VV pool in 2002.

     Sable Offshore Energy Project

     The Sable Offshore Energy Project is located offshore the Province of Nova Scotia. On June 5, 2001 we acquired a 99.99% royalty interest in the reserves and production associated with the 8.4% working interest upstream of the inlet flange on the pipeline from Thebaud platform to shore held by Emera Offshore Incorporated (a subsidiary of Emera Inc.). We are responsible for Emera’s royalty share of associated capital and operating costs and our royalty interest is convertible into a working interest upon the satisfaction of various conditions. As of December 31, 2001 the total Sable Offshore Energy Project remaining established reserves are estimated by Gilbert Laustsen Jung Associates Ltd. to be 2.5 tcf of natural gas and 109 mmbbls of

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NGLs, with our royalty share estimated at 206 bcf (171 bcf on a net proved reserves basis) of natural gas and 9.1 mmbbls (7.5 mmbbls on a net proved reserves basis) of NGLs. Production averaged 543 mmcfpd of natural gas during the fourth quarter of 2001 of which our royalty interest share was 45.7 mmcfpd. Pengrowth holds its interest in the Sable Offshore Energy Project through 958503 Alberta Ltd., a wholly owned subsidiary.

     These gas reserves were discovered in the early 1970’s and commercial gas production began in December 1999. Sable Offshore Energy Project currently produces gas and NGLs from three fields in the vicinity of Sable Island, Nova Scotia — Venture, North Triumph and Thebaud. The project consists of two tiers. The first tier, completed in December 1999, included the construction of the main gas processing plant at Goldboro, a NGLs fractionation plant at Point Tupper, offshore platforms at Thebaud, North Triumph and Venture and the offshore pipeline system. Subject to owner approval, we expect the second tier to be developed between 2002 and 2007 and will add three platforms and production from wells in Alma, Glenelg and South Venture. We expect the first platform in the second tier to be installed in the Alma Field. Fabrication and construction are planned for 2002, followed by installation, commissioning and start up in 2003. Development of the fields comprising the second tier will be managed in a staged approach over the next several years.

     Sales gas from the project is delivered to the onshore gas plant facility at Goldboro, and the liquids are processed at the fractionation plant in Point Tupper. The refined gas is transported to market via the Maritimes & Northeast Pipeline.

     The New B.C. Properties

     The New B.C. Properties have working interests averaging 65% and are characterized by multi-zone potential at a moderate drilling depth and a mature marketing and transportation infrastructure for crude oil and natural gas. Average production for the year ended December 31, 2001 was 37.3 mmcfpd of natural gas and 9,599 bblpd of crude oil and NGLs. Major producing gas properties include Bulrush, Oak, Redeye and Tupper, while significant oil production is derived from Elm, Oak, Rigel and Squirrel. For the second half of 2002, the New B.C. Properties are forecast to contribute 25% of our natural gas production and 30% of crude oil and NGL production, before royalties, based on the GLJ July Report.

     Bulrush

     This area consists of eight producing gas wells and a compression and dehydration facility. A booster compressor is presently being installed to lower the field operating pressure and increase recoverable reserves. Current working interest daily sales are approximately 3.3 mmcfpd (2.5 mmcfpd net) of natural gas and 40 bblpd (32 bblpd net) of NGLs.

     Oak

     This area consists of 29 operated oil and natural gas wells, 6 injection wells and 7 source wells surrounding two batteries and three natural gas compressors, and a 20.6% working interest in a non-operated oil unit. Production is obtained from the Halfway, Cecil, Baldonnel, Cadomin and Bluesky formations. Current daily working interest sales are approximately 1,036 bblpd (approximately 808 bblpd net) of crude oil and NGLs and 3.6 mmcfpd (2.7 mmcfpd net) of natural gas. Two horizontal injection wells were drilled in 2001 to optimize the waterflood and enhance Cecil oil production and reserves recovery within the area.

     Redeye

     Redeye production is predominantly from the Bluesky and Halfway formations. Current daily working interest sales are approximately 4.5 mmcfpd (approximately 3.4 mmcfpd net) of natural gas and 216 bblpd (approximately 172 bblpd net) of crude oil and NGLs. Development of the Redeye field is complete and no additional wells were drilled in 2001. The Redeye field consists of 16 producing natural gas wells, two compressors and a dehydration facility.

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     Tupper

     This area consists of four producing gas wells, two compressors and a dehydration facility. Current daily working interest sales are approximately 4.6 mmcfpd (3.5 mmcfpd net) of natural gas and 48 bblpd (38 bblpd net) of NGLs.

     Elm

     The Elm area consists of one producing gas well, one compressor station, 15 producing oil wells 13 of which produce to a central battery and two are single battery oil wells, a central oil processing battery and one water disposal well. Current working interest daily sales are approximately 2.0 mmcfpd (1.5 mmcfpd net) of natural gas and 487 bblpd (385 bblpd net) of crude oil and NGLs. In 2001, 12 Gething oil wells were drilled and placed on production. The oil processing facility, a gas compressor station and water disposal facilities were constructed in 2001.

     Rigel

     The Rigel area consists of four Cecil oil pools containing 39 oil wells, 19 injection wells, a central battery, and a solution gas compressor. Two oil wells, four injection wells and two dry exploration wells were drilled in 2002 resulting in better pool delineation and water flood response to the Rigel Cecil oil pools. During 2000, there was an expansion of the oil battery and the waterflood plant as well as an installation of a vapour recovery unit to eliminate tank vapours and flaring. Current working interest daily sales are averaging approximately 3,730 bblpd (2,890 bblpd net) of crude oil and NGLs and 1.9 mmcfpd (approximately 1.4 mmcfpd net) of natural gas.

     Squirrel

     This area consists of 12 producing wells, four water injection wells, a gas injection well, a central battery and a compressor station. These oil wells were either drilled or acquired in 2000 to obtain production from the Triassic North Pine formation. A gas re-injection project was implemented during November 2000 to maintain pool pressure and increase oil production. Current working interest daily working interest sales for the area are approximately 2,950 bblpd (2,272 bblpd net) of crude oil and NGLs and 1.4 mmcfpd (1.1 mmcfpd net) of natural gas. During 2001, four net wells were drilled or acquired and we implemented a waterflood to maximize reserve recovery.

     Montney

     This area consists of eleven producing gas wells and a compression and dehydration facility. Solution gas from Oak North and some third party gas is also produced at this facility. Current daily working interest sales are approximately 2.1 mmcfpd (1.6 mmcfpd net) of natural gas and 45 bblpd (approximately 35 bblpd net) of NGLs.

     Beatton River

     Current working interest daily sales are approximately 214 bblpd (167 bblpd net) of crude oil and NGLs and 1.9 mmcfpd (1.4 mmcfpd net) of natural gas. The Beatton area consists of 23 oil and natural gas wells, one oil processing facility and a compressor station. Two oil wells were recompleted and placed on production in the Beatton River area in 2001.

     Weasel

     This area consists of five oil and three natural gas wells plus an oil processing facility. Current working interest daily sales are approximately 1.4 mmcfpd (1.1 mmcfpd net) of natural gas and 183 bblpd (146 bblpd net) of crude oil and NGLs.

61

Reserves

     The following summary of reserves includes those working interests and gross overriding royalty interests held by Pengrowth Corporation as at July 1, 2002. These tables reflect a summary of our reserves presented using two different sets of price and cost assumptions. Both the escalated and constant price cases are based on the GLJ July Report.Assumptions and qualifications contained in the GLJ July Report relating to prices, costs and inflation are set forth in the notes to the tables. All evaluations have been stated prior to any provision for income taxes, interest costs or general and administrative costs. It should not be assumed that any of the estimated present values of the estimated future net cash flows represent the fair market value of the reserves. Probable reserves and cash flows from probable reserves have been reduced by 50% to reflect the risk of recovery.Pengrowth Corporation is not aware of any material adverse changes in the information contained in the GLJ July Report.

     Read the following tables in conjunction with the notes set out under “Business — Reserves — Notes to Reserves”.The bold face information in the following tables indicates the information ordinarily disclosed in accordance with U.S. reserves disclosure guidelines. For a description of certain differences between estimating reserves under U.S. reserve disclosure guidelines and Canadian reserve disclosure guidelines, please read “Presentation of Our Reserve Information.”

     The tables below summarize our reserves as of July 1, 2002 before the acquisition of the New B.C. Properties.

Reserves Before the Acquisition of the New B.C. Properties

Constant Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		57,980		12,977		257.1		113,812		48,303		9,330		204.8		91,773		1,928		1,083		1,005		910		836
Proved Non-Producing		22,627		7,007		121.4		49,859		18,588		5,360		97.2		40,141		748		346		303		250		207
Total Proved		80,607		19,984		378.5		163,671		66,891		14,690		302.0		131,914		2,676		1,429		1,308		1,160		1,043
Risked Probable		17,362		3,927		62.5		31,704		13,786		2,816		46.7		24,380		578		194		167		138		116
Total Established		97,969		23,911		441.0		195,375		80,677		17,506		348.7		156,294		3,254		1,623		1,475		1,297		1,159

Reserves Before the Acquisition of the New B.C. Properties

Escalated Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		57,662		13,328		264.7		115,102		48,744		9,573		209.4		93,213		1,437		861		806		738		684
Proved Non-Producing		22,512		6,892		119.2		49,273		19,607		5,266		95.2		40,741		524		230		197		158		127
Total Proved		80,174		20,220		383.9		164,375		68,351		14,839		304.6		133,954		1,959		1,091		1,003		896		811
Risked Probable		17,382		3,957		63.1		31,860		14,260		2,843		47.1		24,956		472		152		131		107		89
Total Established		97,556		24,177		447.0		196,235		82,611		17,682		351.7		158,910		2,431		1,244		1,134		1,003		900

62

     The tables below summarize our estimated cash flow from established reserves (proved reserves plus one-half probable reserves) as at July 1, 2002 before the acquisition of the New B.C. Properties.

Estimated Cash Flows from Pengrowth’s Working Interest Share of Established Reserves

(Before the Acquisition of the New B.C. Properties)

Constant Prices and Costs, in $ millions

						Net Revenue
		Company				After						Net		Alberta							Net		Net Cash
		Interest		Royalty		Royalty		Operating		Other		Production		Royalty		Other			Abandonment		Capital		Flow Before
Year		Revenue		Burdens		Burdens		Expenses		Expenses		Revenue		Credit		Income			Costs		Investment		Income Taxes
2002			242.1		46.8		195.4		52.5		1.9		141.0		0.2		1.9			1.0		20.4		121.7
2003			491.3		77.7		413.6		149.6		3.2		260.7		0.5		14.3			1.9		74.1		199.5
2004			511.9		93.6		418.3		120.7		3.3		294.3		0.5		5.9			2.7		40.9		257.1
2005			500.7		93.3		407.4		114.5		3.1		289.9		0.5		2.9			2.5		37.6		253.2
2006			487.9		107.7		380.2		101.2		2.9		276.1		0.5		(3.1	)		2.9		17.4		253.2
2007			436.4		97.1		339.2		92.1		2.6		244.5		0.5		(4.3	)		0.7		23.4		216.6
2008			395.0		90.8		304.2		84.5		2.5		217.2		0.5		(7.6	)		1.2		10.7		198.2
2009			367.5		84.8		282.8		80.0		2.4		200.3		0.5		(8.5	)		1.0		10.7		180.7
2010			317.8		73.6		244.2		67.4		2.2		174.6		0.5		(7.1	)		1.1		6.7		160.3
2011			285.7		68.5		217.2		57.8		2.1		157.3		0.5		(6.8	)		0.7		4.0		146.4
2012			265.0		63.0		202.1		54.4		1.9		145.8		0.5		(6.4	)		0.5		3.6		135.8
2013			229.4		51.3		178.0		51.5		1.7		124.8		0.5		(5.4	)		0.3		3.3		116.4
Subtotal			4,530.6		948.0		3,582.6		1,026.2		29.8		2,526.8		5.8		(24.0	)		16.3		252.9		2,239.2
Remaining			2,159.7		351.0		1,808.6		701.5		14.7		1,092.4		13.8		(44.2	)		28.6		18.2		1,015.1
	TOTAL		6,690.3		1,299.1		5,391.2		1,727.8		44.4		3,608.9		19.6		(68.3	)		44.9		271.2		3,254.1
PV-10(1)			3,320.3		665.4		2,654.9		790.6		22.0		1,842.4		5.1		(11.3	)		14.3		198.8		1,623.0

(1)  Present value based on a discount of 10% per year.

Estimated Cash Flows from Pengrowth’s Working Interest Share of Established Reserves

(Before the Acquisition of the New B.C. Properties)

Escalated Prices and Costs, in $ millions

						Net Revenue
		Company				After						Net		Alberta							Net		Net Cash
		Interest		Royalty		Royalty		Operating		Other		Production		Royalty		Other			Abandonment		Capital		Flow Before
Year		Revenue		Burdens		Burdens		Expenses		Expenses		Revenue		Credit		Income			Costs		Investment		Income Taxes
2002			245.6		47.9		197.7		53.3		1.9		142.5		0.2		3.0			1.0		20.4		124.3
2003			451.0		66.8		384.2		153.5		3.1		227.5		0.5		16.3			2.0		75.2		167.1
2004			419.5		64.6		354.9		125.9		3.0		225.9		0.5		7.9			2.8		42.2		189.3
2005			402.7		62.5		340.3		121.2		2.9		216.1		0.5		4.8			2.6		39.4		179.4
2006			396.6		77.3		319.3		108.8		2.7		207.7		0.5		(1.4	)		3.0		18.5		185.3
2007			360.7		72.1		288.6		100.7		2.5		185.3		0.5		(2.7	)		0.8		25.3		157.1
2008			331.1		69.9		261.3		93.9		2.5		164.9		0.5		(6.1	)		1.4		11.7		146.3
2009			313.2		67.3		245.9		90.2		2.3		153.4		0.5		(7.1	)		1.1		11.9		133.8
2010			271.5		58.8		212.7		77.2		2.1		133.3		0.5		(5.8	)		1.3		7.6		119.2
2011			247.2		56.3		190.8		67.3		2.1		121.5		0.5		(5.5	)		0.8		4.5		111.2
2012			233.8		53.5		180.3		64.2		1.8		114.3		0.5		(5.2	)		0.6		4.2		104.8
2013			204.1		44.2		159.9		61.7		1.7		96.5		0.5		(4.3	)		0.3		3.8		88.5
Subtotal			3,877.1		741.3		3,135.8		1,117.9		28.7		1,989.9		5.8		(6.1	)		17.6		264.7		1,706.3
Remaining			2,108.7		335.0		1,773.7		952.3		16.2		805.2		14.6		(27.2	)		44.8		23.5		724.3
	TOTAL		5,985.8		1,076.3		4,909.5		2,070.2		44.9		2,794.1		20.3		(33.4	)		62.3		288.1		2,430.6
PV-10(1)			2,881.7		528.8		2,353.0		872.6		21.4		1,459.0		5.1		2.8			16.1		207.2		1,243.6

(1)  Present value based on a discount of 10% per year.

63

     The tables below summarize the reserves as at July 1, 2002 associated with the New B.C. Properties.

New B.C. Properties Reserves

Constant Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		10,593		1,157		58.7		21,530		8,712		920		45.5		17,216		457		337		321		300		283
Proved Non-Producing		3,664		273		26.8		8,411		3,054		216		20.4		6,663		176		96		87		77		68
Total Proved		14,257		1,430		85.5		29,941		11,766		1,136		65.9		23,879		633		433		408		377		351
Risked Probable		2,550		302		21.1		6,367		2,050		240		16.2		4,999		133		67		61		54		47
Total Established		16,807		1,732		106.6		36,308		13,861		1,376		82.1		28,878		766		500		469		431		398

New B.C. Properties Reserves

Escalated Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		10,499		1,150		58.3		21,369		8,636		915		45.3		17,094		346		264		253		239		226
Proved Non-Producing		3,668		273		26.9		8,422		3,064		216		20.3		6,674		133		69		63		55		49
Total Proved		14,167		1,423		85.2		29,791		11,700		1,131		65.6		23,768		479		334		316		294		275
Risked Probable		2,514		301		21.0		6,313		2,016		239		16.2		4,949		103		51		46		41		36
Total Established		16,681		1,724		106.2		36,104		13,716		1,370		81.8		28,717		582		385		362		334		311

64

     The tables below summarize our pro forma reserves as at July 1, 2002 including the New B.C. Properties.

Pro Forma Reserves

(Including the New B.C. Properties)

Constant Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		68,630		14,155		316.8		135,592		57,060		10,267		251.1		109,185		2,390		1,424		1,330		1,214		1,122
Proved Non-Producing		26,290		7,279		148.2		58,269		21,643		5,575		117.5		46,801		924		442		389		326		275
Total Proved		94,920		21,434		465.0		193,861		78,703		15,842		368.6		155,986		3,314		1,866		1,719		1,540		1,397
Risked Probable		19,912		4,228		83.6		38,063		15,834		3,056		62.9		29,373		711		261		229		191		163
Total Established		114,832		25,662		548.6		231,924		94,537		18,898		431.5		185,359		4,025		2,127		1,948		1,731		1,560

Pro Forma Reserves

(Including the New B.C. Properties)

Escalated Prices and Costs

																	Estimated Future Net Cash Flow
																	Before Income Tax
	Gross Reserves								Net Reserves								($ Millions)
			Natural								Natural
			Gas		Natural						Gas		Natural						Discounted at
	Oil		Liquids		Gas		BOE		Oil		Liquids		Gas		BOE		Undis-
	(mbbls)		(mbbls)		(bcf)		(mbbls)		(mbbls)		(mbbls)		(bcf)		(mbbls)		counted		10%		12%		15%		18%
Proved Producing		68,161		14,478		323.0		136,471		57,380		10,488		254.6		110,306		1,783		1,126		1,059		977		910
Proved Non-Producing		26,180		7,165		146.1		57,694		22,671		5,481		115.6		47,416		655		299		261		213		176
Total Proved		94,341		21,643		469.1		194,165		80,051		15,969		370.2		157,722		2,438		1,425		1,320		1,190		1,086
Risked Probable		19,896		4,257		84.1		38,174		16,276		3,083		63.3		29,905		575		203		177		147		125
Total Established		114,237		25,900		553.2		232,339		96,327		19,052		433.5		187,627		3,013		1,628		1,497		1,337		1,211

65

     The tables below summarize net cash flows from our pro forma established reserves (proved reserves plus one-half probable reserves), including the New B.C. Properties, estimated as of July 1, 2002.

Estimated Cash Flows from Pengrowth’s Working Interest Share of Pro Forma Established Reserves

(Including the New B.C. Properties)

Constant Prices and Costs, in $ millions

						Net Revenue
		Company				After						Net		Alberta							Net		Net Cash
		Interest		Royalty		Royalty		Operating		Other		Production		Royalty		Other			Abandonment		Capital		Flow Before
Year		Revenue		Burdens		Burdens		Expenses		Expenses		Revenue		Credit		Income			Costs		Investment		Income Taxes
2002			343.1		68.3		274.8		63.3		2.2		209.3		0.2		2.9			1.0		28.4		183.1
2003			675.8		116.0		559.8		170.5		3.7		385.7		0.5		15.9			1.9		84.0		316.1
2004			668.1		125.8		542.3		139.6		3.6		399.1		0.5		7.2			2.7		43.4		360.7
2005			629.5		119.3		510.2		130.9		3.3		376.0		0.5		4.0			2.8		38.3		339.4
2006			595.6		128.9		466.7		116.1		3.1		347.6		0.5		(2.3	)		4.0		17.6		324.2
2007			524.1		113.4		410.7		105.7		2.8		302.2		0.5		(3.6	)		1.5		23.8		273.9
2008			462.9		102.4		360.5		96.4		2.6		261.5		0.5		(7.0	)		2.3		10.9		241.8
2009			422.0		93.5		328.4		90.5		2.5		235.4		0.5		(8.1	)		2.0		10.7		215.0
2010			365.0		80.9		284.1		77.0		2.3		204.8		0.5		(6.8	)		1.9		7.2		189.4
2011			327.8		75.2		252.6		66.3		2.1		184.1		0.5		(6.5	)		1.2		4.0		172.9
2012			302.0		68.8		233.2		62.3		2.0		169.0		0.5		(6.2	)		2.1		4.0		157.2
2013			259.4		56.0		203.5		58.3		1.7		143.5		0.5		(5.2	)		1.7		3.4		133.6
	Subtotal		5,575.3		1,148.4		4,426.9		1,176.9		31.9		3,218.1		5.8		(15.7	)		25.2		275.6		2,907.4
Remaining			2,358.0		381.6		1,976.4		751.5		14.8		1,210.1		13.8		(43.2	)		43.6		19.3		1,117.9
	TOTAL		7,933.3		1,530.0		6,403.3		1,928.3		46.6		4,428.2		19.6		(58.9	)		68.8		294.9		4,025.3
PV-10(1)			4,112.2		819.4		3,292.8		902.3		23.6		2,367.0		5.1		(4.9	)		21.2		219.1		2,126.9

(1)  Present value based on a discount of 10% per year.

Estimated Cash Flows from Pengrowth’s Working Interest Share of Pro Forma Established Reserves

(Including the New B.C. Properties)

Escalated Prices and Costs, in $ millions

						Net Revenue
		Company				After						Net		Alberta							Net		Net Cash
		Interest		Royalty		Royalty		Operating		Other		Production		Royalty		Other			Abandonment		Capital		Flow Before
Year		Revenue		Burdens		Burdens		Expenses		Expenses		Revenue		Credit		Income			Costs		Investment		Income Taxes
2002			345.7		69.3		276.4		64.1		2.2		210.1		0.2		4.0			1.0		28.4		185.0
2003			612.9		100.4		512.5		174.5		3.5		334.5		0.5		17.9			2.0		85.3		265.6
2004			537.7		88.8		448.8		145.2		3.2		300.4		0.5		9.2			2.8		44.7		262.5
2005			498.2		81.6		416.6		138.2		3.0		275.4		0.5		5.8			2.9		40.0		238.7
2006			476.7		93.0		383.7		124.6		2.8		256.3		0.5		(0.6	)		4.1		18.6		233.4
2007			427.0		84.5		342.5		115.1		2.6		224.8		0.5		(2.0	)		1.6		25.6		196.1
2008			383.4		79.0		304.4		106.6		2.5		195.3		0.5		(5.5	)		2.5		11.9		175.9
2009			355.9		74.3		281.6		101.7		2.4		177.5		0.5		(6.7	)		2.2		11.9		157.2
2010			309.5		64.9		244.6		87.9		2.2		154.5		0.5		(5.4	)		2.2		8.1		139.2
2011			281.9		62.1		219.8		76.7		2.1		141.1		0.5		(5.3	)		1.3		4.6		130.4
2012			264.8		58.7		206.2		72.8		1.9		131.5		0.5		(5.0	)		2.2		4.6		120.1
2013			229.6		48.3		181.3		69.3		1.7		110.3		0.5		(4.1	)		1.7		4.1		100.9
	Subtotal		4,723.3		904.9		3,818.4		1,276.7		30.2		2,511.5		5.8		2.1			26.4		287.7		2,205.2
Remaining			2,297.9		365.5		1,932.4		1,012.4		16.2		903.9		14.6		(26.2	)		59.7		24.8		807.7
	TOTAL		7,021.2		1,270.4		5,750.8		2,289.1		46.4		3,415.4		20.3		(24.0	)		86.2		312.6		3,012.9
PV-10(1)			3,533.9		656.2		2,877.6		990.2		22.6		1,864.9		5.1		9.2			23.0		227.9		1,628.2

(1)  Present value based on a discount of 10% per year.

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Notes to Reserves

     The following notes provide important information relating to the preceding reserves estimates.

(1)	Gross reserves are defined as the total Pengrowth Corporation share of reserves. Net reserves are defined as Pengrowth Corporation’s gross reserves less all royalties payable to the Crown and others.
(2)	Gilbert Laustsen Jung Associates Ltd. has used its best engineering judgement in estimating production rates and product pricing in evaluating the properties. It should be recognized, however, that uncertainties in the oil and gas industry may result in production rates and product prices being different from those used in the GLJ July Report.
(3)	Proved Reserves: Those reserves estimated as recoverable under current technology and existing economic conditions, in the case of constant pricing, and anticipated economic conditions, in the case of escalated pricing, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir.
	Proved Producing Reserves: Those proved reserves that are actually on production or, if not producing, that could be recovered from existing wells or facilities and where the reason for the current non-producing status is the choice of the owner rather than the lack of markets or some other reason. An illustration of such a situation is where a well or zone is capable but is shut-in because its deliverability is not required to meet contract commitments.
	Proved Non-Producing Reserves: Those proved reserves that are not currently producing either due to lack of facilities and/or markets.
	Probable Reserves: Those reserves which an analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future.
	Risked Probable Reserves: Those probable reserves representing 50% of the total estimated probable reserves.
(4)	Net cash flow is income derived from the sale of net reserves of oil, gas and gas by-products, gas processing and other revenue, less all capital costs, production taxes and operation costs and before provision for income taxes and administrative overhead costs.
(5)	All values are shown in Canadian dollars.
(6)	Pengrowth Trust is entitled to claim Alberta royalty credit, which under current legislation is based on a price-sensitive formula linked to crude oil prices. Credits are generally 25% of Alberta Crown royalties unless the reference price of oil falls below $210 per cubic metre, in which case the royalty rate increases on a sliding scale to a maximum of 75% when the reference price of oil falls below $100 per cubic metre. The maximum annual Alberta Crown royalty to which the rate applies is $2,000,000 per applicant or associated group of applicants. In the GLJ July Report, the Alberta royalty credit program is assumed to continue indefinitely.
(7)	The escalating price and cost assumptions assume the continuance of current laws and regulations and any forecast changes in wellhead selling prices and take into account inflation with respect to future operating and capital costs. In the escalating price and cost assumptions evaluation contained in the GLJ July Report, operating and capital costs have been determined as of July 1, 2002 from a review of operating statements and have been escalated thereafter in accordance with Gilbert Laustsen Jung Associates Ltd.’s estimate thereof. Gilbert Laustsen Jung Associates Ltd.’s

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October 1, 2002 oil and gas price and cost forecasts, for the periods through the end of 2012, are as shown below. All prices and costs after 2012 are assumed to escalate at 1.5% per annum thereafter.

	Oil Prices
							Capital and		Natural Gas Liquid Prices
					Gas Prices		Operating		FOB Edmonton
	Edmonton		West Texas		Average		Cost
	FOB		Intermediate		Alberta Price		Escalation		Condensate		Propane		Butane
	CDN		US		CDN		Factors		CDN		CDN		CDN
Year	$/bbls		$/bbls		$/mcf		%/yr		$/bbl		$/bbl		$/bbl
2002 Q4		42.75		28.00		4.85		0		43.25		24.75		30.75
2003		36.00		24.00		4.85		1.5		36.50		23.25		24.25
2004		30.50		21.00		4.50		1.5		31.00		19.50		20.50
2005		29.50		21.00		4.50		1.5		30.00		18.50		19.50
2006		29.50		21.25		4.50		1.5		30.00		18.50		19.50
2007		30.00		21.75		4.50		1.5		30.50		19.00		20.00
2008		30.50		22.00		4.50		1.5		31.00		19.50		20.50
2009		31.00		22.25		4.55		1.5		31.50		19.75		21.00
2010		31.50		22.50		4.60		1.5		32.00		20.25		21.50
2011		32.00		23.00		4.70		1.5		32.50		20.50		22.00
2012		32.50		23.25		4.75		1.5		33.00		20.75		22.50

(8)	The US/ Canadian dollar exchange rate is assumed to be $0.64 for 2002, $0.65 for 2003, $0.67 for 2004, $0.69 for 2005, $0.70 for 2006 and beyond.
(9)	The constant price assumptions assume that the forecast prices set out above for the second half of 2002, adjusted to the wellhead and for oil quality, will remain constant for the economic life of the reserves.

(10)

Operating costs for the constant price set of assumptions are based on Gilbert Laustsen Jung Associate Ltd.’s estimate of costs as of July 1, 2002 determined from a review of operating statements, which costs are assumed to remain constant for the economic life of the reserves. Capital costs have been included to drill, complete, equip and tie-in wells where applicable. All operating costs and capital cost figures quoted in the GLJ July Report are in terms of 2002 dollars.

(11)

Gilbert Laustsen Jung Associates Ltd. estimates the total capital costs net to Pengrowth Corporation necessary to achieve the estimated future net proved and risked probable production revenues in respect of the established reserves to be as follows.

	Projected Capital Costs ($ Millions)
	2002		2003		2004		2005		Remainder		Total
Escalated Prices & Costs		28.4		85.3		44.7		40.0		114.2		312.6
Constant Pricing		28.4		84.0		43.4		38.3		100.8		294.9

(12)  Pengrowth Trust bases its distributions to unitholders on distributable income calculated in accordance with Canadian generally accepted accounting principles. The net cash flows estimated in the GLJ July Report will not correspond directly to distributable income reported by Pengrowth Trust for several reasons including the following:

(a) net cash flow before income tax from the GLJ July Report is stated prior to general and administrative expenses, interest and management fees; and

(b) for purposes of calculating distributable income, Pengrowth 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 is currently 30 months.

(13)  Well abandonment costs have been considered in evaluating the reserves. The cash flow calculations include the abandonment of wells in the evaluation (i.e., those assigned reserves and value)

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but do not include currently suspended wells or wells not assigned reserves and value which Pengrowth Corporation will analyze and accrue for.

Production

     Production History

     Our natural gas, NGLs and oil production (excluding production from the New B.C. Properties), before royalties, for the specified periods is set out in the following table.

	Natural Gas				Natural Gas Liquids				Crude Oil
													Average Daily
			Average Daily				Average Daily				Average Daily		Total
	Gas		Production				Production				Production		Production
Period(1)	mmcf		mmcfpd		mbbls		bblpd		mbbls		bblpd		boepd(2)
1997		18,744		51.4		677.2		1,856		2,792.3		7,650		18,140
1998		21,063		57.7		1,219.7		3,342		6,093.8		16,695		29,741
1999		22,445		61.5		1,433.2		3,927		6,413.1		17,570		31,821
2000		25,656		70.1		1,539.1		4,205		6,441.2		17,599		33,581
2001		33,494		91.8		1,919.3		5,258		7,199.9		19,726		40,320
June 30, 2002		19,355		106.9		936.9		5,176		3,312.7		18,302		41,312

(1)	Twelve month period ended December 31, except in the case of the six months ended June 30, 2002.
(2)	6:1 gas to equivalent barrels of oil conversion.

     The natural gas, NGLs and oil production for the New B.C. Properties, before royalties, for the specified periods is set out in the following table.

	Natural Gas				Natural Gas Liquids				Crude Oil
			Average Daily				Average Daily				Average Daily		Average Daily Total
	Gas		Production				Production				Production		Production
Period(1)	mmcf		mmcfpd		mbbls		bblpd		mbbls		bblpd		boepd(2)
1997		11,017		30.2		95		259		1,026		2,812		8,104
1998		14,842		40.7		222		609		1,850		5,068		12,460
1999		17,376		47.6		269		737		2,081		5,701		14,372
2000		15,495		42.3		293		801		2,900		7,925		15,782
2001		13,629		37.3		243		667		3,260		8,932		15,822
June 30, 2002		6,410		35.4		117		644		1,681		9,286		15,833

(1)	Twelve month period ended December 31, except in the case of the six months ended June 30, 2002.
(2)	6:1 gas to equivalent barrels of oil conversion.

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Producing Wells

     Our producing wells as at June 30, 2002 are summarized in the following table.

		Gas				Oil				Total
Property		Gross		Net		Gross		Net		Gross		Net
Judy Creek BHL Unit							132.00		132.00		132.00		132.00
Weyburn Unit							656.00		63.94		656.00		63.94
Swan Hills Unit No. 1							228.00		23.82		228.00		23.82
Judy Creek West BHL Unit							33.00		31.21		33.00		31.21
Enchant							43.00		41.20		43.00		41.20
Nipisi Non-Unit							44.00		41.80		44.00		41.80
Goose River Unit No. 1							31.00		13.10		31.00		13.10
Dunvegan Gas Unit No. 1			177.00		14.12						177.00		14.12
McLeod River			64.00		33.26		3.00		1.25		67.00		34.51
Monogram Gas Unit			375.00		201.82						375.00		201.82
Hanlan Swan Hills Pool Gas Unit No. 1			11.00		0.86						11.00		0.86
Kaybob Notikewin Unit No. 1			24.00		15.49						24.00		15.49
House Mountain Unit No. 1							107.00		13.38		107.00		13.38
House Mountain Unit No. 2							18.00		1.27		18.00		1.27
Minnehik Buck Lake Unit No. 1			22.00		3.94						22.00		3.94
Other(1)			960.00		170.66		514.00		76.16		1,474.00		246.82
	Total		1,633.00		440.14		1,809.00		439.13		3,442.00		879.27

(1)  Includes Pengrowth Corporation’s 99.99% royalty interest in the 8.4% working interest in the Sable Offshore Energy Project held by Emera Offshore Incorporated (a subsidiary of Emera Inc.) and 28 other properties. In accordance with the confidentiality agreement between Pengrowth Corporation, Emera Offshore Incorporated and the other Sable Offshore Energy Project owners, Pengrowth Corporation is precluded from presenting certain information with respect thereto except on a consolidated basis.

     The producing wells of the New B.C. Properties as at June 30, 2002 are summarized in the following table.

		Gas				Oil				Total
Property		Gross		Net		Gross		Net		Gross		Net
Rigel							37		27.0		37		27.0
Redeye			35		23.5						35		23.5
Oak			7		4.4		37		23.8		44		28.2
Montney			10		7.6						10		7.6
Beatton River			5		4.4		18		16.0		23		20.4
Bulrush			13		8.7		1		0.3		14		9.0
Squirrel							14		14.0		14		14.0
Weasel			1		0.3		2		2.0		3		2.3
Elm			2		1.5		15		15.0		17		16.5
Tupper							8		5.2		8		5.2
Other			40		20.9		11		8.0		51		28.9
	Total		113		71.3		143		111.3		256		182.6

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     Drilling Activity

     The number of wells drilled by us (excluding wells in the New B.C. Properties) for the specified periods are set out in the following table.

													Dry &
	Gas				Oil				Service				Abandoned				Total
Period(1)	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
1997		15		2.92		73		7.28						5		0.35		93		10.56
1998		60		27.74		62		4.77		11		6.45		18		3.02		151		41.98
1999		5		0.46		21		3.52						3		1.21		29		5.19
2000		8		1.20		61		21.40		19		2.99		3		0.78		91		26.37
2001		62		32.36		75		13.82		9		3.80		2		1.10		148		51.09
June 30, 2002		3		1.86		12		5.19		3		0.40						18		7.45

(1)  Twelve month period ended December 31, except in the case of the six months ended June 30, 2002.

     The number of wells drilled in respect of the New B.C. Properties for the specified periods are set out in the following table.

													Dry &
	Gas				Oil				Service				Abandoned				Total
Period(1)	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
1997		24		15.5		23		16.9		1		1.0		10		8.0		58		41.3
1998		13		9.0		24		17.8		4		2.8		15		10.9		56		40.6
1999		27		20.8		10		8.5		2		1.1		8		6.8		47		37.1
2000		21		14.5		19		15.1		10		8.4		25		22.3		75		60.3
2001		17		11.0		20		18.3		3		3.0		9		7.9		49		40.2
June 30, 2002		3		1.2		1		0.2						2		1.5		6		2.9

(1)  Twelve month period ended December 31, except in the case of the six months ended June 30, 2002.

     Capital Expenditures

     The capital expenditures, excluding property acquisitions, and excluding capital expenditures related to the New B.C. Properties made by us for the specified periods are set out in the following table.

	Capital Expenditures ($000’s)
Period(1)	Drilling and Exploration		Production Facilities		Total
1997		14,534		3,006		17,540
1998		25,330		9,595		34,925
1999		11,712		6,030		17,742
2000		45,351		14,408		59,759
2001		59,516		14,510		74,026
June 30, 2002		19,205		6,228		25,433

(1)  Twelve month period ended December 31, except in the case of the six months ended June 30, 2002.

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     The capital expenditures, excluding property acquisitions, made in respect of the New B.C. Properties to June 30, 2002 are set out in the following table.

	Capital Expenditures ($000’s)
Period(1)	Drilling and Exploration		Production Facilities		Total
1997		30,537		15,647		46,184
1998		34,917		17,271		52,188
1999		41,640		18,676		60,316
2000		72,057		15,586		87,643
2001		65,969		27,266		93,235
June 30, 2002		10,533		2,656		13,189

(1)  Twelve month period ended December 31, except in the case of the six months ended June 30, 2002.

Current Marketing and Hedging Activities

     Pengrowth uses forward and futures contracts to manage its exposure to commodity price fluctuations. Prior to the acquisition of the New B.C. Properties, the board of directors of Pengrowth Corporation set a ceiling for hedging activities of 40% of natural gas and oil production. The board of directors of Pengrowth Corporation has authorized an increase in the hedging position for volumes equivalent to up to two-thirds of Pengrowth’s net oil, natural gas and NGLs production for up to three years. This additional hedging capacity was intended to provide management with the flexibility to enter into financial hedges for up to all of the production associated with the New B.C. Properties. Prices available under financial hedges currently exceed the Gilbert Laustsen Jung Associates Ltd. price forecast effective for October 1, 2002, the application of which to the independent engineering prepared by Gilbert Laustsen Jung Associates Ltd. was an important consideration in our negotiation of the acquisition of the New B.C. Properties. The increased hedging position also allows us to avail ourselves of the benefits associated with the higher current production and the lower reserve life characteristics of the acquired properties.

     Price Hedging

     We have currently hedged 7,000 bblpd of crude oil, including foreign exchange risk, for a period expiring on December 31, 2002 at an average price of $40.35. In addition, we have hedged 7,000 bblpd of crude oil for the calendar year 2003 at an average price of $40.80 and 5,500 bblpd for the calendar year 2004 at a price of $37.90.

     We have also hedged 8,720 mcfpd of Alberta gas at an average plantgate price of $2.99 for the period expiring on October 31, 2002. For the month of November, 2002, an additional 2,087 mcfpd has been hedged at an average plantgate price of $2.80. For the calendar period 2003, one additional fixed price contract in Alberta has been entered into for 2,370 mcfpd at a plantgate price of $5.56.

     Sable Offshore Energy Project Price Hedging and Marketing

     We have hedged a total of 7,000 mmbtupd of Sable Island gas using financial swaps for the remainder of 2002 at an average Goldboro netback price of US$2.77 per mmbtu. We have also hedged 12,000 mmbtupd of Sable Island gas for the years 2003 and 2004 at an average Goldboro netback price of $4.52 per mmbtu (all subject to variations in transportation costs).

     We have contracted for the sale of 33,000 mmbtupd of our Sable Offshore Energy Project gas (approximately 72% of Pengrowth Corporation’s current Sable Offshore Energy Project production) under long term sales arrangements. Any sales gas available in excess of the contracted amounts is currently being sold on the spot market.

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Interest Rate Swaps

     We have entered into interest rate swaps on $125 million of our long term debt for periods of three years ending November 30, 2004 ($75 million), December 31, 2004 ($25 million) and March 4, 2005 ($25 million) at an average interest rate of 4.09% before stamping fees.

     The estimated fair value of these interest rate swaps at June 30, 2002 (the amount that Pengrowth Corporation would receive to terminate these contracts) was $313,000.

Other Acquisitions/ Dispositions

     We will continue to pursue an active acquisition program to acquire properties which demonstrate stable long-life production and which may offer the potential for additional development. Pengrowth may also acquire additional interests in facilities if the acquisitions have a positive impact upon Pengrowth’s distributable income and value per trust unit. Pengrowth Corporation intends to undertake development and optimization activities upon acquired interests and to farmout or sell development and exploration opportunities which are considered by the board of directors of Pengrowth Corporation to have an inappropriate level of risk relative to its other investments. Pengrowth Corporation may, from time to time, sell various non-core assets.

Industry Conditions

          Government Regulation

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

     Pricing and Marketing — Oil

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

     Pricing and Marketing — Natural Gas

     In Canada, the price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, length of contract term, weather conditions, the supply/ demand balance and other contractual terms. Natural gas exported from Canada is subject to regulation by the National Energy Board and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the National Energy Board and the government of Canada. Natural gas exports for a term of less than two years or for a term of 2 to 20 years (in quantities of not more than 30,000 m³/day), must be made pursuant to an order of the National Energy Board. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity, requires an exporter to obtain an export licence from the National Energy Board and the issue of such a licence requires the approval of the Governor in Council.

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

     The North American Free Trade Agreement

     On January 1, 1994, the North American Free Trade Agreement among the governments of Canada, the U.S. and Mexico became effective. The North American Free Trade Agreement carries forward most of the material energy terms contained in the Canada-United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements and, except as permitted in enforcement of countervailing and antidumping orders and undertakings, minimum or maximum import price requirements.

     The North American Free Trade Agreement contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The North American Free Trade Agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

     Provincial Royalties and Incentives

     In addition to federal regulations, each province in Canada has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the freehold mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location and field discovery date.

     From time to time, the federal and provincial governments in Canada have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects although the trend is toward eliminating these types of programs in favour of long term programs which enhance predictability for producers. Oil and natural gas royalty holidays and reductions for specific wells will reduce the amount of Crown royalties paid by Pengrowth to the provincial governments.

     On October 13, 1992, the government of Alberta implemented major changes to its royalty structure and created incentives for exploring and developing oil and natural gas reserves. The incentives created include: (i) a one year royalty holiday on new oil discovered on or after October 1, 1992; (ii) incentives by way of royalty holidays and reduced royalties on reactivated, low productivity, vertical re-entry and horizontal wells; (iii) introduction of separate par pricing for light/ medium and heavy oil; and (iv) a modification of the royalty formula structure through the implementation of a the third tier royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.

     In Alberta, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new gas, and between 15% and 35%, in the case of old gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 is eligible for a royalty exemption for a period of 12 months, up to a prescribed maximum amount. Natural gas produced from

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qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the wells.

     In Alberta, certain producers of oil or natural gas are also entitled to a credit against the royalties payable to the Alberta Crown by virtue of the Alberta royalty tax credit program. The Alberta royalty tax credit program is based on a price-sensitive formula, and the Alberta royalty tax credit program rate varies between 75%, at prices for oil below $100 per cubic meter, and 25%, at prices above $210 per cubic meter. The Alberta royalty tax credit program rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from companies claiming maximum entitlement to Alberta royalty tax credit program will generally not be eligible for Alberta royalty tax credit program. The Alberta royalty tax credit program rate is established quarterly based on the average “par price”, as determined by the Alberta Resource Development Department for the previous quarterly period.

     In British Columbia, the amount payable as a royalty in respect of oil depends on the vintage of the oil (whether it was produced from a pool discovered before or after October 31, 1975), the quantity of oil produced in a month and the value of the oil. Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production. The royalty payable on natural gas is determined by a sliding scale based on a reference price which is the greater of the amount obtained by the producer and a prescribed minimum price. Natural gas produced in association with oil has a minimum royalty of 8% while the royalty in respect of other natural gas may not be less than 15%.

     Effective October 1, 2002, the government of Saskatchewan revised its fiscal regime for the oil and gas industry. Some royalties on wells existing as of that date will remain unchanged and will therefore be subject to various periods of royalty/tax deduction. The changes include new lower royalty and tax structures applicable to both oil, natural gas and associated natural gas (natural gas produced from oil wells), a new system of volume incentives and a reduced corporation capital tax surcharge rate.

     The new fiscal regime for the Saskatchewan oil and gas industry provides an incentive to encourage exploration and development through a revised royalty/tax structure for oil and natural gas wells with a finished drilling date on or after October 1, 2002 or incremental oil production due to a new or expanded waterflood project with a commencement date on or after October 1, 2002. This “fourth tier” Crown royalty rate, applicable to both oil and natural gas, is price sensitive and ranges from a minimum 5% at a base price to a maximum of 30% at a price above the base price. A fourth tier freehold tax structure, calculated by subtracting a production tax factor of 12.5 percentage points from the corresponding Crown royalty rates, has also been created which is applicable to conventional oil, incremental oil from new or expanded waterfloods and natural gas. The fourth tier royalty/tax structure is also applicable in respect of associated natural gas that is gathered for use or sale which is produced either from oil wells with a finished drilling date on or after October 1, 2002 and oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of more than 3,500 m³ of natural gas per 1 m³ of oil. In addition, volume-based royalty/tax reduction incentives have been changed such that a maximum royalty of 2.5% now applies to various volumes of both oil and natural gas, depending on the depth and nature of the well (up to 16,000 m³ of oil in the case of deep exploratory wells and 25,000 m³ of natural gas produced from exploratory wells). The royalty/tax category with respect to re-entry and short sectional horizontal oil wells has been eliminated such that all horizontal oil wells with a finished drilling date on or after October 1, 2002 will receive fourth tier royalty/tax rates and incentive volumes. Further changes include the reduction of the corporation capital tax surcharge rate from 3.6% to 2.0% and the expansion of the “deep oil well” definition to include oil wells producing from a zone deeper than 1,700 meters provided that the zone is within a geological system deposited during the Mississippian Period or earlier or from a zone that was deposited before the Bakken zone regardless of depth.

     The government of Nova Scotia has established a generic royalty regime in respect of oil and gas produced from offshore Nova Scotia. Such regime contemplates a multi-tier royalty in which the royalty rate fluctuates when certain threshold levels of rates of return on capital have been reached. Notwithstanding the

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generic royalty regime, royalties in respect of offshore Nova Scotia oil and gas production may be determined contractually between the participant and the government of Nova Scotia.

     Oil and natural gas royalty holidays and reductions for specific wells reduce the amount of Crown royalties paid by Pengrowth to the provincial governments. The Alberta royalty tax credit program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties. These incentives result in increased net income and funds from the operations of Pengrowth.

     Environmental Regulation

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

     In Alberta, environmental compliance is governed by theAlberta Environmental Protection and Enhancement Act. In addition to replacing a variety of older statutes which related to environmental matters, theAlberta Environmental Protection and Enhancement Act imposes certain new environmental responsibilities on oil and natural gas operators in Alberta and in certain instances also imposes greater penalties for violations.

     In Saskatchewan, environmental compliance is governed by theEnvironmental Management and Protection Act.

     In British Columbia, energy projects may be subject to review pursuant to the provisions of theEnvironmental Assessment Act (British Columbia). TheEnvironmental Assessment Act (British Columbia) rolls the previous processes for the review of major energy projects into a single environmental assessment process which contemplates public participation in the environmental review.

     In offshore Nova Scotia, the Canada-Nova Scotia Offshore Petroleum Board created by reciprocal legislation by the governments of Canada and Nova Scotia, is responsible for environmental protection during all phases of offshore petroleum activities. All offshore projects must undergo an environmental assessment prior to approval by the Canada-Nova Scotia Offshore Petroleum Board.

     In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which will require, upon ratification, nations to reduce their emissions of carbon dioxide and other greenhouse gases. Canada has not ratified the Kyoto Protocol, but should it do so reductions in greenhouse gases from Pengrowth’s operations may be required which could result in increased capital expenditures and reductions in production of oil and gas.

     Pengrowth is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment. Pengrowth Corporation will be taking such steps as required to ensure compliance with theAlberta Environmental Protection and Enhancement Act, theEnvironmental Assessment Act (British Columbia) and similar legislation or requirements in other jurisdictions in which it operates. Pengrowth believes that it is in material compliance with applicable environmental laws and regulations. Pengrowth also believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

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STRUCTURE AND ORGANIZATION OF PENGROWTH

Introduction

     Pengrowth Trust is an oil and gas royalty trust that was created under the laws of the Province of Alberta on December 2, 1988. Pengrowth Trust is governed by a trust indenture between Pengrowth Corporation and Computershare, as trustee. In 1996, Pengrowth Trust’s original name, “Pengrowth Gas Income Fund”, was changed to “Pengrowth Energy Trust”. The purpose of Pengrowth Trust is to purchase and hold royalty units issued by Pengrowth Corporation, its majority owned subsidiary, and to issue trust units to members of the public. Pengrowth Corporation acquires, owns and manages working interests and royalty interests in oil and natural gas properties. The beneficiaries of Pengrowth Trust are the unitholders.

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

     Pengrowth Management was created under the laws of the Province of Alberta on December 16, 1982. Pengrowth Management serves as the manager of Pengrowth Trust and as the manager of Pengrowth Corporation. Pengrowth Management attends to the acquisition, development, operation and disposition of oil and natural gas properties and other related assets.

Our Structure

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

     Under the trust indenture, Pengrowth Trust has issued trust units to the unitholders. Each trust unit represents a fractional undivided beneficial interest in Pengrowth 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.

     Pengrowth Trust presently holds approximately 99.98% of the royalty units issued by Pengrowth Corporation. In addition, Pengrowth Trust holds other permitted investments, such as oil and gas processing facilities and cash. Included in these permitted investments are the interests we acquired in 1998 in certain Judy Creek and Swan Hills facilities for $106 million under a transaction where the facilities were leased back to Pengrowth Corporation in consideration for lease payments which are distributed to our unitholders.

     Pursuant to a unanimous shareholder agreement among Pengrowth Management, Pengrowth Trust, Pengrowth Corporation and Computershare, our unitholders and the holders of royalty units of Pengrowth Corporation (other than Computershare) are entitled to notice of, and to attend, all meetings of shareholders of Pengrowth Corporation and vote as shareholders at all meetings of the shareholders of Pengrowth Corporation to the same extent as if they were holders of common shares of Pengrowth Corporation, including voting on the election of the directors of Pengrowth Corporation (other than the two directors to be appointed by Pengrowth Management), approving its financial statements, appointing its auditors and appointing the auditor of Pengrowth Trust. In addition, our unitholders are entitled to vote on any proposed amendment to the unanimous shareholders agreement. Pengrowth Management refrains from exercising its rights as a shareholder except in respect of the election of two directors, or except as otherwise may be permitted by the provisions of theBusiness Corporations Act(Alberta) (and then as directed by the votes of the unitholders and the holders of royalty units of Pengrowth Corporation (other than Computershare).

     The principal business of Pengrowth Management is that of a specialty fund manager. Pengrowth Management currently provides advisory, management, and administrative services to Pengrowth Trust and to Pengrowth Corporation. Pengrowth Management also previously provided investment advisory and management services in relation to investments by several Canadian pension funds in the energy sector. These investments were later acquired by Pengrowth Corporation for royalty units and cash.

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     James S. Kinnear, president and a director of Pengrowth Management and president, chief executive officer and a director of Pengrowth Corporation, owns, directly or indirectly, all of the issued and outstanding voting securities of Pengrowth Management.

The Management Agreement

     Appointment of Pengrowth Management

     Pengrowth Trust entered into a management agreement with Pengrowth Corporation, Pengrowth Management and Computershare, as trustee, effective April 23, 2002 (replacing a management agreement dated December 2, 1998, as amended). Pengrowth Management is appointed as manager with respect to Pengrowth Corporation and Pengrowth Trust and is appointed to undertake a broad variety of matters on behalf of Pengrowth Corporation and Pengrowth Trust. The primary duties conducted by Pengrowth Management are:

(i)	advise Pengrowth Corporation with respect to its oil and natural gas properties, including the acquisition, development and disposition of such properties;
(ii)	keep Pengrowth Corporation fully informed with respect to the acquisition, exploration, development, operation and disposition of, and other dealing with, the properties of Pengrowth Corporation and the marketing or other dealing with produced petroleum substances;
(iii)	review all opportunities to acquire Canadian resource properties which, acting reasonably and in the interests of the Pengrowth Corporation, the holders of royalty units and trust units, it believes Pengrowth Corporation might reasonably be interested in acquiring. Conduct negotiations for the acquisition of Canadian resource properties, provide lease and land services related to such acquisitions (including the examination and evaluation of any title documents) and arrange for examination and preparation of legal documents or such other services required in connection with such acquisitions;
(iv)	provide all necessary services in respect of Pengrowth Corporation acting as operator of any of the properties of Pengrowth Corporation;
(v)	arrange for and negotiate, on behalf of and in the name of Pengrowth Corporation all contracts with third parties for the proper management and operation of the properties of Pengrowth Corporation;
(vi)	to the extent possible supervise the disposition and marketing of petroleum substances from the properties of Pengrowth Corporation;

(vii) arrange such audit, legal insurance and other professional services as are required by Pengrowth Corporation and Pengrowth Trust;

(viii)	arrange for all required petroleum engineering and geological services to adequately assess and evaluate the properties of Pengrowth Corporation;
(ix)	ensure that Pengrowth Corporation and the Pengrowth Trust comply with all material regulations, statutes and reporting requirements including compliance with the continuous disclosure obligations under all applicable securities legislation;
(x)	arrange for and negotiate all borrowings required by Pengrowth Corporation to purchase Canadian resource properties or to fund capital expenditures;
(xi)	administer all matters relating to the royalty units and the trust units; and
(xii)	secure office space and equipment and all necessary clerical, administrative and accounting services necessary to carry out their business and affairs.

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     The services performed by Pengrowth Management also include strategic planning, conduct of oil and gas economics, conduct of financings, and the provision of specialized advice in the areas of geology, engineering, production operations, land administration, oil and gas accounting and risk management.

     Pengrowth Management participates in the hiring of employees and consultants to perform certain of the services and supervises the activities of these employees and consultants. Expenses associated with the employment and consulting relationships can be flowed through to Pengrowth Corporation in accordance with the Management Agreement. In practise many employment and consulting arrangements have been structured directly with Pengrowth Corporation subject to the supervision of Pengrowth Management because of the structure of Pengrowth Corporation’s benefit plans and the taxation implications of those plans to employees and consultants. Also, in practise Pengrowth Management incurs expenses for its own account including certain expenses related to identifying, evaluating, negotiating and completing acquisitions on behalf of Pengrowth Corporation which Pengrowth Management could have claimed under the terms of the Management Agreement.

     The management agreement provides that Pengrowth Management will be reimbursed for all reasonable costs and expenses incurred by Pengrowth Management in connection with its duties thereunder and that Pengrowth Management will be paid management fees and acquisition fees as described below. The board of directors of Pengrowth Corporation reviews, on an ongoing basis, both the nature and extent of the services provided by Pengrowth Management and the cost of those services.

     All proposed amendments to the management agreement are considered by the board of directors of Pengrowth Corporation and by Computershare, as trustee, before being presented to the unitholders and the holders of royalty units of Pengrowth Corporation for approval by an extraordinary resolution.

     Pengrowth Management Fee

     Under the management agreement, we pay Pengrowth Management a management fee. The management fee is based upon an “income amount”, which is the aggregate of the net production revenue of Pengrowth Corporation and income earned by Pengrowth Trust from certain other categories of permitted investments other than royalty units of Pengrowth Corporation. The management fee is calculated as of the end of each calendar year as the sum of 3.5% of the first $50,000,000 of the income amount, 3.0% of the next $50,000,000 of income amount and 2.5% of any income amount in excess of $100,000,000.

     Acquisition Fee

     We also pay an acquisition fee to Pengrowth Management which is 1% of a “base amount” calculated each year and 0.5% in respect of any acquisitions in excess of the base amount. The base amount in 2001 was $100 million and will be a minimum of $100 million in all subsequent years. Beginning in 2002, if Pengrowth Corporation succeeds in replacing production from the previous year, the base amount shall be increased (but not decreased) to the actual purchase price of replacing production in that prior year. The new base amount will apply to the year in which production is replaced and to all subsequent years under the management agreement unless further increased as a result of replacing production in a subsequent year. There is no fee in respect to the disposition of properties.

     We anticipate that the acquisition of the New B.C. Properties will result in the payment of an acquisition fee of approximately $2.3 million by Pengrowth to Pengrowth Management.

     Bonus Pool

     As an incentive to officers, employees and special consultants of Pengrowth Management (including employees of Pengrowth Corporation), a bonus pool has been established which is funded from the management fee paid to Pengrowth Management, determined as a minimum of 0.25% of the income amount. Bonuses will be paid from time to time in accordance with criteria to be set at the discretion of Pengrowth Management as a further incentive for performance. It has been the practice of Pengrowth Management to exclude the President, James S. Kinnear, from participation in the bonus pool.

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     Term of Agreement

     The management agreement will remain in force for a rolling three year term such that any termination of the agreement will require a minimum of three years’ written notice. Based upon the recommendation of the independent committee of the board of directors of Pengrowth Corporation, amendments to the management agreement were approved at both a special meeting of the holders of royalty units of Pengrowth Corporation and a special meeting of our unitholders, each of which was held on April 26, 2000. The management agreement shall be considered by the unitholders at the annual meeting of holders of trust units to be held in 2003 and at the end of each succeeding three year period. If not terminated or amended pursuant to an extraordinary resolution of holders of trust units, the agreement shall automatically continue.

The Trust Indenture

     Trust Units

     Trust units are issued under the terms of the trust indenture between Pengrowth Corporation and Computershare, as trustee. A maximum of 500,000,000 trust units may be created and issued pursuant to the trust indenture, of which 90,398,323 trust units were outstanding on October 15, 2002. Each trust unit represents a fractional undivided beneficial interest in Pengrowth Trust.

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

     The Trustee

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

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

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

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     Redemption Right

     Trust units are redeemable by Computershare, as trustee, at the request of a unitholder when properly endorsed for transfer and when accompanied by a duly completed and properly executed notice requesting redemption. The redemption right permits unitholders in the aggregate to redeem trust units for maximum proceeds of $25,000 in any calendar month; provided that such limitation may be waived at the discretion of the board of directors of Pengrowth Corporation. The redemption price is the lesser of: (i) 95% of the market price of the trust units on the principal market on which the trust units are quoted for trading during the 10 day trading period commencing immediately after the date on which the trust units are surrendered for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are surrendered for redemption.

     Voting at Meetings of Pengrowth Trust

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

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

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

     Voting at Meetings of Pengrowth Corporation

     The unitholders, along with holders of royalty units other than Computershare, as trustee, are entitled to voting rights at meetings of shareholders of Pengrowth Corporation on the basis of one vote for each trust unit (or royalty unit) held.

     Termination of Pengrowth Trust

     The unitholders may vote to terminate Pengrowth Trust at any meeting of the unitholders, subject to the following:

(a)	a vote may be held only if requested in writing by the holders of not less than 25% of the trust units, or if the trust units have become ineligible for investment by RRSPs, RRIFs, RESPs and DPSPs;
(b)	the termination must be approved by extraordinary resolution of the unitholders; and
(c)	a quorum representing 5% of the issued and outstanding trust units must be present or represented by proxy at the meeting at which the vote is taken.

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

     Unitholder Limited Liability

     The trust indenture between Pengrowth Corporation and Computershare, as trustee, provides that no unitholder will be subject to any personal liability in connection with Pengrowth Trust or its obligations and affairs, and the satisfaction of claims of any nature arising out of or in connection therewith is only to be made out of Pengrowth Trust’s assets. Additionally, the trust indenture states that no unitholder is liable to indemnify or reimburse Computershare for any liabilities incurred by Computershare with respect to any taxes payable by or liabilities incurred by Pengrowth Trust or Computershare, and all such liabilities will be enforceable only against, and will be satisfied only out of, Pengrowth Trust’s assets. It is intended that the operations of Pengrowth Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the unitholders for claims against Pengrowth Trust. Notwithstanding the foregoing, because of uncertainties in the law relating to trusts such as Pengrowth Trust, there is a risk that a unitholder could be held personally liable for obligations of Pengrowth Trust to the extent that claims are not satisfied by Pengrowth Trust.

The Royalty Indenture

     Royalty Units

     Royalty units are issued under the terms of the royalty indenture between Pengrowth Corporation and Computershare, as trustee. A maximum of 500,000,000 royalty units can be created and issued pursuant to the royalty indenture. The royalty units represent fractional undivided interests in the royalty, consisting of a 99% share of “royalty income”.

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

     The royalty indenture may be amended or varied only by extraordinary resolution of the unitholders and the holders of royalty units, or by Pengrowth Corporation and Computershare, as trustee, for certain specifically defined purposes so long as, in the opinion of Computershare, the unitholders and the holders of royalty units are not prejudiced as a result.

     The holders of royalty units other than the trustee are currently entitled to vote at shareholder meetings of Pengrowth Corporation on the basis of one vote for each royalty unit held.

     The Royalty

     The royalty consists of a 99% share of “royalty income”. Under the terms of the royalty indenture, Pengrowth Corporation is entitled to retain a 1% share of “royalty income”. The royalty indenture provides that “royalty income” means the aggregate of any special distributions and gross revenue less, without duplication, the aggregate of the following amounts:

     (a) operating costs;

     (b) general and administrative costs;

     (c) management fees and debt service charges;

     (d) taxes or other charges payable by Pengrowth Corporation; and

     (e) any amounts paid into the “reserve”.

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

     The “reserve” is established by Pengrowth Corporation with miscellaneous revenues (such as processing and transportation revenues) and allowable portions of gross revenue, and must be used to fund the payment of operating costs, future abandonments, environmental and reclamation costs, general and administrative costs, management fees and debt service charges. Any amounts remaining in the reserve when there are no longer any properties that are subject to the royalty, and all of the above obligations have been satisfied, are to be paid to Pengrowth Trust so long as there are no adverse income tax consequences for Pengrowth Corporation or Pengrowth Trust, failing which such amounts shall be distributed to shareholders of Pengrowth Corporation as a dividend.

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

     To date, Pengrowth Corporation has not incurred income taxes but is subject to the federal large corporations tax and the Saskatchewan resource surcharge. Any taxes payable by Pengrowth Corporation will reduce royalty income, and thus the distributions received by holders of royalty units and trust units.

     The Trustee

     Computershare Trust Company of Canada is the trustee for the holders of royalty units under the royalty indenture. It will remain the trustee thereunder unless it resigns or is removed by unitholders. Computershare or its successor may resign on 60 days prior notice to the unitholders, and may be removed by extraordinary resolution of the unitholders. Computershare’s successor must be approved in the same manner.

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

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DIRECTORS AND OFFICERS

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

Directors and Officers of Pengrowth Management

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

Name and
Municipality of Residence	Position With Pengrowth Management	Principal Occupation
James S. Kinnear Calgary, Alberta	President and Director (since 1982)	President, Pengrowth Management Limited
Gregory S. Fletcher Calgary, Alberta	Director (since 1988)	President, Sierra Energy Inc.
Gordon M. Anderson Calgary, Alberta	Vice President, Financial Services (since 2001) Vice President, Treasurer (1997-2001) Treasurer (1995-1997)	Vice President, Financial Services Pengrowth Management Limited
Charles V. Selby Calgary, Alberta	Corporate Secretary (since 1993)	Lawyer, Selby Professional Corporation Principal, Ikon Strategies Inc.

     Each of the foregoing directors and officers has had the same principal occupation for the previous five years except for: Mr. Fletcher who was President, Canadian Conquest Exploration Inc. (1998-1999), President, Sierra Energy Inc. (1997-Present) and President, Aztec Resources Ltd. (1985-1997); and Mr. Anderson who was the Vice President, Treasurer of Pengrowth Management (1997-2001) and Treasurer of Pengrowth Management (1995-1997).

     James S. Kinnear, B.Sc., CFA, President

     Mr. Kinnear graduated from the University of Toronto in 1969 with a bachelor of science degree and received a CFA designation in 1979. In 1982 he founded Pengrowth Management and in 1988 created Pengrowth Trust. Prior to 1982 he was research director and partner with a securities firm in Montreal, Quebec and previously worked as a securities analyst in Toronto, Ontario and London, England.

Gregory S. Fletcher, B.Sc., Director

     Mr. Fletcher graduated from the University of Calgary in 1972 with a bachelor of science degree in geology and has held various positions in the oil and gas industry. In 1985 Mr. Fletcher formed Aztec Resources Ltd., a public oil and gas exploration and producing company of which he was the president and a director until 1997. From 1998 to 1999 Mr. Fletcher was president and a director of Canadian Conquest Exploration Inc., and from 1997 to the present, Mr. Fletcher has been President of Sierra Energy Inc. Mr. Fletcher was elected as a director of Denison Energy Inc., a Toronto Stock Exchange listed company in 2002.

     Gordon M. Anderson, B. Comm., CGA, Vice President, Financial Services

     Mr. Anderson joined Pengrowth in 1990 as chief accountant following a career specializing in oil and gas audit, accounting and tax. Mr. Anderson was appointed as treasurer of Pengrowth Management in 1995 and was appointed as vice president of Pengrowth Management in 1997. In 2001, Mr. Anderson was appointed as vice president, financial services. Mr. Anderson is a certified general accountant holding a bachelor of commerce degree from the University of Calgary.

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     Charles V. Selby, B.Sc. (Hons), P.Eng. LL.B., Corporate Secretary

     Mr. Selby is a lawyer and professional engineer. Mr. Selby was employed as a petroleum engineer in the energy sector prior to practicing law. He practised law with two Calgary based law firms for ten years prior to establishing an independent consulting business and legal practice in 1994. Mr. Selby is also the chairman and a director of AltaCanada Energy Corp., a junior public oil and natural gas company and is a member of the board of directors of Quest Energy Corporation.

Directors and Officers of Pengrowth Corporation

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

Name and
Municipality of Residence	Position With Pengrowth Corporation	Principal Occupation
James S. Kinnear Calgary, Alberta	President, Director and Chief Executive Officer (since 1988)	President, Pengrowth Management Limited
Francis G. Vetsch(1)(2)(4) Calgary, Alberta	Director (since 1988)	President, Quantex Resources Ltd.
Stanley H. Wong(4) Calgary, Alberta	Director (since 1988)	President, Carbine Resources Ltd., a private oil and gas producing and engineering consulting company
John B. Zaozirny(1)(2) Calgary, Alberta	Director (since 1988)	Counsel, McCarthy Tétrault LLP, Barristers and Solicitors
Thomas A. Cumming(1)(2) Calgary, Alberta	Director (since 2000)	Business Consultant
Michael A. Grandin(2)(5) Calgary, Alberta	Director (since 2002)	Independent Businessman
Robert B. Hodgins Calgary, Alberta	Chief Financial Officer (since 2002)	Chief Financial Officer, Pengrowth Corporation
Gordon M. Anderson Calgary, Alberta	Vice President (since 2001) Interim Chief Financial Officer (2001-2002) Vice President, Treasurer (1997-2001) Treasurer (1995-1997) Chief Financial Officer (1991-1998)	Vice President, Financial Services, Pengrowth Management Limited
Henry D. McKinnon Calgary, Alberta	Vice President, Operations (since 2000)	Vice President, Operations Pengrowth Corporation
Lynn Kis Calgary, Alberta	Vice President, Engineering (since 2001)	Vice President, Engineering Pengrowth Corporation
Charles V. Selby Calgary, Alberta	Corporate Secretary (since 1993)	Lawyer, Selby Professional Corporation Principal, Ikon Strategies Inc.
Christopher G. Webster Calgary, Alberta	Treasurer (since 2001)	Treasurer, Pengrowth Corporation
Lianne Bigham Calgary, Alberta	Controller (since 1996)(3)	Controller, Pengrowth Corporation

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(1)	Member of the Audit Committee.
(2)	Member of the Corporate Governance and Compensation Committee.
(3)	Ms. Bigham was appointed an officer in 2001.
(4)	Member of the Reserves Committee.
(5)	Mr. Grandin was a director of Pegasus Gold Inc. in 1988 when that company filed voluntarily to reorganize under Chapter 11 of theBankruptcy Code (United States). A liquidation plan for that company received court confirmation later that year.

     Each of the foregoing directors and officers has had the same principal occupation for the previous five years except for Mr. Cumming who was president of the Alberta Stock Exchange from 1988 to 1999; Mr. Grandin who was president, PanCanadian Energy Corporation in 2001, executive vice president and chief financial officer, Canadian Pacific Limited in 2000 and vice chairman and director, Midland Walwyn from 1996 to 1998; Mr. Hodgins who was vice president and treasurer of Canadian Pacific Limited from 1998 to 2001 and chief financial officer of TransCanada Pipelines Limited from 1993 to 1998; Ms. Kis who was general manager, engineering from 1998 to 2001 for Pengrowth Corporation and engineering manager for Jordan Petroleum from 1994 to 1998; and Mr. Webster who was manager, operations accounting from 2000 to 2001 and team leader, marketing accounting and treasury, Union Pacific Resources Inc. from 1996 to 2000.

Francis G. Vetsch, B.Sc., P.Eng.

     Mr. Vetsch is president of Quantex Resources Ltd. and is the former president of Tripet Resources and chairman of Chauvco Resources Ltd. In his earlier career he served as president and chief executive officer of Alberta Eastern Gas Ltd. for six years and vice president, operations of Atlantic Richfield Canada for six years.

Stanley H. Wong, B.Sc., P.Eng.

     Mr. Wong is president of Carbine Resources Ltd., a private oil and gas producing and engineering consulting company. He was senior engineer with Hudson’s Bay Oil & Gas for 10 years and employed by Total Petroleum (North America) Ltd. for 15 years where he was chief engineer and later became manager of special projects. He is currently a director of Cavell Energy Corporation.

John B. Zaozirny, Q.C., B.Comm., LL.B., LL.M.

     Mr. Zaozirny is counsel to McCarthy Tétrault LLP of Calgary, Alberta and is the Vice Chairman of Canaccord Capital Corporation. Mr. Zaozirny was Minister of Energy and Natural Resources for the Province of Alberta from 1982 to 1986, and currently serves as a director of numerous Canadian and international companies. He is also a Governor of The Business Council of British Columbia and a senior associate of Cambridge Energy Research Associates.

Thomas A. Cumming, BA.Sc., P.Eng.

     Mr. Cumming joined the board of directors of Pengrowth Corporation in April 2000, having held the position of president and chief executive officer of the Alberta Stock Exchange from 1988 to 1999. His career also includes 25 years with a major Canadian bank both nationally and internationally. He currently serves as a director of the Calgary Chamber of Commerce, Calgary Research & Development Authority, Calgary YMCA Foundation and the Alberta Capital Market Foundation.

Michael A. Grandin, B.Sc., P. Eng., M.B.A.

     Mr. Grandin joined the board of directors of Pengrowth Corporation in April 2002 having held the position of president of PanCanadian Energy Corporation. Mr. Grandin was executive vice president and chief financial officer, Canadian Pacific Limited from 1998 to 2001. Mr. Grandin is currently a director of Fording Coal Limited, Enerflex Systems Ltd. and EnCana Corporation.

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Robert B. Hodgins, B.A. Hons. (Bus.), C.A., Chief Financial Officer

     Mr. Hodgins joined Pengrowth Corporation in August 2002 as the chief financial officer having held the position of vice president and treasurer of Canadian Pacific Limited from 1998 to 2001. He was chief financial officer of TransCanada PipeLines Limited from 1993 to 1998. Mr. Hodgins graduated from the undergraduate program of the Richard Ivey School of Business with a bachelor of arts degree (honours) in business and received his chartered accounting designation in 1977.

Henry D. McKinnon, B.Sc., P. Eng., Vice President, Operations

     Mr. McKinnon joined Pengrowth Corporation in November 1997 having previously worked for 20 years in operations with several petroleum companies. He assumed responsibility for coordinating the transition of operations at Judy Creek and continues to be the liaison with field operations. Mr. McKinnon graduated in 1975 from the University of Manitoba with a bachelor of science degree in mechanical engineering.

Lynn Kis, B.Sc. Hons., P. Eng., Vice President, Engineering

     Ms. Kis joined Pengrowth Corporation in August 1998. She has over 20 years’ experience in the petroleum engineering field, contributing her diverse talents in reservoir and project engineering to acquiring, developing and fully exploiting properties for major oil and gas companies in western Canada. Ms. Kis graduated from the University of Wales with a bachelor of science degree (Hons) applied science and continued with post graduate studies at the University of Calgary.

Christopher G. Webster, B.Comm., CGA, CFA, Treasurer

     Mr. Webster joined Pengrowth Corporation in March 2000 as manager, operations accounting following a 12-year career in oil and gas operations accounting, marketing and treasury. He was appointed treasurer for Pengrowth Corporation in September 2001. Mr. Webster graduated from Concordia University with a bachelor of commerce degree.

Lianne Bigham, B.Comm., C.A., Controller

     Ms. Bigham joined Pengrowth in December 1993 as senior accountant and was appointed controller in 1995. She has a bachelor of commerce degree from the University of Alberta and is a chartered accountant.

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CORPORATE GOVERNANCE AND CONFLICTS OF INTEREST

Corporate Governance

Mandates of Computershare, Pengrowth Management and the Board of Directors of Pengrowth Corporation

     Under the terms of the trust indenture between Pengrowth Corporation and Computershare Trust Company, as trustee, subject to the voting rights of our unitholders, Computershare has broad power over the administration and management of Pengrowth Trust and the power to delegate those duties and responsibilities. All of our unitholders and all of the holders of royalty units of Pengrowth Corporation, other than Computershare, are entitled to attend at and vote upon all resolutions brought before meetings of the shareholders of Pengrowth Corporation on the basis of one vote for each trust unit or royalty unit held. The board of directors of Pengrowth Corporation presently consists of two nominees of Pengrowth Management and four “independent directors” who are elected by our unitholders and holders of royalty units other than the Trustee.

     The board of directors of Pengrowth Corporation has general corporate authority over the business and affairs of Pengrowth Corporation and derives its authority with respect to Pengrowth Trust by virtue of the delegation of powers by the trustee to Pengrowth Corporation as “administrator” in accordance with the trust indenture.

     Pengrowth Management derives its authority from the management agreement among Pengrowth Corporation, Pengrowth Trust, Computershare and Pengrowth Management. Pengrowth Management has broad discretion to administer and regulate the day-to-day operations of Pengrowth Trust and Pengrowth Corporation and initiates acquisition and disposition activity. Although overall responsibilities are shared between the board of directors of Pengrowth Corporation and Pengrowth Management, in practice Pengrowth Management brings recommendations forward and defers to the board of directors of Pengrowth Corporation on material acquisitions, dispositions, operational and other matters impacting upon Pengrowth Corporation and Pengrowth Trust.

Corporate Governance Guidelines

     The board of directors of Pengrowth Corporation complies with the non-mandatory guidelines for effective corporate governance published in February 1995 by the Toronto Stock Exchange Committee on Corporate Governance. The guidelines address the constitution of boards of directors and board committees, their functions, their independence from management and other means of addressing corporate governance practice.

     As a foreign private issuer in the United States, Pengrowth Trust will comply with the applicable legislative reforms contained in the Sarbanes-Oxley Act of 2002 and is considering the application of recent recommendations by the Corporate Accountability and Listings Standards Committee of the Board of the New York Stock Exchange. In practice, the board of directors of Pengrowth Corporation will seek to comply with prevailing standards for corporate governance in both Canada and the United States.

     The following are important elements of our current scheme of corporate governance:

(i)

The board of directors of Pengrowth Corporation is responsible for the overall stewardship of Pengrowth Corporation and Pengrowth Trust and for determining corporate strategy and direction. The board of directors of Pengrowth Corporation considers management development and succession programs, strategic business development such as significant acquisitions and financing proposals, including the issuance of trust units and other securities as well as those matters which require board approval;

(ii)

Two directors are related to Pengrowth by virtue of their appointment by Pengrowth Management and other factors. The remainder of the directors are independent in that they do not and have not worked for Pengrowth Corporation or Pengrowth Management nor do they

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	have material contracts with Pengrowth Corporation or Pengrowth Management and they do not receive remuneration from Pengrowth Corporation or Pengrowth Management, in excess of directors’ fees payable by Pengrowth Corporation other than trust options to acquire trust units;
(iii)	The Corporate Governance and Compensation Committee of the board of directors of Pengrowth Corporation is comprised of the four independent directors. The committee’s activities have included:

(A)  adoption of a charter for corporate governance which has been ratified by the board of directors of Pengrowth Corporation;

(B)	development of procedures for assessing the effectiveness of the board of directors of Pengrowth Corporation, its committees and individual directors;
(C)	undertaking responsibility for evaluating the performance of Pengrowth Management and making recommendations to the unitholders as to the terms of the management agreement. The committee has engaged outside advisors to review the terms of the management agreement in order to make a recommendation to our unitholders at the 2003 annual meeting, as required by the trust indenture; and

(D)  consideration of a code of business and ethics and policies on disclosure and insider trading.

(iv)	The independent members of the board of directors of Pengrowth Corporation meet separately at meetings of the board under the chairmanship of a lead director;
(v)	The audit committee of the board of directors of Pengrowth Corporation is comprised entirely of independent members of the board and communicates directly with the auditors of Pengrowth Corporation and Pengrowth Trust;
(vi)	A reserves committee of the board of directors of Pengrowth Corporation has been appointed to review Pengrowth’s standards for reporting reserves for its portfolio of oil and gas properties and communicates directly with Gilbert Laustsen Jung Associates Ltd., Pengrowth Corporation’s independent engineers; and
(vii)	All stock option plans have been approved by our unitholders.

Conflicts of Interest

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

     Oil and natural gas properties may occasionally be made available for purchase in areas where Pengrowth Management’s clients hold interests. In such circumstances, Pengrowth Management shall provide each of its clients, including Pengrowth Corporation, with the opportunity to participate in the acquisition of such properties.

     Although Pengrowth Management provides advisory and management services to Pengrowth Corporation and Pengrowth Trust, the board of directors of Pengrowth Corporation supervises the management of the

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business and affairs of Pengrowth Corporation and Pengrowth Trust. The board of directors of Pengrowth Corporation makes significant operational decisions and all decisions relating to:

(i)	the issuance of additional trust units;
(ii)	material acquisitions and dispositions of properties;
(iii)	material capital expenditures;
(iv)	borrowing; and
(v)	the payment of distributable income.

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

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

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CERTAIN INCOME TAX CONSIDERATIONS

Certain Canadian Federal Income Tax Considerations

     In the opinion of Bennett Jones LLP and Fraser Milner Casgrain LLP, the following summary describes the principal Canadian federal income tax considerations generally applicable to a unitholder who acquires trust units pursuant to this offering and who, for the purposes of theIncome Tax Act (Canada) (the “Tax Act”), holds the trust units as capital property and deals at arm’s length with Pengrowth Trust. Generally, the trust units will be considered to be capital property to a unitholder provided the unitholder does not hold the trust units in the course of carrying on a business and has not acquired them in one or more transactions considered to be an adventure in the nature of trade. Certain unitholders who might not otherwise be considered to hold their trust units as capital property may, in certain circumstances, be entitled to have them treated as capital property by making the election permitted by subsection 39(4) of the Tax Act. This summary is not applicable to: (i) a unitholder that is a “financial institution”, as defined in the Tax Act for purposes of the “mark-to-market” rules; (ii) a unitholder an interest in which would be a “tax shelter” or “tax shelter investment” as defined in the Tax Act; or (iii) a unitholder that is a “specified financial institution” as defined in the Tax Act. Any such unitholder should consult its own tax advisor with respect to an investment in trust units.

     This summary is based upon the provisions of the Tax Act in force as of the date hereof, the Income Tax Regulations, all specific proposals to amend the Tax Act and the Income Tax Regulations that have been publicly announced prior to the date hereof, theAlberta Corporate Tax Act, and counsels’ understanding of the current published administrative and assessing policies of the Canada Customs and Revenue Agency, including the advance income tax rulings obtained by Pengrowth Trust from the Canada Customs and Revenue Agency.

     This summary is not exhaustive of all possible Canadian federal income tax considerations and does not take into account any changes in the law, whether by legislative, governmental or judicial action. This summary does not take into account provincial, territorial or foreign tax considerations, which may differ significantly from those discussed herein.

     This summary is of a general nature only and is not intended to be legal or tax advice to any particular unitholder. Consequently, prospective unitholders should consult their own tax advisors with respect to their particular circumstances.

     This summary assumes that Pengrowth Trust qualifies as a “unit trust” and a “mutual fund trust” within the meaning of the Tax Act on the date of closing, and will continue to qualify thereafter, as a mutual fund trust for the duration of its existence. In order to so qualify, there must be at least 150 unitholders each of whom owns not less than one “block” of trust units having a fair market value of not less than $500. A “block” of trust units means 100 trust units if the fair market value of one trust unit is less than $25 and 25 trust units if the fair market value of one trust unit is greater than $25 and less than $100. In order to qualify as a mutual fund trust, Pengrowth Trust cannot, and may not at any time, reasonably be considered to be established or maintained primarily for the benefit of non-resident persons. In addition, the undertakings of Pengrowth Trust must be restricted to the investing of its funds in property (other than real property or an interest in real property), the acquiring, holding, maintaining, improving, leasing or managing of any real property (or interest in real property) that is capital property of Pengrowth Trust, or a combination of these activities. This summary assumes that these requirements will be satisfied so that Pengrowth Trust will qualify as a mutual fund trust at all relevant times. In the event that Pengrowth Trust were not to qualify as a mutual fund trust, the income tax considerations would, in some respects, be materially different from those described below.

     If Pengrowth Trust ceases to qualify as a mutual fund trust, the trust units will cease to be a qualified investment for trusts governed by RRSPs, RRIFs, RESPs and DPSPs as defined in the Tax Act. Where, at the end of a month, a RRSP, RRIF, RESP or DPSP holds trust units that are not qualified investments, the RRSP, RRIF, RESP or DPSP, as the case may be must, in respect of that month, pay a tax under Part XI.1 of the Tax Act equal to 1% of the fair market value of the trust units at the time such trust units were acquired by the RRSP, RRIF, RESP or DPSP. In addition, trusts governed by a RRSP or a RRIF will be subject to

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tax on the income attributable to the holding of non-qualified investments including a tax on full capital gains, if any, realized on the disposition of trust units. Where a trust governed by a RRSP or a RRIF acquires trust units that are not qualified investments, the value of the investment will be included in the income of the annuitant for the year of the acquisition. Trusts governed by RESPs which hold trust units that are not qualified investments can have their registration revoked by the Canada Customs and Revenue Agency. Additionally, if Pengrowth Trust ceases to qualify as a mutual fund trust, it will be required to pay a tax under Part XII.2 of the Tax Act. The payment of Part XII.2 tax by Pengrowth Trust may have adverse income tax consequences for certain unitholders, including non-resident persons and RRSPs, RRIFs, RESPs and DPSPs that acquire an interest in the trust units directly or indirectly from another unitholder.

     Taxation of Pengrowth Trust

     Pengrowth Trust is subject to taxation in each taxation year on its income or loss for the year as though it were a separate individual. The taxation year of Pengrowth Trust is the calendar year.

     Pengrowth Trust will be required to include in its income for each taxation year all amounts that it receives in respect of the royalty paid by Pengrowth Corporation, including amounts paid by it to Pengrowth Corporation in respect of reimbursed Crown charges, any interest on indebtedness owed by Pengrowth Corporation and any other interest in respect of its other investments that accrues to the end of the year, or becomes receivable or is received by it before the end of the year, except to the extent that such amount was included in computing its income for a preceding taxation year. Other types of income from Pengrowth Trust’s investments, including its oil and natural gas facilities, is generally required to be included in income on an accrual basis.

     In computing its income for tax purposes, Pengrowth Trust may deduct reasonable administrative expenses, capital cost allowance in respect of its oil and natural gas facilities in an amount generally equal to the lesser of the prescribed rate and the net leasing income attributable to such property, an amount not exceeding 10% of its cumulative Canadian oil and gas property expense account, determined on a declining balance basis, 20% of the total issue expenses of this offering and prior offerings to the extent that the expenses were not otherwise deductible in a preceding year and a resource allowance in each taxation year generally equal to 25% of Pengrowth Trust’s “adjusted resource profits” within the meaning of the Income Tax Regulations.

     Pengrowth Trust will be entitled to deduct from its income for a taxation year otherwise determined, after taking into account the inclusions and deductions outlined above, the portion thereof that is paid or becomes payable in the year to unitholders, including the amount which constitutes the excess, if any, of reimbursed Crown charges paid by Pengrowth Trust over the resource allowance deductible for the year to the extent that such excess amount is designated to the unitholders for that year. In accordance with the terms of the trust indenture between Pengrowth Corporation and Computershare, as trustee, Computershare has agreed to designate the full amount of such excess amount annually in favour of unitholders. An amount will be considered to be payable to a unitholder in a taxation year if it is paid in the year by Pengrowth Trust or the unitholder is entitled in the year to enforce payment of the amount. The trust indenture provides that Computershare, on behalf of Pengrowth Trust, shall claim the maximum permissible deductions for the purposes of computing the income of Pengrowth Trust pursuant to the Tax Act to the extent required to reduce the taxable income of Pengrowth Trust to nil or to the extent desirable in the best interests of unitholders. As a result, Computershare may choose not to claim all deductions in computing income and taxable income to the maximum extent permitted by the Tax Act in order to utilize losses from prior taxation years.

     Pengrowth Trust is entitled to claim Alberta royalty credit, which under current legislation is based on a price-sensitive formula linked to crude oil prices. Credits are generally 25% of Alberta Crown royalties unless the reference price of oil falls below $210 per cubic metre, in which case the royalty rate increases on a sliding scale to a maximum of 75% when the reference price of oil falls below $100 per cubic metre. The maximum annual Alberta Crown royalty to which the rate applies is $2,000,000 per applicant or associated group of applicants.

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     Taxation of Unitholders

     A unitholder will generally be required to include in computing income for a particular taxation year of the unitholder the portion of the net income of Pengrowth Trust for a taxation year that is paid or becomes payable to the unitholder in that particular taxation year, including all amounts designated to the unitholder as reimbursed Crown charges in excess of the resource allowance deducted in computing Pengrowth Trust’s income. An amount will be considered payable to a unitholder in a taxation year if the unitholder is entitled in the year to enforce payment of the amount. For the purposes of the Tax Act, income of a unitholder from the trust units will generally be deemed to be income from property and not resource income. Any deduction or loss of Pengrowth Trust for purposes of the Tax Act cannot be allocated to, or treated as a deduction or loss of, a unitholder. As discussed above, Computershare, as trustee may claim a deduction in computing income for a taxation year in an amount less than Pengrowth Trust’s income for the year payable to unitholders in order to utilize losses from prior years, subject to certain limitations under the Tax Act.

     The cost to a unitholder of trust units acquired pursuant to this offering will equal the purchase price of the trust units plus the amount of any other reasonable costs incurred in connection therewith. This cost will be averaged with the cost of all other trust units held by the unitholder to determine the adjusted cost base of each trust unit.

     Any amount paid or payable by Pengrowth Trust to a unitholder in excess of the net income of Pengrowth Trust that is paid or payable to the unitholder in a taxation year will not generally be included in the unitholder’s income for the year. However, such amount will reduce the unitholder’s adjusted cost base of the trust unit. To the extent that the adjusted cost base of a trust unit would otherwise be less than zero, the negative amount will be deemed to be a capital gain of the unitholder from the disposition of the trust unit in the year in which the negative amount arises.

     Upon the disposition or deemed disposition by a unitholder of a trust unit, the unitholder will generally realize a capital gain (or a capital loss) equal to the amount by which the proceeds of disposition (excluding any amount payable by Pengrowth Trust which represents an amount that must otherwise be included in the unitholder’s income as described above) are greater (or less) than the aggregate of the unitholder’s adjusted cost base of the trust unit and any reasonable costs associated with the disposition.

     A unitholder will generally be required to include in income one-half of the amount of any resulting capital gain (a “taxable capital gain”) and will generally be able to deduct one-half of the amount of any resulting capital loss (an “allowable capital loss”) against taxable capital gains realized by a unitholder in the same taxation year. Allowable capital losses not deducted in the taxation year in which they are realized may be carried back and deducted in any of the three preceding years or carried forward and deducted in any following years against capital gains realized in such years, to the extent and in the circumstances described in the Tax Act.

     Taxable capital gains realized by a unitholder that is an individual or a trust, other than certain types of trusts, may give rise to alternative minimum tax depending on the unitholder’s circumstances.

     A unitholder that is a “Canadian-controlled private corporation” (as defined in the Tax Act) may be liable to pay an additional refundable tax of 6 2/3% on certain investment income, including taxable capital gains and excluding income of a unitholder from trust units which is treated as property income of a unitholder only because of the deeming rule discussed above. The 6 2/3% tax is to be added to the Canadian-controlled private corporation’s refundable dividend tax on hand account and will be eligible for refund at a rate of $1 for every $3 of dividends paid by the Canadian-controlled private corporation.

Tax-Exempt Unitholders

     Provided that Pengrowth Trust qualifies as a mutual fund trust, the trust units will generally be qualified investments for trusts governed by RRSPs, RRIFs, RESPs and DPSPs as defined in the Tax Act. Subject to the specific provisions of any particular RRSP, RRIF, RESP or DPSP, the trust units offered under this prospectus are, as of the date hereof, qualified investments for trusts governed by such plans. RRSPs, RRIFs, RESPs and DPSPs will generally not be liable for tax in respect of any distributions received from Pengrowth

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Trust or, any capital gain realized on the disposition of any trust units. Pengrowth Corporation has advised counsel that, at all material times, the cost amount of foreign property of Pengrowth Trust, if any, was less than 30% of the cost amount of all property of Pengrowth Trust and, accordingly, as at the date of closing, the trust units will not constitute foreign property for RRSPs, RRIFs and DPSPs, under Part XI of the Tax Act. There are no restrictions on RESPs holding foreign property for the purposes of Part XI of the Tax Act. If Pengrowth Trust ceases to qualify as a mutual fund trust, the trust units will cease to be qualified investments for RRSPs, RRIFs, RESPs and DPSPs the consequences of which are described above.

     Non-Residents of Canada

     Where Pengrowth Trust makes distributions to a unitholder who is not resident in Canada for purposes of the Tax Act, the same considerations as those discussed above with respect to a unitholder who is resident in Canada will apply, except that any distribution of income of Pengrowth Trust to a unitholder not resident in Canada will be subject to Canadian withholding tax at a rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the unitholder’s jurisdiction of residence. For example, pursuant to theCanada — United States Income Tax Convention, 1980, residents of the United States will be entitled to have the rate of withholding reduced to 15% of the amount of any distribution of income. To the extent that Canadian withholding tax is applied to the non-taxable portion of a distribution, unitholders (or their agent) may apply for a refund of such Canadian withholding tax by filing Canada Customs and Revenue Agency Form NR7-R “Application for Refund of Non-Resident Tax Withheld” no later than two years after the end of the calendar year in which Pengrowth Trust has paid the distribution (see “Distributions”). Residents of the United States should read “Certain Income Tax Considerations — Certain United States Federal Income Tax Considerations — Tax Consequences of Trust Units Ownership — Foreign Tax Credits”.

     A disposition or deemed disposition of a trust unit, whether on redemption, by virtue of capital distributions in excess of a unitholder’s adjusted cost base or otherwise, will not give rise to any capital gain subject to tax under the Tax Act to the unitholders who for purposes of the Tax Act, are neither resident in nor deemed to be resident in Canada, do not carry on an insurance business in Canada, hold their trust units as capital property, neither use nor hold their trust units in the course of carrying on business in Canada, and deal at arm’s length with the Pengrowth Trust within the meaning of the Tax Act provided that their trust units do not constitute taxable Canadian property under the Tax Act. Trust units of a unitholder will not generally be considered to be “taxable Canadian property” unless either: (i) at any time during the period of five years immediately preceding the disposition of trust units by such unitholder, not less than 25% of the issued trust units (taking into account any rights to acquire trust units) were owned by the unitholder, by persons with whom the unitholder did not deal at arm’s length or by any combination thereof; (ii) Pengrowth Trust ceases to qualify as a mutual fund trust; or (iii) the unitholder’s trust units are otherwise deemed to be taxable Canadian property. A unitholder who is not resident in Canada will generally compute the adjusted cost base of his trust units under the same rules as apply to residents of Canada.

Certain United States Federal Income Tax Considerations

     The following is a summary of all the material United States federal income tax consequences that generally would apply to a purchaser of trust units who is a United States person, with respect to the ownership and disposition of trust units. This description is based on theInternal Revenue Code of 1986(United States), as amended (the “Code”), Treasury Regulations promulgated thereunder, and judicial and administrative interpretations thereof, all as in effect on the date hereof and all of which are subject to change either prospectively or retroactively. Unless otherwise noted, all statements of legal conclusions contained in this discussion represent the opinion of Carter, Ledyard & Milburn, United States counsel for Pengrowth Trust. That opinion is based in part upon the accuracy and completeness of certain factual representations made by us to Carter, Ledyard & Milburn. The tax treatment of an owner of our trust units may vary depending upon his particular situation. Certain owners (including persons that are not United States persons, banks, insurance companies, tax-exempt organizations, financial institutions, persons whose functional currency is not the United States dollar, persons subject to the alternative minimum tax and broker-dealers) may be subject to special rules not discussed below. The following summary is limited to investors who will own the trust units as

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“capital assets” within the meaning of the Code. The discussion below does not address the effect of any state, local or foreign tax law on an owner of the trust units. Purchasers of trust units are urged to consult with their own tax advisors with respect to circumstances peculiar to them that could affect the U.S. federal income tax treatment of their investment in the trust units.

     As used herein, the term “United States person” means an individual who is a citizen or resident of the United States, a partnership, corporation or other entity organized in or under the laws of the United States or any state thereof, an estate that is subject to United States federal income taxation without regard to the source of its income or a trust if a United States court has primary supervision over its administration and one or more United States persons have the authority to control all substantial decisions of the trust.

     Classification of Pengrowth Trust as a Partnership

     Pengrowth Trust has elected under applicable Treasury Regulations to be treated as a partnership for United States federal income tax purposes. The application of these regulations is unclear in certain respects and no rulings have been requested from the United States Internal Revenue Service (the “IRS”) with respect to the United States federal income tax treatment of Pengrowth Trust or other matters regarding Pengrowth Trust except Pengrowth Trust received a ruling from the IRS regarding the timeliness of its partnership election.

     A partnership generally is not treated as a taxable entity and incurs no United States federal income tax liability. Instead, as discussed below, each partner in an entity treated as a partnership for tax purposes is required to take into account his share of partnership income, gain, loss and deduction in computing his federal income tax liability, regardless of whether cash or other distributions are made. Distributions by a partnership to a partner are generally not taxable unless the amount of any cash distributed is in excess of the partner’s adjusted basis in his partnership interest. Each owner of trust units will be treated as a partner in Pengrowth Trust.

     Section 7704 of the Code provides that entities treated as publicly-traded partnerships such as Pengrowth Trust will, as a general rule, be taxed as corporations. However, an exception (the “qualifying income exception”) exists with respect to publicly-traded partnerships of which 90% or more of the gross income for the relevant taxable year and each preceding taxable year beginning after December 31, 1987, during which such partnership was in existence, consists of “qualifying income.” Qualifying income includes interest (from other than a financial business), dividends, rents from real property, and income and gains derived from the exploration, development, mining, production, processing, refining, transportation, or marketing of oil and gas. In the opinion of Carter, Ledyard & Milburn, income with respect to the royalty units issued by Pengrowth Corporation, to the extent attributable to qualifying income, will itself be treated as qualifying income. The income of Pengrowth Corporation is expected to consist primarily of income and gains derived from activities with respect to oil and gas that will result in qualifying income.

     Pengrowth Corporation has entered into (and intends to continue entering into) hedging transactions to protect the value of the royalty payments that it anticipates making to Pengrowth Trust. Based on certain factual representations relating to such transactions, Carter, Ledyard & Milburn is of the opinion that income from such transactions should constitute qualifying income.

     Based on certain factual representations made by Pengrowth Trust and the legal conclusions discussed above, Carter, Ledyard & Milburn is of the opinion that Pengrowth Trust has met the qualifying income exception since it first elected to be treated as a partnership for United States tax purposes in 1997. Pengrowth Trust expects that it will continue to meet the qualifying income exception in 2002 and thereafter. We estimate that less than 7% of Pengrowth Trust’s gross income will be non-qualifying income in 2002. No assurance can be given that the qualifying income exception will in fact be met.

     Possible Classification as a Corporation; PFIC

     If Pengrowth Trust fails to meet the qualifying income exception (other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery),

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Pengrowth Trust will be treated as if it had transferred all of its assets (subject to liabilities) to a newly formed corporation (on the first day of the year in which it fails to meet the qualifying income exception) in return for stock in that corporation, and then distributed that stock to the owners of our trust units in liquidation of their interests in Pengrowth Trust. That deemed transfer and liquidation would likely be taxable to the unitholders. Thereafter, Pengrowth Trust would be treated as a corporation for United States federal income tax purposes.

     If Pengrowth Trust were treated as a corporation in any taxable year, either as a result of a failure to meet the qualifying income exception or otherwise, its items of income, gain, loss and deduction would not be passed through to the unitholders. Instead, unitholders would be taxed upon the receipt of distributions, as either taxable dividend income (to the extent of Pengrowth Trust’s current or accumulated earnings and profits calculated by reference to Pengrowth Trust’s tax basis in its assets without regard to the price paid for trust units by subsequent unitholders) or (in the absence of earnings and profits) a non-taxable return of capital (to the extent of the unitholder’s tax basis in the trust units) or taxable capital gain (after the unitholder’s tax basis in the trust units is reduced to zero). In addition, should Pengrowth Trust be treated as a corporation, it is possible that it would be a considered a PFIC, in which case special rules (discussed below), potentially quite adverse to U.S. persons, would apply.

     Consequences of Possible PFIC Classification

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

     Based upon factual representations made by Pengrowth Trust concerning, among other things, the nature of its assets, income and operations, Carter, Ledyard & Milburn is of the opinion that Pengrowth Trust, if classified as a corporation, would not be a PFIC. There are, however, legal uncertainties involved and, in addition, there is no assurance that the nature of Pengrowth Trust’s assets, income and operations will continue in the same manner. Therefore, no assurance can be given that Pengrowth Trust is not now, and will not be in the future, a PFIC.

     If Pengrowth Trust were classified as a PFIC, for any year during which a unitholder owns trust units, he will generally be subject to special rules (regardless of whether Pengrowth Trust continues to be a PFIC) with respect to (1) any “excess distribution” (generally, any distribution received by him on trust units in a taxable year that is greater than 125 percent of the average annual distributions received by him in the three preceding taxable years or, if shorter, his holding period for the trust units) and (2) any gain realized upon the sale or other disposition of trust units. Under these rules:

•  the excess distribution or gain will be allocated ratably over the unitholder’s holding period;

•  the amount allocated to the current taxable year and any year prior to the first year in which Pengrowth Trust was a PFIC will be taxed as ordinary income in the current year;

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

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

     Certain elections may be available to a unitholder if Pengrowth Trust was classified as a PFIC. Pengrowth Trust will provide unitholders with information concerning the potential availability of such elections if it determines that it is or will become a PFIC.

     The discussion below is based on the assumption, consistent with the opinion of Carter, Ledyard & Milburn as discussed above, that Pengrowth Trust will be treated as a partnership for United States federal income tax purposes.

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Tax Consequences of Trust Units Ownership

     Flow-through of Taxable Income.Each unitholder will be required to report on his income tax return his share (based generally on the percentage of our trust units owned by that unitholder) of the income, gains, losses and deductions of Pengrowth Trust without regard to whether corresponding cash distributions are received by him. Consequently, a unitholder may be allocated income from Pengrowth Trust even if he has not received a cash distribution from Pengrowth Trust. Each unitholder will be required to include in income his share for the taxable year of Pengrowth Trust ending with or within the taxable year of the unitholder.

     Pengrowth Trust intends to make available to each unitholder, within 75 days after the close of each calendar year, a Schedule K-1 containing his share of Pengrowth Trust’s income, gain, loss and deduction for the preceding Pengrowth Trust taxable year.

     Pengrowth Trust treats the royalty between it and Pengrowth Corporation as a royalty interest for all legal purposes, including United Stated federal income tax purposes. Carter, Ledyard & Milburn has advised Pengrowth Trust, based upon existing authorities, that this treatment is supportable. However, the royalty indenture between Pengrowth Corporation and Computershare, as trustee, in some respects differs from more conventional “net profits” interests as to which the courts and the IRS have ruled, and as a result the matter is not free from doubt. It is possible that the IRS could contend, for example, that Pengrowth Trust should be considered to have a working interest in the properties of Pengrowth Corporation. If the IRS were successful in making such a contention, the United States federal income tax consequences to unitholders could be different, perhaps materially worse, than indicated in the discussion herein, which generally assumes that the royalty indenture will be respected as a royalty.

     Treatment of Distributions.Distributions by Pengrowth Trust to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his trust units immediately before the distribution. Cash distributions in excess of his tax basis generally will be considered to be gain from the sale or exchange of the trust units, taxable in accordance with the rules described under “— Disposition of Trust Units” below.

     Basis of Trust Units.A unitholder’s initial tax basis for his trust units will be the amount he paid for the trust units. That basis will be increased by his share of Pengrowth Trust income and decreased (but not below zero) by distributions to him from Pengrowth Trust, by his share of Pengrowth Trust losses and deductions, and by his share of expenditures of Pengrowth Trust that are not deductible in computing its taxable income and are not required to be capitalized. See “— Disposition of Trust Units — Recognition of Gain or Loss.”

     Limitations on Deductibility of Losses.Although we do not expect losses, the deduction by a unitholder of his share of any losses of Pengrowth Trust will be limited to the tax basis in his trust units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to Pengrowth Trust’s activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a trust unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

     In general, a unitholder will be at risk to the extent of the tax basis in his trust units, reduced by any amount of money he borrows to acquire or hold his trust units, if the lender of those borrowed funds owns an interest in Pengrowth Trust, is related to a person that owns an interest in Pengrowth Trust (other than the unitholder whose at risk amount is being considered), or can look only to the trust units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of his trust units increases or decreases.

     The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally

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activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately to each entity such as Pengrowth Trust which is treated as a publicly-traded partnership. Consequently, any passive losses generated by Pengrowth Trust will only be available to offset passive income generated in the future by Pengrowth Trust and will not be available to offset income from other passive activities or investments, including Pengrowth Trust investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income may be deducted in full when he disposes of his entire investment in Pengrowth Trust in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

     A unitholder’s share of net income from Pengrowth Trust may be offset by any suspended passive losses from Pengrowth Trust, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other entities treated as publicly-traded partnerships. Unitholders should consult their own tax advisors as to the applicability to them of all these limitations.

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

     Foreign Tax Credits.Subject to the limitations set forth in the Code, United States persons may elect to claim a credit against their United States federal income tax liability for net Canadian income tax withheld from distributions received in respect of the trust units (see “Certain Canadian Federal Income Tax Considerations”). Unitholders will also be entitled to claim a foreign tax credit for their share of any Canadian income taxes paid by Pengrowth Trust. Income from Pengrowth Trust will likely constitute foreign source “passive income” for purposes of the United States foreign tax credit limitation. The rules relating to the determination of the foreign tax credit are complex and prospective purchasers are urged to consult their own tax advisors to determine whether or to what extent they would be entitled to such credit. United States persons that do not elect to claim foreign tax credits may instead claim a deduction for their shares of Canadian income taxes paid by Pengrowth Trust or withheld from distributions by Pengrowth Trust.

Tax Treatment of Pengrowth Trust Operations

     Accounting Method and Taxable Year.Pengrowth Trust uses the year ending December 31 as its taxable year and has adopted the accrual method of accounting for United States federal income tax purposes. Each unitholder will be required to include in income his share of Pengrowth Trust’s income, gain, loss and deduction for the taxable year of Pengrowth Trust ending within or with the taxable year of the unitholder. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his trust units following the close of Pengrowth Trust’s taxable year but before the close of his taxable year must include his share of Pengrowth Trust income, gain, loss and deduction in income for his taxable year with the result that he will be required to report in income for his taxable year his share of more than one year of Pengrowth Trust income, gain, loss and deduction. See “— Disposition of Trust Units — Allocations Between Transferors and Transferees.”

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

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the royalty units for depletion and other purposes. Pengrowth Trust, however, intends to furnish each unitholder with information relating to this computation.

     Cost depletion is calculated by dividing the adjusted basis of a property by the total number of trust units of oil or gas expected to be recoverable therefrom and then multiplying the quotient by the number of trust units of oil and gas sold during the year. Cost depletion, in the aggregate, cannot exceed the initial adjusted basis of the property. In this connection, Pengrowth Trust intends to utilize a tax election available to it which will allow Purchasers of trust units in this offering to be entitled to depletion deductions based upon their purchase price for the trust units.

     The depletion allowance must be computed separately by each unitholder for each oil and gas property, within the meaning of Section 614 of the Code. The IRS is currently taking the position that a net profits interest carved from multiple properties is a single property for depletion purposes. The royalty indenture between Pengrowth Corporation and Computershare, as trustee, burdens multiple properties. Accordingly, Pengrowth Trust intends to take the position that the properties subject to the royalty indenture constitute a single property for depletion purposes and the income from the net profits interest will be royalty income qualifying for an allowance for depletion. Carter, Ledyard & Milburn believes this position is consistent with the policy underlying the IRS position. Pengrowth Trust anticipates that it would change this position if it should be determined that a different method of computing the depletion allowance is required by law.

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

     Impact of United States Federal Income Taxes on Hypothetical Distributions.The discussion below and the table that follows were prepared by us; counsel has not been engaged to and has not undertaken to opine on the discussion or table set forth below. The following table of examples is not intended to be a projection or forecast of the actual results from an investment in trust units. The purpose of the table is to illustrate the possible impact of United States federal income taxes on a unitholder at various hypothetical distribution levels. Distributions over the past five years (including 6 month annualized distributions for 2002) have ranged from $1.53 (US$0.96) to $3.79 (US$2.39) per trust unit and have averaged approximately $2.50 (US$1.58). The examples are based upon a trust unit trading price of US$9.07 which was the closing price of the trust

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units on the New York Stock Exchange on October 10, 2002. The following table was prepared by us and is not based upon an independent opinion rendered by an accountant or lawyer.

	Dec. 31, 2001			Hypothetical (US$)
	Actual (US$)
Annual pre-tax distributions paid		2.27			1.00		1.50		2.00		2.50
15% Canadian withholding tax(3)		(0.34	)		(0.15	)	(0.225	)	(0.30	)	(0.375	)
Net distributions to United States investors		1.93			0.85		1.275		1.70		2.125
Allocated share of income(1)		1.99			1.00		1.50		2.00		2.50
Depletion/depreciation(2)		(0.94	)		(0.68	)	(0.68	)	(0.68	)	(0.68	)
United States federal taxable income		1.05			0.32		0.82		1.32		1.82
United States federal income tax (38.6%)		(0.41	)		(0.12	)	(0.32	)	(0.51	)	(0.7 0	)
Withholding taxes refunded or credited against United States taxes(3)		0.34			0.15		0.225		0.30		0.375
Net distributions paid to United States investors after federal taxes(4)		1.86			0.88		1.18		1.49		1.86
Annual pre-tax distributions to unit price		17.8	%		11.0	%	16.5	%	22.1	%	27.6	%
Annual after-tax distributions to unit price		14.6	%		9.7	%	13.0	%	16.4	%	19.8	%

(1)	Pre-tax distributions paid with respect to a trust unit may differ from the income allocated to the trust unit (before depletion and depreciation deductions) for a fiscal year for various reasons, including the fact that distributions are generally paid two months after the income is recognized. Over longer periods of time, pre-tax distributions paid and allocations of income (before depletion and depreciation deductions) with respect to a trust unit should be substantially equal.
(2)	The depletion deduction for the column entitled “Dec. 31, 2001 Actual” is $0.94 per trust unit for a unitholder that purchased units at US$12.70 per unit on January 2, 2001. The depletion deduction for the remaining columns is assumed to be US$0.68 per trust unit based upon the purchase of a trust unit at a purchase price of US$9.07 per trust unit, the closing price of the trust units on the New York Stock Exchange on October 11, 2002. In general, the depletion deduction will remain constant if production remains constant and reserves are not added. It is anticipated, however, that the depletion deduction available to unitholders will fluctuate.
(3)	Withholding taxes are refundable, subject to certain limitations, in the same proportion that the distributions are treated as a return of capital in Canada and the balance of the withholding taxes can generally be credited against United States income taxes payable, subject to certain limitations, or taken as a deduction against taxable income by a United States unitholder. For purposes of this table, it is assumed that one-half of the Canadian withholding taxes will be refunded. See “Certain Income Tax Considerations — Certain Canadian Federal Income Tax Considerations — Non-Residents of Canada”.
(4)	Net distributions paid to United States investors after taxes are assumed to be equal to pre-tax distributions less the United States income tax. It is assumed that any Canadian withholding tax that is not refunded will be credited against United States income tax. This assumption may not be true in all cases.

     Valuation of Pengrowth Trust’s Properties.Certain of the United States federal income tax consequences of the ownership and disposition of trust units will depend in part on Pengrowth Trust’s estimates of the relative fair market value of its assets. Although Pengrowth Trust may consult from time to time with professional appraisers regarding valuation matters, Pengrowth Trust will itself make many of the relative fair market value estimates. These estimates are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be

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required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

     Section 754 Election.Pengrowth Trust has made the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. The election will generally require Pengrowth Trust, in the case of a sale of the trust units in the secondary market, to adjust the purchaser’s tax basis in the assets of Pengrowth Trust pursuant to Section 743(b) of the Code to reflect his purchase price. This election does not apply to a person who purchases trust units directly from Pengrowth Trust in this Offering.

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

     Transfers of Units to Employees or Directors of Pengrowth Corporation and Pengrowth Management.Under Pengrowth’s trust unit option plan and the share appreciation rights plan, employees and directors of Pengrowth Corporation and Pengrowth Management may receive trust units for less than their fair market value on the date of issuance. The United States federal income tax treatment of such transfers to Pengrowth Trust and the unitholders is not clear. It is possible that the IRS could take the position that Pengrowth Trust should be treated as having disposed of a pro rata portion of all of its assets, equal in value to the amount of such discount, thereby recognizing taxable gain (or loss), which would flow through to unitholders. In such event, Pengrowth Trust may be entitled to an offsetting compensation deduction.

Disposition of Trust Units

     Recognition of Gain or Loss.A portion of any amount realized on a sale or exchange of trust units (which portion could be substantial) will be separately computed and taxed as ordinary income under Section 751 of the Code to the extent attributable to the recapture of depletion or depreciation deductions. The difference between the balance of the amount realized and the unitholder’s tax basis for the trust units sold will represent gain (or loss) on the disposition of the trust units. Ordinary income attributable to depletion deductions and depreciation recapture could exceed net taxable gain realized upon the sale of the trust units and may be recognized even if there is a net taxable loss realized on the sale of the trust units. Thus, a unitholder may recognize both ordinary income and a capital loss upon a taxable disposition of trust units. Net capital loss may offset no more than $3,000 of ordinary income in the case of individuals and may only be used to offset capital gain in the case of corporations.

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

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     Allocations Between Transferors and Transferees. In general, Pengrowth Trust’s taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of trust units owned by each of them on the first business day of the month (the “allocation date”). However, gain or loss realized on a sale or other disposition of Pengrowth Trust assets other than in the ordinary course of business, and other extraordinary items, will be allocated among the unitholders on the allocation date in the month in which that gain or loss is recognized.

     Notification Requirements. A unitholder who sells or exchanges trust units is required to notify Pengrowth Trust in writing of that sale or exchange within 30 days after the sale or exchange and in any event by no later than January 15 of the year following the calendar year in which the sale or exchange occurred. Pengrowth Trust is required to notify the IRS of that transaction and to furnish certain information to the transferor and transferee. However, these reporting requirements do not apply with respect to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Additionally, a transferor and a transferee of trust units will be required to furnish statements to the IRS, filed with its income tax return for the taxable year in which the sale or exchange occurred, that allocates the consideration paid for the trust units. This information will be provided by Pengrowth Trust. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties.

     Constructive Termination. Pengrowth Trust will be considered to have been terminated for United States federal income tax purposes if there is a sale or exchange of 50% or more of the total trust units within a 12-month period. A termination of Pengrowth Trust will result in a decrease in tax depreciation available to the unitholders thereafter and in the closing of its taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of Pengrowth Trust’s taxable year may result in more than 12 months’ taxable income or loss of Pengrowth Trust being includable in his taxable income for the year of termination. New tax elections would have to be made by Pengrowth Trust subsequent to a termination including a new election under Section 754 of the Code. Adverse tax consequences could ensue if Pengrowth Trust were unable to determine that the termination had occurred. Finally, a termination of Pengrowth Trust could result in taxation of Pengrowth Trust as a corporation if the qualifying income exception was not met in the short taxable years caused by termination. See “— Classification of Pengrowth Trust as a Partnership.”

     Treatment of Trust Unit Lending and Short Sales. A unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of ownership of those trust units. If so, he would no longer be a partner with respect to those trust units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period, any Pengrowth Trust income, gain, deduction or loss with respect to those trust units would not be reportable by the unitholder, any cash distributions received by the unitholder with respect to those trust units would be fully taxable and all of such distributions would appear to be treated as ordinary income. Unitholders desiring to assure their status as owners of trust units and avoid the risk of gain recognition resulting from the application of these rules should modify any applicable brokerage account agreements to prohibit their brokers from borrowing or loaning their trust units.

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

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Uniformity of Trust Units

     Because Pengrowth Trust cannot match transferors and transferees of trust units, it must maintain uniformity of the economic and tax characteristics of the trust units to a purchaser of these trust units. In the absence of uniformity, Pengrowth Trust may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory.

     A lack of uniformity can result from a literal application of some Treasury regulations. Any non-uniformity could have a negative impact on the value of the trust units.

Tax-Exempt Organizations and Regulated Investment Companies

     Employee benefit plans (including individual retirement accounts (“IRAs”) and other retirement plans) and most other organizations exempt from federal income tax (each, a “TEO”) are subject to federal income tax on unrelated business taxable income (“UBTI”). Because we expect substantially all income of Pengrowth Trust to be royalty income, rents from real property or interest, none of which is UBTI, a TEO should not be taxable on any income generated by ownership of the trust units except as described in the next paragraph. However, the royalty indenture between Pengrowth Corporation and Computershare, as trustee, is in several respects an unusual royalty indenture, for which there is no clear United States income tax guidance. It is possible that the IRS could contend that some or all of the income of Pengrowth Trust under the royalty indenture does not qualify as royalty income, but should instead be treated as UBTI. In addition, the classification of certain facilities owned by Pengrowth Trust as real property or personal property is a determination subject to uncertainty. If such facilities were determined to be personal property for United States federal income tax purposes, the rent derived therefrom would be UBTI to a TEO. Prospective purchasers of trust units that are TEOs are encouraged to consult their tax advisors regarding the foregoing.

     If the trust units constitute “debt-financed property” within the meaning of Code Section 514(b), then a portion of any interest, rents from real property and royalty income received by the TEO attributable to the trust units will be treated as UBTI and thus will be taxable to a TEO. Under Code Section 514(b), “debt-financed property” is defined as any property which is held to produce income and with respect to which there is acquisition indebtedness.

     A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends, gains from the sale of stocks or securities or foreign currency or certain related sources (“RIC qualifying income”). It is anticipated that substantially all of Pengrowth Trust’s gross income will be non-RIC qualifying income. Furthermore, it is unclear whether gain from the sale of the trust units is properly treated as RIC qualifying income. Prospective purchasers of our trust units that are regulated investment companies are encouraged to consult their tax advisors regarding the impact of these rules on their status as regulated investment companies.

Administrative Matters

     Pengrowth Trust Information Returns. Pengrowth Trust currently is not required to file a United States federal income tax return, since it has no gross income derived from sources within the United States or gross income which is effectively connected with the conduct of a trade or business within the United States. However, the IRS may require a unitholder to provide statements or other information necessary for the IRS to verify the accuracy of the reporting by the unitholder on its income tax return of any items of Pengrowth Trust’s income, gain, loss, deduction, or credit. If Pengrowth Trust were to file a United States tax return in future tax years, the filing would change the manner in which they provide tax information to the unitholders and special procedures would also apply to an audit of such tax return by the IRS.

     Registration as a Tax Shelter. The Code requires that “tax shelters” be registered with the Secretary of the Treasury. The temporary Treasury Regulations interpreting the tax shelter registration provisions of the Code are extremely broad. It is arguable that Pengrowth Trust is not subject to the registration requirement on the basis that it will not constitute a tax shelter. However, Pengrowth Trust has registered as a tax shelter with the Secretary of the Treasury because of the absence of assurance that it will not be subject to tax shelter

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registration and in light of the substantial penalties which otherwise might be imposed if it failed to register and it were subsequently determined that registration was required.

     The IRS has issued Pengrowth Trust the following tax shelter registration number: 99068000003.

     You must report this registration number to the IRS, if you claim any deduction, loss, credit, or other tax benefit or report any income by reason of your investment in Pengrowth Trust.

     You must report the registration number (as well as the name, and taxpayer identification number of Pengrowth Trust) on Form 8271. Pengrowth Trust’s taxpayer identification number is 98-0185056.

     Form 8271 must be attached to the return on which you claim the deduction, loss, credit, or other tax benefit or report any income.

     Issuance of a registration number does not indicate that an investment in Pengrowth Trust or the claimed tax benefits have been reviewed, examined, or approved by the IRS.

     A unitholder who sells or otherwise transfers trust units must furnish the tax shelter registration number to the transferee. The penalty for failure of the transferor of a trust unit to furnish the registration number to the transferee is $100 for each such failure. The unitholders must disclose the tax shelter registration number of Pengrowth Trust on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit generated by Pengrowth Trust is claimed or income of Pengrowth Trust is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed herein are not deductible for federal income tax purposes.

     Accuracy-Related Penalties. In addition, a penalty equal to 20% of the amount of any portion of an underpayment of tax which is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, with respect to any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith with respect to that portion. Special rules exist for “tax shelters,” a term that in this context does not appear to include Pengrowth Trust. In addition, Pengrowth Trust will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid any such penalty attributable to ownership of the trust units.

     Foreign Partnership Reporting. A unitholder who contributes more than US$100,000 to Pengrowth Trust (when added to the value of any other property contributed to Pengrowth Trust by such person or a related person during the previous 12 months) in exchange for trust units, may be required to file Form 8865,Return of US Persons With Respect to Certain Foreign Partnerships, in the year of the contribution. There may be other circumstances when a unitholder is required to file Form 8865.

ERISA CONSIDERATIONS

     An investment in trust units by employee benefit plans is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions ofThe Employee Retirement Income Security Act of 1974 (United States) (“ERISA”) and restrictions imposed by Section 4975 of the Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Prior to an employee benefit plan investing in trust units, consideration should be given to, among other things to: (a) whether the investment is prudent under Section 404(a)(1)(B) of ERISA; (b) whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and (c) whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in trust units is authorized by the appropriate plan documents and is a proper investment for the plan. Section 406 of ERISA

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and Section 4975 of the Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan. In addition to considering whether the purchase of trust units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in trust units, be deemed to own an undivided interest in the assets of Pengrowth Trust, with the result that Pengrowth Management also would be a fiduciary of the plan and Pengrowth Trusts’ operations would be subject to the regulatory provisions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.

     Regulations issued by the U.S. Department of Labor provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things, the equity interests acquired by employee benefit plans are (i) publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other; (ii) freely transferable; and (iii) registered under some provisions of the federal securities laws. Pengrowth Trust’s assets should not be considered “plan assets” under these regulations because our trust units will satisfy the requirements described above. Plan fiduciaries contemplating a purchase of our trust units should consult with their own counsel regarding the consequences under ERISA and the Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, and the tax issues discussed above.

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UNDERWRITING

     This offering is being made concurrently in all provinces of Canada and in the United States pursuant to the multi-jurisdictional disclosure system implemented by securities regulatory authorities in Canada and the United States. The Canadian underwriters will offer the trust units to investors in Canada and the United States underwriters will offer the trust units to investors in the United States. RBC Capital Markets is the global coordinator of the offering and the lead manager and book-runner of the offering to Canadian residents. Lehman Brothers Inc. and RBC Capital Markets are the joint lead managers and book-runners of the offering to United States residents.

     We and Pengrowth Management have entered into an underwriting agreement (the “Canadian Underwriting Agreement”) with RBC Dominion Securities Inc., BMO Nesbitt Burns Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc., Scotia Capital Inc., UBS Bunting Warburg Inc., HSBC Securities (Canada) Inc., Canaccord Capital Corporation, Raymond James Ltd., Dundee Securities Corporation, and FirstEnergy Capital Corp. (the “Canadian Underwriters”) with respect to the offering of                     trust units to Canadian residents. Pursuant to the Canadian Underwriting Agreement, subject to certain conditions, each of the Canadian Underwriters has severally agreed to purchase, and we have agreed to sell, the number of trust units indicated in the following table at a purchase price of Cdn$                    per trust unit. We will pay underwriting discounts and commissions of Cdn$                    per trust unit purchased by the Canadian Underwriters. The obligations of the Canadian Underwriters under the Canadian Underwriting Agreement are several and may be terminated at their discretion on the occurrence of certain stated events. The obligations of the Canadian Underwriters under the Canadian Underwriting Agreement will be terminated on the termination of the obligations of the U.S. Underwriters to purchase trust units under the U.S. Underwriting Agreement.

     We and Pengrowth Management have entered into an underwriting agreement (the “U.S. Underwriting Agreement”) with Lehman Brothers Inc., RBC Dain Rauscher Inc., UBS Warburg LLC, McDonald Investments Inc. and Raymond James & Associates, Inc. (the “U.S. Underwriters”) with respect to the offering of                      trust units to United States residents. Pursuant to the U.S. Underwriting Agreement, subject to certain conditions, each of the U.S. Underwriters has severally agreed to purchase, and we have agreed to sell, the number of trust units indicated in the following table at a purchase price of US$                     per trust unit. We will pay underwriting discounts and commissions of US$                     per trust unit purchased by the U.S. Underwriters. The obligations of the U.S. Underwriters under the U.S. Underwriting Agreement are several and may be terminated at their discretion on the occurrence of certain stated events. The obligations of the U.S. Underwriters under the U.S. Underwriting Agreement will be terminated on the termination of the obligations of the Canadian Underwriters to purchase trust units under the Canadian Underwriting Agreement.

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		Number of
		Trust Units
Canadian Underwriters
RBC Dominion Securities Inc.
BMO Nesbitt Burns Inc.
CIBC World Markets Inc.
TD Securities Inc.
National Bank Financial Inc.
Scotia Capital Inc.
UBS Bunting Warburg Inc.
HSBC Securities (Canada) Inc.
Canaccord Capital Corporation
Raymond James Ltd.
Dundee Securities Corporation
FirstEnergy Capital Corp.
	Total
U.S. Underwriters
Lehman Brothers Inc.
RBC Dain Rauscher Inc.
UBS Warburg LLC
McDonald Investments Inc.
Raymond James & Associates, Inc.
	Total
Aggregate Total

     The Canadian Underwriting Agreement and the U.S. Underwriting Agreement provide that the underwriters are obligated to purchase, subject to certain conditions, all of the trust units in the offering if any are purchased, other than those covered by the over-allotment option described below. The conditions contained in the Canadian Underwriting Agreement and the U.S. Underwriting Agreement include the requirements that:

•  the representations and warranties we made to the underwriters are true,

•  there is no material change in the financial markets, and

•  we deliver to the underwriters customary closing documents.

     Under the Canadian Underwriting Agreement, we have granted to the Canadian Underwriters an over-allotment option to purchase up to an aggregate of                      additional trust units at $                     per trust unit and the Canadian Underwriters will receive a commission of $                     per trust unit purchased under this over-allotment option. This option may be exercised, in whole or in part, for a period of 30 days from the date of closing of this offering solely to cover over-allotments, if any, made in connection with the offering. Each Canadian Underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional trust units based on its pro rata portion of the underwriting commitment in the offering shown in the preceding table.

     Under the U.S. Underwriting Agreement we have granted to the U.S. Underwriters an over-allotment option to purchase up to an aggregate of                      additional trust units at US$                     per trust unit and the U.S. Underwriters will receive a commission of US$                     per trust unit purchased under this over-allotment option. This option may be exercised, in whole or in part, for a period of 30 days from the date

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of closing of this offering solely to cover over-allotments, if any, made in connection with the offering. Each U.S. Underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional trust units based on its pro rata portion of the underwriting commitment in the offering shown in the preceding table.

     The purchase price for the trust units was determined by negotiation between us and Pengrowth Management and the underwriters.

     The underwriters have advised us that they propose to offer trust units directly to the public at the offering price on the cover of the prospectus and to selected dealers, who may include the underwriters, at such offering price less a selling concession not in excess of Cdn$                     per trust unit in Canada or US$                    in the United States. The underwriters may allow, and the selected dealers may re-allow, to other dealers a discount from the concession not in excess of Cdn$                     per trust unit in Canada or US$                    in the United States. After the offering, the underwriters may change the public offering price and other offering terms.

     The following table summarizes the underwriting discounts and commissions that we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise by the Canadian Underwriters and the US Underwriters of the underwriters’ over-allotment options.

		Cdn$		US$
		No Exercise	Full Exercise	No Exercise	Full Exercise
Per trust unit paid by us
	Total

     We estimate that the expenses of this offering, excluding underwriting discounts and commissions summarized in the table above, will be approximately $                     million. The underwriters have agreed to reimburse us for certain expenses incurred by us in connection with the offering.

     The U.S. Underwriters may engage in over-allotment, stabilizing transactions, syndicate covering transactions and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the trust units, in accordance with Regulation M of the Exchange Act.

•  Over-allotment involves sales by the underwriters of trust units in excess of the number of trust units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of trust units over-allotted by the underwriters is not greater than the number of trust units that they may purchase in the over-allotment option. In a naked short position, the number of trust units involved is greater than the number of trust units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing trust units in the open market.

•  Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•  Syndicate covering transactions involve purchases of the trust units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of trust units to close out the short position, the underwriters will consider, among other things, the price at which they may purchase trust units through the over-allotment option. If the underwriters sell more trust units than could be covered by the over-allotment option, which is called a naked short position, the position can only be closed out by buying trust units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the trust units in the open market after pricing that could adversely affect investors who purchase in the offering.

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•  Penalty bids permit RBC Capital Markets and Lehman Brothers Inc. to reclaim a selling concession from a syndicate member when the trust units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

     Under policy statements of certain securities commissions, the Canadian Underwriters may not, throughout the period of distribution, bid for or purchase trust units. Such restriction is subject to certain exceptions including: (1) a bid or purchase permitted under the by-laws and rules of the Toronto Stock Exchange relating to market stabilization and passive market making activities; and (2) a bid or purchase made for and on behalf of a customer where the order was not solicited during the period of the distribution, provided that the bid or purchase was not engaged in for the purpose of creating actual or apparent active trading in, or raising the price of the trust units. Under the first mentioned exemption, in connection with this offering, the Canadian Underwriters may over-allot or effect transactions which stabilize or maintain the market price of the trust units at a level other than that which might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time.

     These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our trust units or preventing or retarding a decline in the market price of our trust units. As a result, the price of the trust units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange, the Toronto Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

     Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the trust units. In addition, neither we nor any of the underwriters make a representation that the underwriters will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

     In connection with the offering, we and each of the officers and directors of Pengrowth Corporation and Pengrowth Management have agreed that we and they will not, subject to certain limited exceptions, directly or indirectly, offer, sell, pledge or otherwise dispose of any trust units or any securities convertible into or exchangeable or exercisable for trust units or enter into any swap or other derivative transaction with similar effect as a sale of trust units, for a period of 90 days from the date of this prospectus supplement without the prior written consent of RBC Dominion Securities Inc. and Lehman Brothers Inc. The restrictions in this paragraph do not apply to:

•  the sale of trust units to the underwriters in this offering, including trust units sold pursuant to the over-allotment option,

•  the sale or transfer of trust units to us by our directors or officers in connection with the exercise of a currently outstanding option, warrant or right, or

•  our issuance of options under any of our currently effective employee benefit plans, trust unit option or incentive plans or of trust units upon the exercise of a currently outstanding option, warrant or right or the conversion of a security outstanding on the date of the supplemental prospectus.

     RBC Dominion Securities Inc. and Lehman Brothers Inc., in their discretion, may release the trust units subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release the trust units from lock-up agreements, RBC Dominion Securities Inc. and Lehman Brothers Inc. will consider, among other factors, the unitholders’ reasons for requesting the release, the number of trust units for which the release is being requested, and market conditions at the time.

     Pursuant to the U.S. Underwriting Agreement and the Canadian Underwriting Agreement, we and Pengrowth Management have agreed to indemnify, under certain circumstances, the underwriters against liabilities relating to the offering, including liabilities under the United States Securities Act of 1933, as amended, and liabilities arising from breaches of the representations and warranties contained in the underwriting agreement, and to contribute, under certain circumstances, to payments that the underwriters may be required to make for these liabilities.

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     A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online, and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

     Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of this prospectus or the registration statement, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

     An affiliate of RBC Dominion Securities Inc. and RBC Dain Rauscher Inc. is a lender to us under our syndicated facility and the additional credit facilities obtained to finance the acquisition of the New B.C. Properties. This lender will receive a share of the repayment by us of amounts outstanding under the additional credit facilities from the net proceeds of this offering. Because we intend to use more than 10% of the net proceeds from the sale of the trust units to repay indebtedness owed by us to this affiliate under the additional credit facilities, the offering is being made in compliance with the requirements of Rule 2710(c)(8) of the Conduct Rules of the National Association of Securities Dealers, Inc. (“NASD”). However, pursuant to Rule 2720, the appointment of a qualified independent underwriter is not required in connection with this offering because a bona fide independent market (as defined in the NASD Conduct Rules) exists for the trust units. Because the NASD views the trust units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD Conduct Rules.

     No sales to accounts over which the underwriters exercise discretionary authority may be made without the prior written approval of the customer.

     Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us and our affiliates. They receive customary fees and commissions for these services.

     Pengrowth Trust has applied to list the trust units to be distributed under this prospectus on the Toronto Stock Exchange and the New York Stock Exchange. Listing will be subject to Pengrowth Trust fulfilling all of the listing requirements of such exchanges.

RELATIONSHIP BETWEEN PENGROWTH CORPORATION AND CERTAIN UNDERWRITERS

     Pengrowth Trust may be considered under Canadian securities legislation to be a connected issuer of RBC Dominion Securities Inc., RBC Dain Rauscher Inc., BMO Nesbitt Burns Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc., Scotia Capital Inc. and HSBC Securities (Canada) Inc., as they are subsidiaries of banks (the “Banks”) which are part of a syndicate of lenders to Pengrowth Corporation and to which Pengrowth Corporation is presently indebted. As of the date hereof, the amount drawn on the syndicated facility is $360 million, of which the Banks’ portion is $309 million. In addition, as interim financing for the acquisition of the New B.C. Properties, Pengrowth Corporation has also obtained an aggregate of $285 million in additional credit facilities from the one of the Banks (the “Bridge Lender”), of which RBC Dominion Securities Inc. and RBC Dain Rauscher Inc. are subsidiaries. A total of $260 million has been drawn on these additional credit facilities. In connection with obtaining the additional credit facilities, Pengrowth Corporation obtained a waiver from the lenders of its syndicated facility to simplify the administration of the respective facilities. The net proceeds of this offering will be paid by Pengrowth Trust to Pengrowth Corporation either to subscribe for additional royalty units of Pengrowth Corporation or as a loan; Pengrowth Corporation will, in turn, use such funds to repay a portion of these additional facilities to the Bridge Lender. Pengrowth Corporation is in compliance with terms of its credit facilities. The decision to distribute the trust units pursuant to this offering and the determination of the terms of distribution were made

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through negotiations among Pengrowth Management, Pengrowth Corporation, Pengrowth Trust and the underwriters. The Banks did not have any involvement in the decision to distribute the trust units pursuant to this offering or in the determination of the terms of the distribution; however, the Banks have been advised of the offering and the terms thereof. As a consequence of this issuance, each of RBC Dominion Securities Inc., RBC Dain Rauscher Inc., BMO Nesbitt Burns Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc., Scotia Capital Inc. and HSBC Securities (Canada) Inc. will receive its share of the underwriters’ fee. See “Use of Proceeds”.

     Mr. John Zaozirny, a director of Pengrowth Corporation, is the Vice-Chairman of Canaccord Capital Corporation, which will receive its share of the underwriters’ fee.

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DOCUMENTS INCORPORATED BY REFERENCE

     The following documents of Pengrowth Trust filed with securities commissions or similar authorities in Canada are incorporated by reference into this prospectus:

     (a) Renewal Annual Information Form dated May 17, 2002;

     (b) Management’s Discussion and Analysis for the year ended December 31, 2001, contained on pages 32 to 43, inclusive, of the 2001 Annual Report of Pengrowth Trust;

     (c) Comparative financial statements for the year ended December 31, 2001, together with the report of the auditors thereon, contained on pages 45 to 61, inclusive, of the 2001 Annual Report of Pengrowth Trust;

     (d) Comparative financial statements for the year ended December 31, 2000, together with the report of the auditors thereon, contained on pages 50 to 66, inclusive, of the 2000 Annual Report of Pengrowth Trust;

     (e) Information Circular — Proxy Statement dated March 15, 2002 for the Special and Annual Meeting of Trust unitholders held on April 23, 2002 (excluding Schedules A and C and those portions which, in accordance with National Instrument 44-101 — Short Form Prospectus Distributions, need not be incorporated by reference);

     (f) Management’s Discussion and Analysis for the six month period ended June 30, 2002, contained on pages 4 to 9, inclusive, of the Second Quarter Results June 30, 2002 of Pengrowth Energy Trust;

     (g) Comparative interim financial statements for the six month period ended June 30, 2002, contained on pages 12 to 18, inclusive, of the Second Quarter Results June 30, 2002 of Pengrowth Energy Trust; and

     (h) Material Change Report dated September 26, 2002, relating to the acquisition of the New B.C. Properties.

     Any comparative financial statements, interim financial statements, information circulars and material change reports (excluding confidential reports) filed by Pengrowth Trust with a securities commission or similar authority in Canada after the date of this prospectus and prior to the termination of the distribution, shall be deemed to be incorporated by reference into this prospectus.

     Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded, for purposes of this prospectus, to the extent that a statement contained herein or in any other subsequently filed document that also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omission to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it is made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

     Information has been incorporated by reference in this short form prospectus from documents filed with securities commissions or similar authorities in Canada.Copies of the documents incorporated herein by reference may be obtained on request without charge from the Corporate Secretary of Pengrowth Corporation, 700, 112 Fourth Avenue SW, Calgary, Alberta T2P 0H3 (telephone: (403) 233-0224). For the purpose of the Province of Québec, this simplified prospectus contains information to be completed by consulting the permanent information record. A copy of the permanent information record may be obtained from the Corporate Secretary of Pengrowth Corporation at the above-mentioned address and telephone number.

     All disclosure contained in the supplemented PREP prospectus that is not contained in this base PREP prospectus will be incorporated by reference into this base PREP prospectus as of the date of the supplemented PREP prospectus.

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AVAILABLE INFORMATION

     Pengrowth Trust has filed with the United States Securities and Exchange Commission (SEC) a Registration Statement on Form F-10 (together with all amendments and supplements thereto, the “Registration Statement”) under the United States Securities Act of 1933, as amended (the “U.S. Securities Act”), with respect to the trust units offered hereby. This prospectus, which forms part of the Registration Statement, does not contain all the information set forth in the Registration Statement, certain parts of which have been omitted in accordance with the rules and regulations of the SEC. For further information with respect to Pengrowth Trust, and the trust units offered hereby, reference is made to the Registration Statement and to the schedules and exhibits filed therewith. Statements contained in this prospectus as to the contents of certain documents are not necessarily complete and, in each instance, reference is made to the copy of the document filed as an exhibit to the Registration Statement. Each such statement is qualified in its entirety by such reference.

     Pengrowth Trust is subject to the informational requirements of the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”), and in accordance therewith files reports and other information with the SEC. Under the multi-jurisdictional disclosure system adopted by the United States, such reports and other information may be prepared in accordance with the disclosure requirements of Canada, which requirements are different than those of the United States. Pengrowth Trust is exempt from the rules under the Exchange Act prescribing the furnishing and content of proxy statements, and its officers, directors and principal shareholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act.

     Any information filed with the SEC can be inspected and copied at the public reference facilities maintained by the SEC at Room 5024, 450 Fifth Street, N.W., Washington, D.C. 20549. Information on the operation of the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330.

DOCUMENTS FILED AS PART OF THE U.S. REGISTRATION STATEMENT

     The following documents have been filed or incorporated by reference as part of the registration statement filed with the SEC: (i) the documents listed in this prospectus as incorporated by reference herein; (ii) form of underwriting agreement; (iii) comfort letter of KPMG LLP, Chartered Accountants, to the Canadian securities regulatory authorities; (iv) reports or information that must be made publicly available in Canada in connection with the transaction, pursuant to Canadian or provincial law; (v) consent of Gilbert Laustsen Jung Associates Ltd; (vi) consent of KPMG LLP, Chartered Accountants; (vii) awareness letter of KPMG LLP; (viii) consent of Bennett Jones LLP; (ix) consent of Fraser Milner Casgrain LLP; (x) consent of Carter, Ledyard & Milburn; (xi) amended and restated trust indenture dated April 23, 2002; (xii) amended and restated royalty indenture dated April 23, 2002; (xiii) amended and restated management agreement dated April 23, 2002; and (xiv) amended and restated unanimous shareholders agreement dated April 23, 2002. You can obtain copies of the documents incorporated herein by reference without charge from the Corporate Secretary of Pengrowth Trust, 700 Sun Life Plaza, East Tower, 112-4 Avenue S.W., Calgary, Alberta T2P 0H3, telephone (403) 233-0224.

AUDITORS, TRANSFER AGENT AND REGISTRAR

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

113

ELIGIBILITY FOR INVESTMENT

     In the opinion of Bennett Jones LLP and Fraser Milner Casgrain LLP, subject to the assumptions outlined under the heading “Certain Income Tax Considerations — Certain Canadian Federal Income Tax Considerations”, the trust units offered under this prospectus are qualified investments under theIncome Tax Act(Canada) for trusts governed by registered retirement savings plans, registered retirement income funds, registered education savings plans and deferred profit sharing plans.

     In the opinion of Bennett Jones LLP and Fraser Milner Casgrain LLP, subject to compliance with the prudent investment standards and general investment provisions of the following statutes (and, where applicable, the regulations thereunder) and, in certain cases, subject to the satisfaction of additional requirements relating to investment or lending policies, procedures or goals, and, in certain circumstances, the filing of such policies, procedures or goals, the trust units offered under this prospectus are not, at the date hereof, precluded as investments under or by the following statutes:

Insurance Companies Act(Canada)
Trust and Loan Companies Act(Canada)
Cooperative Credit Associations Act(Canada)
Pension Benefits Standards Act, 1985
  (Canada)
Pension Benefits Standards Act
  (British Columbia)
Financial Institutions Act(British Columbia)
Alberta Heritage Savings Trust Fund Act
  (Alberta)
Employment Pension Plans Act(Alberta)
Insurance Act(Alberta)
Loan and Trust Corporations Act(Alberta)
The Pension Benefits Act, 1992
  (Saskatchewan)
The Insurance Act(Manitoba)
The Pension Benefits Act(Manitoba) The Trustee Act(Manitoba)
Loan and Trust Corporations Act(Ontario)
Pension Benefits Act(Ontario)
Trustee Act(Ontario)
an Act respecting insurance(Québec)
  (in respect of an issuer, as defined therein,
  incorporated under the laws of the Province
  of Québec, other than a guarantee fund)
an Act respecting trust companies and savings
  companies(Québec)(for a trust company
  investing its own funds and deposits it
  receives or a savings company, as defined
  therein, which invests its own funds)
Supplemental Pension Plans Act(Québec)

LEGAL MATTERS

     Certain legal matters relating to this offering of trust units will be passed upon by Bennett Jones LLP, Calgary, Alberta, and Carter, Ledyard & Milburn, New York, New York, on behalf of Pengrowth Trust and by Fraser Milner Casgrain LLP, Calgary, Alberta, and Vinson & Elkins L.L.P., Houston, Texas, on behalf of the underwriters. As at the date hereof, the partners and associates, as a group of each of Bennett Jones LLP, Carter, Ledyard & Milburn, Fraser Milner Casgrain LLP and Vinson & Elkins L.L.P. beneficially own, directly or indirectly, less than 1% of our outstanding trust units.

114

INDEX TO FINANCIAL STATEMENTS

Compilation Report of KPMG LLP and Unaudited Pro Forma Consolidated Financial Statements of Pengrowth Energy Trust	F-2
Unaudited Interim Consolidated Financial Statements of Pengrowth Energy Trust for the Six Months Ended June 30, 2002	F-10
Reconciliation of Interim Consolidated Financial Statements of Pengrowth Energy Trust for the Six Months Ended June 30, 2002 to United States Generally Accepted Accounting Principles	F-19
Auditors’ Report of KPMG LLP and Consolidated Financial Statements of Pengrowth Energy Trust for the Years Ended December 31, 2001 and December 31, 2000	F-24
SFAS No. 69 Supplemental Reserve Information	F-44
Auditors’ Report of KPMG LLP and Schedule of Revenue and Expenses associated with the northern British Columbia oil and natural gas assets acquired from the Calpine Canada Natural Gas Partnership by Pengrowth Corporation	F-50

F-1

COMPILATION REPORT OF KPMG LLP AND UNAUDITED

PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF

PENGROWTH ENERGY TRUST

F-2

COMPILATION REPORT

To: The Board of Directors of Pengrowth Corporation, as Administrator of

Pengrowth Energy Trust

     We have reviewed, as to compilation only, the accompanying unaudited pro forma consolidated balance sheet of Pengrowth Energy Trust as at June 30, 2002 and the unaudited pro forma combined statement of income and distributable income for the six month period ended June 30, 2002 and the year ended December 31, 2001. These pro forma consolidated financial statements have been prepared for inclusion in the short-form prospectus dated October l, 2002, relating to the issue of trust units by Pengrowth Energy Trust. In our opinion, the unaudited pro forma consolidated balance sheet and the unaudited pro forma combined statement of income and distributable income have been properly compiled to give effect to the assumptions and adjustments described in the notes thereto.

Chartered Accountants

Calgary, Canada

October l, 2002

COMMENTS FOR UNITED STATES READERS ON DIFFERENCES BETWEEN CANADIAN AND UNITED STATES REPORTING STANDARDS

     The above report, provided solely pursuant to Canadian requirements, is expressed in accordance with standards of reporting generally accepted in Canada. Such standards contemplate the expression of an opinion with respect to the compilation of pro forma financial statements. United States standards do not provide for the expression of an opinion on the compilation of pro forma financial statements. To report in conformity with United States standards on the reasonableness of the pro forma adjustments and their application to the pro forma financial statements requires an examination or review substantially greater in scope than the review we have conducted. Consequently, we are unable to express any opinion in accordance with standards of reporting generally accepted in the United States with respect to the compilation of the accompanying unaudited pro forma financial information.

Chartered Accountants

Calgary, Canada

October l, 2002

F-3

PENGROWTH ENERGY TRUST

PRO FORMA CONSOLIDATED BALANCE SHEET

		As at June 30, 2002
		Pengrowth				Pro Forma
		Energy Trust		Adjustments		Consolidated
		(Note 2)
		(Stated in thousands of dollars)
		(Unaudited)
ASSETS
CURRENT ASSETS
	Marketable securities	$	2,689	$		$	2,689
	Accounts receivable		32,742				32,742
	Inventory		1,258				1,258
			36,689				36,689
REMEDIATION TRUST FUND			6,808				6,808
PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS			1,145,197		348,700		1,493,897
		$	1,188,694	$	348,700	$	1,537,394
LIABILITIES AND UNITHOLDERS’ EQUITY
CURRENT LIABILITIES
	Bank indebtedness	$	3,452	$		$	3,452
	Accounts payable and accrued liabilities		29,403				29,403
	Distributions payable to unitholders		31,046				31,046
	Due to Pengrowth Management Limited		554				554
			64,455				64,455
LONG-TERM DEBT			219,123		114,450		333,573
FUTURE SITE RESTORATION COSTS			37,903				37,903
TRUST UNITHOLDERS’ EQUITY			867,213		234,250		1,101,463
		$	1,188,694	$	348,700	$	1,537,394

See accompanying notes to pro forma consolidated financial statements.

F-4

PENGROWTH ENERGY TRUST

PRO FORMA COMBINED STATEMENT OF INCOME AND DISTRIBUTABLE INCOME

		For the Six Months Ended June 30, 2002
		Pengrowth								Pro Forma
		Energy Trust			New B.C. Properties			Adjustments		Combined
								(Note 2)
		(Stated in thousands of dollars)
		(Unaudited)
REVENUES
	Oil and gas sales	$	203,178		$	81,474				$	284,652
	Processing and other income		3,036								3,036
	Crown royalties		(24,383	)		(17,520	)				(41,903	)
	Alberta Royalty Tax Credit		250								250
	Freehold royalties and mineral taxes		(3,306	)		(159	)				(3,465	)
			178,775			63,795					242,570
	Interest and other income		(525	)							(525	)
NET REVENUE			178,250			63,795					242,045
EXPENSES
	Operating		58,057			10,561					68,618
	Amortization of injectants for miscible floods		23,454								23,454
	Interest		6,165						1,961		8,126
	General and administrative		5,219								5,219
	Management fee		3,140						1,331		4,471
	Capital taxes		281						193		474
	Depletion and depreciation		62,113						28,665		90,778
	Future site restoration		5,759						2,192		7,951
			164,188			10,561					209,091
Income before the following			14,062			53,234					32,954
Royalty income attributable to royalty units other than those held by Pengrowth Energy Trust			16								16
Net Income			14,046			53,234					32,938
Add: Depletion, depreciation and future site restoration			67,872						30,857		98,729
Alberta Royalty Credit received during period			500								500
Deduct: Alberta Royalty Credit accrued for period			(250	)							(250	)
	Reclamation expenses and Remediation Trust Fund		(909	)							(909	)
Distributable income		$	81,259		$	53,234				$	131,008
Net income per unit — Basic		$	0.168							$	0.328
Distributable income per unit based on weighted average units outstanding		$	0.974							$	1.303

See accompanying notes to pro forma consolidated financial statements.

F-5

PENGROWTH ENERGY TRUST

PRO FORMA COMBINED STATEMENT OF INCOME AND DISTRIBUTABLE INCOME

		For the Year Ended December 31, 2001
		Pengrowth						Interest in
		Energy			New B.C.			Sable Offshore					Pro Forma
		Trust			Properties			Energy Project			Adjustments		Combined
								(Note 3)			(Note 3)
		(Stated in thousands of dollars)
		(Unaudited)
REVENUES
	Oil and gas sales	$	469,929		$	191,253		$	56,360				$	717,542
	Processing and other income		7,071											7,071
	Crown royalties		(65,703	)		(42,957	)		(549	)				(109,209	)
	Alberta Royalty Tax Credit		500											500
	Freehold royalties and mineral taxes		(6,757	)		(636	)							(7,393	)
			405,040			147,660			55,811					608,511
	Interest and other income		1,348											1,348
NET REVENUE			406,388			147,660			55,811					609,859
EXPENSES
	Operating		104,943			21,080			8,754					134,777
	Amortization of injectants for miscible floods		47,448											47,448
	Interest		18,806									7,574		26,380
	General and administrative		7,467											7,467
	Management fee		7,120									4,341		11,461
	Capital taxes		2,659									458		3,117
	Depletion and depreciation		124,208									55,769		179,977
	Future site restoration		8,529									3,534		12,063
			321,180			21,080			8,754					422,690
Income before the following			85,208			126,580			47,057					187,169
Royalty income attributable to royalty units other than those held by Pengrowth Energy Trust			58											58
Net Income			85,150			126,580			47,057					187,111
	Add: Depletion, depreciation and future site restoration		132,737									59,303		192,040
	Alberta Royalty Credit received during period		517											517
	Deduct: Alberta Royalty Credit accrued for period		(500	)										(500	)
	Reclamation expenses and Remediation Trust Fund		(2,117	)										(2,117	)
Distributable income		$	215,787		$	126,580		$	47,057				$	377,051
Net income per unit — Basic		$	1.201										$	2.125
Distributable income per unit based on weighted average units outstanding		$	3.043										$	4.283

See accompanying notes to pro forma consolidated financial statements.

F-6

PENGROWTH ENERGY TRUST

NOTES TO THE PRO FORMA FINANCIAL STATEMENTS

For the six months ended June 30, 2002 and the year ended December 31, 2001:

1.     Basis of Presentation:

     For purposes of these financial statements “Pengrowth” refers to both Pengrowth Energy Trust and Pengrowth Corporation. On October 1, 2002 Pengrowth acquired substantially all of the oil and natural gas assets in northern British Columbia held by Calpine Canada Natural Gas Partnership (the “B.C. Asset Package”) for $387.5 million prior to adjustments. On October 4, 2002 Pengrowth sold a portion of the B.C. Asset Package to Progress Energy Ltd. for $25.4 million before adjustments. The oil and gas assets acquired by Pengrowth net of the assets sold to Progress Energy Ltd. are referred to herein as the “New B.C. Properties”.

     The accompanying unaudited pro forma consolidated financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada.

     The unaudited pro forma consolidated balance sheet as at June 30, 2002 has been prepared from the unaudited consolidated balance sheet of Pengrowth. The unaudited pro forma combined statement of income and distributable income for the six months ended June 30, 2002 has been prepared from the unaudited statement of income and distributable income for Pengrowth for the six months ended June 30, 2002, and the unaudited schedule of revenue and expenses for the New B.C. Properties for the six months ended June 30, 2002.

     The unaudited pro forma combined statement of income and distributable income for the year ended December 31, 2001 has been prepared from the audited statement of income and distributable income for Pengrowth for the year ended December 31, 2001, the audited schedule of revenue and expenses for the New B.C. Properties for the year ended December 31, 2001, and the unaudited interim net revenues and expenses for the period January 1, 2001 to June 14, 2001 from the interest in the Sable Offshore Energy Project that Pengrowth acquired.

     These pro forma financial statements are not necessarily indicative either of the results that actually would have occurred if the events reflected herein had taken place on the dates indicated or of the results which may be obtained in the future.

     It is the recommendation of management that this financial information should be read in conjunction with the financial statements and notes thereto of Pengrowth as at and for the six months ended June 30, 2002, and for the year ended December 31, 2001, and the Schedule of Revenue and Expenses associated with the northern British Columbia oil and natural gas assets acquired from the Calpine Canada Natural Gas Partnership by Pengrowth Corporation.

2.     Pro Forma Transaction and Assumptions (June 30, 2002):

     The pro forma consolidated balance sheet gives effect to the following transactions and adjustments as if they occurred on June 30, 2002:

     (a) The acquisition of the B.C. Asset Package from Calpine Canada Natural Gas Partnership for consideration of $387.5 million adjusted for purchase adjustments of approximately $16.5 million and estimated acquisition costs of $3.1 million, with consideration consisting of cash and the tendering of Calpine Corporation debt securities purchased by Pengrowth.

     (b) The disposition of a portion of the B.C. Asset Package to Progress Energy Ltd. for total cash consideration of $25.4 million.

     (c) The issuance of 17,123,287 trust units at a price of $14.60 per trust unit, for an aggregate consideration of $250 million, less the underwriters’ fee of $13.75 million and expenses of the issue estimated to be $2.0 million.

F-7

PENGROWTH ENERGY TRUST

NOTES TO THE PRO FORMA FINANCIAL STATEMENTS — (Continued)

     The pro forma combined statement of income and distributable income for the six month period ended June 30, 2002 gives effect to the transactions and adjustments referred to above in this Note 2 effective January 1, 2002 and the following:

     (a) In accordance with the management agreement, management fees have been calculated at the rate of 2.5% on incremental net revenue and increase by approximately $1,331,000.

     (b)     Capital taxes have been increased by $193,000 to reflect the impact of the increase in debt on federal large corporations tax, and an increase in B.C. capital tax as a result of the acquisition of the New B.C. Properties.

     (c) A provision for depletion and depreciation and future site restoration based on combining reserves, production and cost of the property, plant and equipment under the full cost method of accounting for oil and gas properties.

     (d) Additional interest expense of $1,961,000 from additional debt of $114,450,000.

3. Pro Forma Transaction and Assumptions (December 31, 2001):

     The pro forma combined statement of income and distributable income for the year ended December 31, 2001 gives effect to the transactions and adjustments referred to in the first paragraph of Note 2 effective January 1, 2001 and the following:

     (a) The acquisition of Pengrowth’s interest in the Sable Offshore Energy Project as if it had occurred on January 1, 2001 instead of the actual closing date of June 15, 2001.

     (b) In accordance with the management agreement, management fees have been calculated at the rate of 2.5% on incremental net revenue and increase by approximately $4,341,000.

     (c) Capital taxes have been increased by $458,000 to reflect the impact of the increase in long-term debt on federal large corporations tax, and an increase in B.C. capital tax as a result of the acquisition of the New B.C. Properties.

     (d) A provision for depletion and depreciation and future site restoration based on combining reserves, production and cost of the property, plant and equipment under the full cost method of accounting for oil and gas properties.

     (e) Additional interest expense of $7,574,000 from additional average long-term debt of $137 million for the period.

4. Application of United States Generally Accepted Accounting Principles:

     The application of United States generally accepted accounting principles (“US GAAP”) would have the following effects on the pro forma combined statement of operations:

		Pro Forma ($000’s)
		December 31, 2001		June 30, 2002
Net income per pro forma combined statement of income and distributable income		$	187,111	$	32,938
Net income adjustments under US GAAP (1)			28,822		14,045
Pro forma net income under US GAAP		$	215,933	$	46,983
Net income per unit:
	Basic	$	2.45	$	0.47
	Diluted	$	2.45	$	0.47

(1) These adjustments reflect those made in the June 30, 2002 US GAAP reconciliation adjusted for the pro forma depletion rate.

F-8

PENGROWTH ENERGY TRUST

NOTES TO THE PRO FORMA FINANCIAL STATEMENTS — (Continued)

     The application of United States generally accepted accounting principles (“US GAAP”) would have the following effect on the pro forma consolidated balance sheet as at June 30, 2002:

		As at June 30, 2002
		Pro Forma		Increase			Pro Forma
		Cdn GAAP		(Decrease)			US GAAP
		(Stated in thousands of Canadian
		Dollars ($))
Assets:
	Marketable securities	$	2,689	$	634		$	3,323
	Capital assets		1,493,897		(321,371	)		1,172,526
	Unrealized hedging gain		—		313			313
				$	(320,424	)
Liabilities:
	Accounts payable and accrued liabilities	$	29,403	$	712		$	30,115
	Provision for abandonment costs		37,903		(37,903	)		—
	Unrealized hedging loss		—		7,903			7,903
Unitholders’ equity:
	Other comprehensive income		—		(6,956	)		(6,956	)
	Trust Unitholders’ Equity		1,101,463		(284,180	)		817,283
				$	(320,424	)

F-9

UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

OF PENGROWTH ENERGY TRUST

FOR THE SIX MONTHS ENDED JUNE 30, 2002

F-10

PENGROWTH ENERGY TRUST

CONSOLIDATED BALANCE SHEETS

		As at		As at
		June 30		December 31
		2002		2001
		(Stated in
		thousands of dollars)
		(unaudited)		(audited)
ASSETS
CURRENT ASSETS
	Cash and term deposits	$	—	$	3,797
	Marketable securities (Note 6)		2,689		—
	Accounts receivable		32,742		27,859
	Inventory		1,258		2,687
			36,689		34,343
REMEDIATION TRUST FUND			6,808		6,470
PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS			1,145,197		1,208,526
		$	1,188,694	$	1,249,339
LIABILITIES AND UNITHOLDERS’ EQUITY
CURRENT LIABILITIES
	Bank indebtedness	$	3,452	$	—
	Accounts payable and accrued liabilities		29,403		31,359
	Distributions payable to unitholders		31,046		22,207
	Due to Pengrowth Management Limited		554		523
			64,455		54,089
LONG-TERM DEBT (Note 3)			219,123		345,456
FUTURE SITE RESTORATION COSTS			37,903		32,591
TRUST UNITHOLDERS’ EQUITY (Note 4)			867,213		817,203
		$	1,188,694	$	1,249,339

See accompanying notes to the consolidated financial statements.

F-11

PENGROWTH ENERGY TRUST

CONSOLIDATED STATEMENTS OF INCOME AND DISTRIBUTABLE INCOME

		Three months ended						Six months ended
		June 30						June 30
		2002			2001			2002			2001
		(Stated in thousands of dollars)
		(Unaudited)
REVENUES
	Oil and gas sales	$	111,544		$	121,043		$	203,178		$	264,004
	Processing and other income		1,349			1,682			3,036			3,359
	Crown royalties		(12,415	)		(14,885	)		(24,383	)		(41,915	)
	Alberta Royalty Tax Credit		125			125			250			250
	Freehold royalties and mineral taxes		(1,895	)		(1,756	)		(3,306	)		(4,275	)
			98,708			106,209			178,775			221,423
	Interest and other income		(952	)		904			(525	)		1,063
NET REVENUE			97,756			107,113			178,250			222,486
EXPENSES
	Operating		30,532			22,157			58,057			43,790
	Amortization of injectants for miscible floods		11,276			11,833			23,454			22,518
	Interest		3,127			5,090			6,165			9,929
	General and administrative		2,989			1,450			5,219			3,627
	Management fee		1,744			1,885			3,140			4,714
	Capital taxes		(122	)		1,333			281			1,812
	Depletion and depreciation		31,666			27,938			62,113			56,748
	Future site restoration		2,930			1,565			5,759			3,556
			84,142			73,251			164,188			146,694
INCOME BEFORE THE FOLLOWING			13,614			33,862			14,062			75,792
ROYALTY INCOME ATTRIBUTABLE TO ROYALTY UNITS OTHER THAN THOSE HELD BY PENGROWTH ENERGY TRUST			10			18			16			40
NET INCOME			13,604			33,844			14,046			75,752
Add:   Depletion, depreciation and future site restoration			34,596			29,503			67,872			60,304
Alberta Royalty Credit received during period			500			517			500			517
Deduct: Alberta Royalty Credit accrued for period			(125	)		(125	)		(250	)		(250	)
Reclamation expenses and Remediation Trust Fund			(434	)		(344	)		(909	)		(857	)
DISTRIBUTABLE INCOME		$	48,141		$	63,395		$	81,259		$	135,466
NET INCOME PER UNIT (Note 4) Basic		$	0.161		$	0.500		$	0.168		$	1.150
Diluted		$	0.161		$	0.494		$	0.168		$	1.141
DISTRIBUTABLE INCOME PER UNIT (Note 4)
	Based on weighted average units outstanding	$	0.569		$	0.936		$	0.974		$	2.057
	Based on actual distributions paid or declared	$	0.540		$	0.830		$	0.950		$	1.970

See accompanying notes to the consolidated financial statements.

F-12

PENGROWTH ENERGY TRUST

CONSOLIDATED STATEMENTS OF CASH FLOW

		Three months ended June 30						Six months ended June 30
		2002			2001			2002			2001
		(Stated in thousands of dollars)
		(unaudited)
CASH PROVIDED BY (USED FOR):
OPERATING
	Net income	$	13,604		$	33,844		$	14,046		$	75,752
	Items not involving cash
	Depletion, depreciation and future site restoration		34,596			29,503			67,872			60,304
	Amortization of injectants		11,276			11,833			23,454			22,518
	Purchase of injectants		(4,110	)		(22,027	)		(7,446	)		(40,114	)
	Expenditures on remediation		(223	)		(116	)		(447	)		(416	)
Funds generated from operations			55,143			53,037			97,479			118,044
	Distributions		(40,340	)		(67,267	)		(72,420	)		(142,115	)
	Changes in non-cash operating working capital (Note 5)		1,844			(9,718	)		(8,898	)		(17,845	)
			16,647			(23,948	)		16,161			(41,916	)
FINANCING
	Change in long-term debt		(119,962	)		27,847			(126,333	)		87,747
	Proceeds from issue of trust units		116,363			215,774			117,223			219,312
			(3,599	)		243,621			(9,110	)		307,059
INVESTING
	Deposit on acquisition		—			(3,000	)		—			(3,000	)
	Expenditures on property acquisitions		(33,955	)		(215,552	)		(33,955	)		(249,709	)
	Expenditures on property, plant and equipment		(14,042	)		(19,849	)		(25,432	)		(33,765	)
	Proceeds on property dispositions		39,641			22,046			44,595			22,046
	Change in Remediation Trust Fund		(150	)		(166	)		(338	)		(377	)
	Marketable securities		(1,023	)		—			(2,689	)		—
	Change in non-cash investing working capital (Note 5)		(4,434	)		(2,416	)		3,519			(2,464	)
			(13,963	)		(218,937	)		(14,300	)		(267,269	)
INCREASE (DECREASE) IN CASH			(915	)		736			(7,249	)		(2,126	)
CASH AND TERM DEPOSITS (BANK INDEBTEDNESS) AT BEGINNING OF PERIOD			(2,537	)		1,671			3,797			4,533
CASH AND TERM DEPOSITS (BANK INDEBTEDNESS) AT END OF PERIOD		$	(3,452	)	$	2,407		$	(3,452	)	$	2,407

See accompanying notes to the consolidated financial statements.

F-13

PENGROWTH ENERGY TRUST

CONSOLIDATED STATEMENTS OF TRUST UNITHOLDERS’ EQUITY

	Three months ended June 30						Six months ended June 30
	2002			2001			2002			2001
	(Stated in thousands of dollars)
	(unaudited)
Unitholders’ equity at beginning of period	$	785,387		$	615,340		$	817,203		$	641,965
Units issued, net of issue costs		116,363			215,774			117,223			219,312
Net income for period		13,604			33,844			14,046			75,752
Distributable income		(48,141	)		(63,395	)		(81,259	)		(135,466	)
TRUST UNITHOLDERS’ EQUITY AT END OF PERIOD	$	867,213		$	801,563		$	867,213		$	801,563

F-14

PENGROWTH ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

June 30, 2002

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

1.  Significant Accounting Policy

     The interim consolidated financial statements of Pengrowth Energy Trust and Pengrowth Corporation (collectively referred to as “Pengrowth”) have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2001 with the exception of the change in accounting policy noted below. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Pengrowth’s annual report for the year ended December 31, 2001.

2.  Change in Accounting Policy

     Effective January 1, 2002, Pengrowth adopted the new standard on accounting for options or similar unit based compensation. Pengrowth prospectively adopted the new standard. For options or similar instruments granted to non-employees, an amount equal to the grant date fair value of the instrument will be recorded as a charge to earnings over the vesting period, if any. The new standard also requires recognition of compensation cost with respect to Stock Appreciation Rights granted to employees. No compensation cost results from application of the above provisions for the three months ended June 30, 2002 or for the year ended December 31, 2001.

     For options granted to employees of Pengrowth, the standard provides that Pengrowth may elect not to use this fair value method but to disclose the impact of the fair value method on a pro forma basis. Had compensation cost for options granted to employees been calculated based on the fair value method, an amount of $675,000 would have been recorded as compensation expense for the three months ended June 30, 2002. Pengrowth’s net income and net income per unit for the three months and six months ended June 30, 2002 would have been $12,929,000 ($0.153 per unit) and $13,371,000 ($0.160 per unit) respectively.

     The weighted average fair market value of options granted during the three months ended June 30, 2002 was $0.92 per option based on the date of grant using a modified Black-Scholes option pricing model with the following assumptions: risk-free interest rate of 4.5 percent, dividend yield of 13 percent, expected volatility of 29 percent, normalized dilution of 3 percent, liquidity discount of 10 percent and expected life of five years.

3.  Long-Term Debt

     Pengrowth has a $425 million revolving credit facility syndicated among nine financial institutions with an extendible 364 day revolving period and a three year amortization term period. In addition, it has a $35 million demand operating line of credit. The two facilities are currently reduced by outstanding letters of credit in the amount of approximately $34 million. Interest payable on amounts drawn is at the prevailing bankers’ acceptance rates plus stamping fees, lenders’ prime lending rates, or U.S. libor rates plus applicable margins, depending on the form of borrowing by the Corporation. The margins and stamping fees vary from 0.25 percent to 1.40 percent depending on financial statement ratios and the form of borrowing.

     The revolving credit facility will revolve until June 22, 2003, whereupon it is expected to be renewed for a further 364 days, subject to satisfactory review by the lenders. If the revolving facility is not renewed, it will convert into a term facility with amounts outstanding under the facility repayable in 12 equal quarterly installments. Pengrowth can post, at its option, security suitable to the banks in lieu of the first year’s

F-15

PENGROWTH ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

June 30, 2002

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

payments. In such an instance, no principal payment would be made to the banks for one year following the date of non-renewal.

4.     Trust Units

     The authorized capital of Pengrowth is 500,000,000 trust units.

	June 30, 2002					December 31, 2001
	Number of					Number of
Trust Units Issued	units		Amount			units		Amount
Balance, beginning of period		82,240,069	$	1,280,599			63,852,198	$	974,724
Issued for cash		8,000,000		123,200			17,622,500		311,974
Less: issue expenses		—		(7,466	)		—		(18,727	)
Issued for cash on exercise of stock options		47,100		623			628,828		10,060
Issued for cash under Distribution Reinvestment (“DRIP”) Plan		60,109		866			136,543		2,568
Balance, end of period		90,347,278	$	1,397,822			82,240,069	$	1,280,599

     The per unit amounts for net income and distributable income are based on weighted average units outstanding for the period. The weighted average units outstanding for the three months ended June 30, 2002 were 84,612,513 units and for the six months ended June 30, 2002 were 83,445,980 units (three months ended June 30, 2001 — 67,727,300 units, six months ended June 30, 2001 — 65,868,024 units). In computing diluted net income per unit, 34,995 units were added to the weighted average number of units outstanding during the quarter ended June 30, 2002 (June 30, 2001 — 356,387 units) and 29,608 units were added for the six months ended June 30, 2002 (six months ended June 30, 2001 — 358,670 units) for the dilutive effect of employee stock options. The per unit amount of distributions paid or declared reflect actual distributions paid or declared based on units outstanding at the time.

     Trust Unit Option Plan

     As at June 30, 2002, options to purchase 4,156,451 trust units were outstanding (December 31, 2001 — 3,106,635) that expire at various dates to June 28, 2009.

	June 30, 2002					December 31, 2001
				Weighted					Weighted
	Number of			Average		Number of			Average
Trust Unit Options	options			Exercise Price		options			Exercise Price
Outstanding at beginning of period		3,106,635		$	17.78		2,893,554		$	17.45
Granted		1,367,303			14.14		905,979			17.66
Exercised		(47,100	)		13.24		(628,828	)		16.00
Cancelled		(270,387	)		17.93		(64,070	)		18.98
Outstanding at period-end		4,156,451			16.62		3,106,635			17.78
Exercisable at period-end		2,736,158			17.15		2,238,406			17.69

F-16

PENGROWTH ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

June 30, 2002

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

     Amendments to the trust unit option plan were approved by trust unitholders at the annual meeting of Pengrowth unitholders on April 23, 2002. The maximum number of units which may be reserved for option grants has been increased from 7 million to 10 million, provided that the number of options granted does not exceed 10 percent of issued and outstanding trust units. The expiry date for all issued and unexercised options, and any options subsequently granted under the plan, has been increased from five years to seven years.

5.     Change in Non-Cash Operating Working Capital

	Three months ended						Six months ended
	June 30			June 30			June 30			June 30
	2002			2001			2002			2001
Accounts receivable	$	(1,523	)	$	4,093		$	(4,883	)	$	(936	)
Inventory		(821	)		5,034			1,429			1,243
Accounts payable and accrued liabilities		3,975			(18,587	)		(5,475	)		(17,755	)
Due to Pengrowth Management Limited		213			(258	)		31			(397	)
	$	1,844		$	(9,718	)	$	(8,898	)	$	(17,845	)

          Change in Non-Cash Investing Working Capital

	Three months ended						Six months ended
	June 30			June 30			June 30		June 30
	2002			2001			2002		2001
Accounts payable for capital accruals	$	(414	)	$	1,764		$	3,519	$	1,716
Note receivable on disposition of properties		—			(4,180	)		—		(4,180	)
Deposit on disposition of properties		(4,020	)		—			—		—
	$	(4,434	)	$	(2,416	)	$	3,519	$	(2,464	)

     The cash payments made for taxes for the quarter ending June 30, 2002 were $435,000 (June 30, 2001 — $1,399,000) and for the six months ended June 30, 2002 were $790,000 (six months ended June 30, 2001 — $1,829,000). Cash payments for interest for the quarter ending June 30, 2002 were $3,134,000 (June 30, 2001 — $6,178,000) and for the six months ended June 30, 2002 were $6,538,000 (six months ended June 30, 2001 — $15,180,000).

6.     Financial Instruments

     Interest Rate Risk

     As at June 30, 2002, Pengrowth had entered into interest rate swaps on $125 million of its long term debt for periods of three years ending November 30, 2004 ($75 million), December 31, 2004 ($25 million) and March 4, 2005 ($25 million) at an average interest rate of 4.09% (before stamping fees).

     The estimated fair value of the interest rate swaps has been determined based on the amount that Pengrowth would receive or pay to terminate the contracts at period end. At June 30, 2002, the amount that Pengrowth would receive to terminate the interest rate swaps is $313,000.

F-17

PENGROWTH ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

June 30, 2002

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

     Forward and Futures Contracts

     Pengrowth has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates, however gains or losses on the contracts are offset by changes in the value of Pengrowth’s production.

     As at June 30, 2002, Pengrowth had fixed the price applicable to future production as follows:

Financial Swap Contracts

	Crude Oil				Natural Gas
	Volume		Price		Volume
	(bbl/d)		C$/bbl		(MMbtu/d)		Fixed Price
2002		4,000	$	36.12		7,000	$	3.90 US/MMbtu
2003		—		—		7,000	$	3.90 US/MMbtu
		—		—		5,000	$	7.05 Cdn/MMbtu
2004		—		—		7,000	$	3.90 US/MMbtu
		—		—		5,000	$	6.90 Cdn/MMbtu

     As well, Pengrowth has natural gas fixed price sales contracts which fixed the price on 8,720 mcf/d until October 31, 2002 at a price of $2.99 Cdn/mcf.

     The estimated fair value of the crude oil financial swap contracts and the natural gas fixed price sales contracts have been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at period-end. At June 30, 2002 the amount Pengrowth would pay to terminate the crude oil and natural gas contracts would be $2,923,000 and $5,720,000, respectively.

     Fair Value of Financial Instruments

     The carrying value of financial instruments included in the balance sheet, other than bank debt, remediation trust fund and marketable securities, approximate their fair value due to their short maturity. The fair value of the marketable securities at June 30, 2002, was $3,323,000. The fair value of the Remediation Trust Fund was $6,821,000 (December 31, 2001 — $6,473,000).

F-18

RECONCILIATION OF INTERIM CONSOLIDATED FINANCIAL STATEMENTS

OF PENGROWTH ENERGY TRUST

FOR THE SIX MONTHS ENDED JUNE 30, 2002

TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

F-19

PENGROWTH ENERGY TRUST

RECONCILIATION OF INTERIM CONSOLIDATED FINANCIAL STATEMENTS

OF PENGROWTH ENERGY TRUST

FOR THE SIX MONTHS ENDED JUNE 30, 2002

TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

     The financial statements included in Pengrowth Energy Trust’s 2001 Annual Report have been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) which in most respects conforms to generally accepted accounting principles in the United States (“U.S. GAAP”).

     The significant differences between those principles as they apply to Pengrowth Energy Trust (“Pengrowth”), are as follows:

     (a) As required annually under U.S. GAAP, the carrying value of oil and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at 10 percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. Under Canadian GAAP, this “ceiling test” is calculated without application of a discount factor. At December 31, 1998 and 1997 the application of the full cost ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $328.6 million and $49.8 million, respectively. At June 30, 2002 and December 31, 2001, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs. A ceiling test has not been performed for any interim period prior to June 30, 2002.

     Where the amount of a ceiling test writedown under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion, depreciation, and amortization will differ in subsequent years.

     (b) Under U.S. GAAP, the provision for abandonment costs is recorded as a reduction of capital assets.

     (c) Under U.S. GAAP, interest and other income would not be included as a component of Net Revenue.

     (d) APB 25 requires recognition of compensation cost with respect to Stock Appreciation Rights granted to employees. No compensation cost results from application of the above provisions for the three or six months ended June 30, 2002. Application of provisions of APB 25 resulted in a reduction of compensation cost of $525,000 for the three months ended June 30, 2001 (increase in compensation cost of $180,000 for the six months ended June 30, 2001) for U.S. GAAP purposes.

     (e) Marketable securities held by Pengrowth are classified as available-for-sale in accordance with definitions of SFAS 115. Under provisions of this Statement, available-for-sale securities are reported at the fair value, with unrealized holding gains and losses included in comprehensive income and reported as a separate component of unitholders’ equity until realized.

     (f) SFAS 130 requires the reporting of comprehensive income in addition to net earnings. Comprehensive income includes net income plus other comprehensive income; specifically, all changes in equity of an entity during a period arising from non-owner sources.

     (g) Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), is effective for all fiscal years beginning after June 15, 2000. Pengrowth implemented the standards set out in SFAS 133 for the fiscal year commencing January 1, 2001, with no restatement of prior periods. SFAS 133 establishes new accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity’s approach to managing risk.

F-20

     On initial adoption of SFAS No. 133 on January 1, 2001, additional liabilities of $2.1 million were recorded for U.S. GAAP purposes to reflect the fair value of derivatives designated as cash flow hedges. A charge of $2.1 million relating to the fair value of these hedges was recognized in other comprehensive income as the cumulative effect of the initial adoption of SFAS No. 133.

     At June 30, 2002, $313,000 has been recorded as an asset in respect of the fair value of interest rate swaps outstanding at period end with a corresponding increase in other comprehensive income for the six months ended June 30, 2002. For the three months ended June 30, 2002, a decrease of $2,204,000 in other comprehensive income has been recorded. No interest rate swaps were outstanding at June 30, 2001. These amounts will be amortized against interest expense over the remaining terms of the related hedges. Also at June 30, 2002, a liability of $7,903,000 (June 30, 2001 — $269,000) has been recorded in respect of the fair value of crude oil and natural gas hedges outstanding at period end with a corresponding decrease in other comprehensive income for the six months ended June 30, 2002 and 2001. For the three months ended June 30, 2002, a decrease in comprehensive income of $5,346,000 has been recorded with respect to these hedges. An increase in other comprehensive income of $1,805,000 has been recorded for the three months ended June 30, 2001.

     At June 30, 2002, $712,000 has been recorded as a liability with respect to the ineffective portion of crude oil and natural gas hedges outstanding at period end and the fair value of derivatives which do not qualify as hedges, with a corresponding decrease to net income for the six months ended June 30, 2002 (June 30, 2001 — nil). For the three months ended June 30, 2002 an increase in net income of $409,000 has been recorded in respect to the ineffective portion of these crude oil and natural gas hedges and derivatives (June 30, 2001 — nil).

Consolidated Statements of Income and Distributable income

     The application of U.S. GAAP would have the following effect on net earnings as reported:

		Three Months Ended					Six Months Ended
		June 30 ($)					June 30 ($)
		2001		2002			2001			2002
		(Stated in thousands of Canadian Dollars, except
		per unit amounts)
		(unaudited)					(unaudited)
Net income, as reported		$	33,844	$	13,604		$	75,752		$	14,046
Adjustments net of tax
	Depletion adjustments (a)		5,449		6,525			12,402			12,836
	Compensation cost (d)		525		—			(180	)		—
	Unrealized gain (loss) on oil and gas contracts that do not qualify as hedges		—		409			—			(712	)
Net income for the year — U.S. GAAP		$	39,818	$	20,538		$	87,974		$	26,170
Other comprehensive income:
	Unrealized gain on available-for-sale securities (e)(f)		—		398			—			634
	Cumulative effect on the initial adoption of SFAS No. 133 (f)(g)		—		—			2,128			—
	Unrealized hedging gains (f)(g)		1,805		—			—			641
	Unrealized hedging losses (f)(g)		—		(7,550	)		(2,397	)		(10,425	)
Other comprehensive income — U.S. GAAP		$	41,623	$	13,386		$	87,705		$	17,020
Net income per unit — U.S. GAAP — Basic		$	0.59	$	0.24		$	1.34		$	0.31
— Diluted		$	0.58	$	0.24		$	1.33		$	0.31

F-21

Consolidated Balance Sheets

     The application of U.S. GAAP would have the following effect on the Balance Sheets as reported:

				Increase
		As Reported		(Decrease)			U.S. GAAP
		(Stated in thousands of Canadian
		Dollars ($))
December 31, 2001
Assets:
	Capital assets (a)(b)	$	1,208,526	$	(328,895	)	$	879,631
	Unrealized hedging gain (g)		—		2,522			2,522
				$	(326,373	)
Liabilities:
	Provision for abandonment costs (b)	$	32,591	$	(32,591	)	$	—
	Unrealized hedging loss (g)		—		328			328
Unitholders’ equity:
	Other comprehensive income (f)(g)		—		2,194			2,194
	Trust Unitholders’ Equity (a)		817,203		(296,304	)		520,899
				$	(326,373	)
June 30, 2002 (unaudited)
Assets:
	Marketable securities (e)	$	2,689	$	634		$	3,323
	Capital assets (a)(b)		1,145,197		(321,371	)		823,826
	Unrealized hedging gain (g)		—		313			313
				$	(320,424	)
Liabilities:
	Accounts payable and accrued liabilities (g)	$	29,403	$	712		$	30,115
	Provision for abandonment costs (b)		37,903		(37,903	)		—
	Unrealized hedging loss (g)		—		7,903			7,903
Unitholders’ equity:
	Other comprehensive income (f)(g)		—		(6,956	)		(6,956	)
	Trust Unitholders’ Equity (a)		867,213		(284,180	)		583,033
				$	(320,424	)

Additional disclosures required under U.S. GAAP

     The components of accounts receivable are as follows:

	December 31,		June 30,
	2001		2002
			(unaudited)
Trade	$	20,292	$	25,311
Prepaids		3,968		4,503
Other		3,599		2,928
	$	27,859	$	32,742

F-22

     The components of accounts payable and accrued liabilities are as follows:

	December 31,		June 30,
	2001		2002
			(unaudited)
Accounts payable	$	19,566	$	23,620
Accrued liabilities		11,793		6,495
	$	31,359	$	30,115

F-23

AUDITORS’ REPORT OF KPMG LLP AND CONSOLIDATED FINANCIAL STATEMENTS

OF PENGROWTH ENERGY TRUST FOR THE YEARS ENDED

DECEMBER 31, 2001 AND DECEMBER 31, 2000

F-24

MANAGEMENT’S REPORT

Management’s Responsibility to the Unitholders

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

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

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

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

/s/ JAMES S. KINNEAR
James S. Kinnear
President and Chief Executive Officer
February 25, 2002 /s/ GORDON M. ANDERSON
Gordon M. Anderson
Vice President and Interim Chief Financial Officer

F-25

AUDITORS’ REPORT

To the Unitholders of

Pengrowth Energy Trust

     We have audited the consolidated balance sheets of Pengrowth Energy Trust as at December 31, 2001 and 2000 and the consolidated statements of income and distributable income, unitholders’ equity and cash flow for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

     In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2001 and 2000 and the results of its operations and its cash flow for the years then ended in accordance with Canadian generally accepted accounting principles.

Chartered Accountants

Calgary, Canada

February 25, 2002

F-26

PENGROWTH ENERGY TRUST

CONSOLIDATED BALANCE SHEETS

		As at December 31
		2001		2000
		(stated in thousands of
		dollars)
ASSETS
CURRENT ASSETS
	Cash	$	3,797	$	4,533
	Accounts receivable		27,859		33,103
	Inventory		2,687		8,509
			34,343		46,145
REMEDIATION TRUST FUND (Note 3)			6,470		5,515
PROPERTY, PLANT AND EQUIPMENT AND OTHER ASSETS (Note 5)			1,208,526		1,038,823
		$	1,249,339	$	1,090,483
LIABILITIES AND UNITHOLDERS’ EQUITY
CURRENT LIABILITIES
	Accounts payable and accrued liabilities	$	31,359	$	40,396
	Distributions payable to unitholders		22,207		48,010
	Due to Pengrowth Management Limited (Note 10)		523		1,941
	Current portion of obligation under capital lease		—		553
			54,089		90,900
LONG-TERM DEBT (Note 6)			345,456		286,823
FUTURE SITE RESTORATION COSTS			32,591		25,285
FUTURE INCOME TAXES (Note 9)			—		45,510
TRUST UNITHOLDERS’ EQUITY(Note 7)			817,203		641,965
		$	1,249,339	$	1,090,483

See accompanying notes to the consolidated financial statements.

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

/s/ THOMAS A. CUMMING	/s/ FRANCIS G. VETSCH
Thomas A. Cumming	Francis G. Vetsch
Director	Director

F-27

PENGROWTH ENERGY TRUST

CONSOLIDATED STATEMENTS OF INCOME AND DISTRIBUTABLE INCOME

		Years ended December 31
		2001			2000
		(stated in thousands of
		dollars)
REVENUES
	Oil and gas sales	$	469,929		$	416,228
	Processing and other income		7,071			5,520
	Crown royalties		(65,703	)		(70,111	)
	Alberta Royalty Tax Credit		500			517
	Freehold royalties and mineral taxes		(6,757	)		(6,994	)
			405,040			345,160
	Interest and other income		1,348			5,788
NET REVENUE			406,388			350,948
EXPENSES
	Operating		104,943			65,195
	Amortization of injectants for miscible floods		47,448			32,463
	Interest		18,806			17,354
	General and administrative		7,467			7,081
	Management fee (Note 10)		7,120			6,873
	Capital taxes		2,659			1,830
	Depletion and depreciation		124,208			89,253
	Future site restoration		8,529			7,612
			321,180			227,661
INCOME BEFORE THE FOLLOWING			85,208			123,287
Royalty income attributable to royalty units other than those held by Pengrowth Energy Trust			58			72
NET INCOME			85,150			123,215
Add: Depletion, depreciation and future site restoration			132,737			96,865
Alberta Royalty Credit received during year			517			1,378
Deduct: Alberta Royalty Credit accrued for year			(500	)		(517	)
Remediation expenses and trust fund contributions (Note 3)			(2,117	)		(2,601	)
DISTRIBUTABLE INCOME		$	215,787		$	218,340
NET INCOME PER UNIT (Note 11) Basic		$	1.201		$	2.213
Diluted		$	1.197		$	2.194
DISTRIBUTABLE INCOME PER UNIT (Note 11)
	Based on weighted average units outstanding	$	3.043		$	3.922
	Based on actual distributions paid or declared	$	3.010		$	3.785

See accompanying notes to the consolidated financial statements.

F-28

PENGROWTH ENERGY TRUST

CONSOLIDATED STATEMENTS OF CASH FLOW

		Years ended
		December 31
		2001			2000
		(stated in thousands of
		dollars)
CASH PROVIDED BY (USED FOR):
OPERATING
	Net income	$	85,150		$	123,215
	Items not involving cash
	Depletion, depreciation and future site restoration		132,737			96,865
	Amortization of injectants		47,448			32,463
	Purchase of injectants		(56,352	)		(46,782	)
	Expenditures on remediation		(1,223	)		(871	)
	Gain on sale of marketable securities		—			(2,741	)
Funds generated from operations			207,760			202,149
	Distributions		(241,590	)		(197,826	)
	Changes in non-cash operating working capital (Note 8)		(2,919	)		4,976
			(36,749	)		9,299
FINANCING
	Change in long-term debt		58,080			56,571
	Proceeds from issue of trust units		305,875			178,500
			363,955			235,071
INVESTING
	Expenditures on property acquisitions		(280,058	)		(181,628	)
	Expenditures on property, plant and equipment		(74,026	)		(59,759	)
	Proceeds on property dispositions		23,567			—
	Change in Remediation Trust Fund		(955	)		(1,730	)
	Marketable securities		—			5,333
	Change in non-cash investing working capital (Note 8)		3,530			(798	)
			(327,942	)		(238,582	)
INCREASE (DECREASE) IN CASH			(736	)		5,788
CASH AND TERM DEPOSITS (BANK INDEBTEDNESS) AT BEGINNING OF YEAR			4,533			(1,255	)
CASH AND TERM DEPOSITS AT END OF YEAR		$	3,797		$	4,533

See accompanying notes to the consolidated financial statements

F-29

PENGROWTH ENERGY TRUST

CONSOLIDATED STATEMENTS OF TRUST UNITHOLDERS’ EQUITY

	Years ended
	December 31
	2001			2000
	(stated in thousands of
	dollars)
Unitholders’ equity at beginning of year	$	641,965		$	558,590
Units issued, net of issue costs		305,875			178,500
Net income for year		85,150			123,215
Distributable income		(215,787	)		(218,340	)
TRUST UNITHOLDERS’ EQUITY AT END OF YEAR	$	817,203		$	641,965

F-30

PENGROWTH ENERGY TRUST

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years ended December 31, 2001 and 2000

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

1.     Structure of the Trust

     Pengrowth Energy Trust (“EnergyTrust”) is a closed-end investment trust created under the laws of the Province of Alberta pursuant to a Trust Indenture dated December 2, 1988 (as amended) between Pengrowth Corporation (“Corporation”) and ComputerShare Investor Services Inc. (formerly Montreal Trust Company of Canada). Operations commenced on December 30, 1988. The beneficiaries of EnergyTrust are the holders of trust units (the “unitholders”).

     EnergyTrust acquires and holds royalty units issued by the Corporation, which entitles EnergyTrust to the net revenue generated by Corporation’s petroleum and natural gas properties less certain defined charges. In addition, unitholders are entitled to receive the net cash flows from other investments that are held directly by EnergyTrust. As at December 31, 2001 EnergyTrust owned 99.9 percent of the royalty units issued by the Corporation.

     Pengrowth Management Limited (the “Manager”) is responsible for the management of the business affairs of the Corporation and the administration of EnergyTrust. At December 31, 2001, the shares of the Corporation were wholly owned by the Manager, and the Manager is controlled by a director of the Corporation. Subsequent to year-end, Corporation issued 1,000 common shares to EnergyTrust for proceeds of $1,000 resulting in EnergyTrust owning 91% of the common shares of Corporation.

     Under the terms of the Royalty Indenture,the Corporation is entitled to retain a one percent share of royalty income and all miscellaneous income (the “Residual Interest”) to the extent this amount exceeds the aggregate of debt service charges, general and administrative expenses, and management fees. In 2001 and 2000, the Corporation was not eligible to retain this Residual Interest.

2.     Significant Accounting Policies

     Basis of Presentation

     EnergyTrust’s consolidated financial statements have been prepared in accordance with generally accepted accounting principles in Canada and they include the accounts of EnergyTrust and the accounts of Corporation (collectively referred to as “Pengrowth”). All inter-entity transactions have been eliminated. These financial statements do not contain the accounts of the Manager.

     Although there is no legal ownership between EnergyTrust and Corporation, EnergyTrust, through the royalty, obtains substantially all the economic benefits of Corporation. In addition, the unitholders of EnergyTrust have the right to elect the majority of the board of directors of Corporation (see note 1).

     Property Plant and Equipment

     Pengrowth follows the full cost method of accounting for oil and gas properties and facilities whereby all costs of acquiring such interests are capitalized and depleted on the unit of production method based on proved reserves before royalties as estimated by independent engineers. Natural gas production and reserves are converted to equivalent units of crude oil using their relative energy content.

     General and administrative costs are not capitalized other than to the extent they are directly related to a successful acquisition, or to the extent of Pengrowth’s working interest in capital expenditure programs to which overhead fees can be recovered from partners. Overhead fees are not charged on 100 percent owned projects.

F-31

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

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

     Pengrowth places a limit on the aggregate carrying value of property, plant and equipment and deferred injectant costs that may be carried forward for depletion against revenues of future periods (the “ceiling test”). The cost of these assets less accumulated depletion and depreciation is limited to an amount equal to the estimated future net revenue from production of proved reserves (based on unescalated prices and costs at the balance sheet date) less estimated future general and administrative costs, financing costs and management fees.

Injectant Costs

     Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated as 30 months.

Inventory

     Inventories of crude oil, natural gas and natural gas liquids are stated at the lower of cost and net realizable value.

Future Site Restoration Costs

     Provisions for future site restoration costs are made over the life of the oil and gas properties and facilities using the unit of production method. Costs are based on engineering estimates considering current regulations, costs and industry standards. Pengrowth has placed cash in a segregated remediation trust account to fund certain site restoration costs for the Judy Creek and Swan Hills properties. Contributions to the remediation trust account and remediation expenditures not funded by the trust account are charged against distributable income in the period incurred.

Income Taxes

     EnergyTrust is a taxable trust under the Income Tax Act (Canada). No provision has been made for income taxes by EnergyTrust in these financial statements, as income taxes are the responsibility of the individual unitholders and EnergyTrust distributes all of its income to its unitholders. In 2001, EnergyTrust allocated $124.3 million in taxable income or $1.795 per unit to unitholders (2000 — $110.4 million, or $1.983 per unit).

     The Corporation follows the tax liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the Corporation’s financial statements and their respective tax bases, using enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs. In determining its taxable income, the Corporation deducts royalty payments to the unitholders. In 2001, net income of the Corporation, after deducting royalty payments to royalty unitholders, was nil. If the Corporation ever lacked sufficient deductions to reduce taxable income to nil, the taxes would be deducted from royalty payments to unitholders.

Trust unit compensation plans

     Pengrowth has a number of trust unit compensation plans, the accounting policies for which are described in Note 7.

F-32

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

Risk Management

     Pengrowth uses forward and futures contracts to manage its exposure to commodity price fluctuations. The net receipts or payments arising from these contracts are recognized in income as a component of oil and gas sales during the same period as the corresponding hedged position.

     Interest rate swaps are used to manage exposure to changes in interest rates. The net receipts or payments arising from interest rate swaps are recognized in income as a component of interest expense during the same period as the corresponding hedged position.

Measurement Uncertainty

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

     The amounts recorded for depletion, depreciation and amortization of injectants and the provision for abandonment costs are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.

     Earnings per unit

     In the fourth quarter of fiscal 2000, Pengrowth adopted the Canadian Institute of Chartered Accountants’ new standard with respect to the computation,presentation and disclosure of earnings per unit. The impact of adopting the new standard on the periods presented is not significant. Under the new standard, the treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations.

3.     Remediation Trust Fund

     Pursuant to a Purchase and Sale Agreement dated August 15, 1997 between Pengrowth and Imperial Oil Resources (“Imperial”), a trust was established to fund certain remediation obligations of the Judy Creek and Swan Hills properties. ComputerShare Investor Services Inc. is the trustee for the Remediation Trust Fund. With respect to the current and future years, Pengrowth agreed to make a contribution of $250,000 on October 15, 2001 and a contribution of $250,000 per annum for each year subsequent to 2001 to the Remediation Trust Fund. In addition, Pengrowth makes a monthly trust fund contribution equivalent to $0.10 per boe of production from the Judy Creek properties.

     Every five years Pengrowth must deliver a report to Imperial evaluating the assets in the trust fund and the outstanding remediation obligations, and make recommendations as to whether contribution levels should be changed. If Imperial does not consent to recommended changes in the contribution level, the matter may be arbitrated.

     The following summarizes Pengrowth’s Remediation Trust Fund contributions for 2001 and 2000 and Pengrowth’s expenditures on remediation activities not covered by the trust fund:

	2001		2000
Contributions to Remediation Trust Fund	$	1,002	$	2,461
Remediation expenditures not covered by the Trust Fund		1,115		140
	$	2,117	$	2,601

F-33

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

4.     Acquisitions

     In June 2001, Pengrowth acquired an 8.4% royalty interest in the Sable Offshore Energy Project for cash consideration of $252.0 million and forgiveness of a note payable of $4.2 million. The acquisition has been accounted for by the purchase method with the results of operations of the acquired assets included in the financial statements from the date of acquisition.

     The following unaudited proforma information provides an indication of what Pengrowth’s results of operations would have been had the acquisition taken place on January 1.

		2001(a)		2000(b)
		unaudited		unaudited
Oil and gas sales		$	537,954	$	504,010
Net income		$	122,014	$	162,742
Net income per unit
	Basic	$	1.618	$	2.445
	Diluted	$	1.613	$	2.432

(a)	assumes acquisition took place on January 1, 2001
(b)	assumes acquisition took place on January 1, 2000

5.     Property, Plant and Equipment and Other Assets

		2001			2000
PROPERTY, PLANT AND EQUIPMENT
	Property, plant and equipment at cost	$	1,583,102		$	1,298,096
	Accumulated depletion and depreciation		(437,599	)		(313,391	)
Net book value of property, plant and equipment		$	1,145,503		$	984,705
OTHER ASSETS
	Deferred injectant costs		63,023			54,118
Net book value of property, plant and equipment and other assets		$	1,208,526		$	1,038,823

     As at December 31, 2001, Pengrowth had a surplus in its ceiling test using year-end prices.

     Total estimated undiscounted future site restoration costs are approximately $165.4 million of which $32.6 million has been accrued to date.

6.     Long Term Debt

	2001		2000
Revolving credit facility	$	345,456	$	286,823
Obligation under capital lease		—		553
Less: current portion of lease obligation		—		(553	)
	$	345,456	$	286,823

     The Corporation has a $415 million revolving credit facility syndicated among nine financial institutions with an extendible 364 day revolving period and a three year amortization term period. In addition, it has a $35 million demand operating line of credit that is currently reduced by outstanding letters of credit in the amount of approximately $14 million. The facilities are secured by a $500 million first fixed and floating

F-34

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

charge debenture on all of the Corporation’s assets. In addition, EnergyTrust has issued a guarantee and a $200 million debenture granting a first fixed security interest in the Judy Creek and Swan Hills facilities to the financial institutions in the credit facility. Interest payable on amounts drawn is at the prevailing bankers’ acceptance rates plus stamping fees, lenders’ prime lending rates, or U.S. LIBOR rates plus applicable margins, depending on the form of borrowing by the Corporation. The margins and stamping fees vary depending on financial statement ratios and can range from 0.625 percent to 1.125 percent. Interest expense for the year ended December 31, 2001 includes $23,630,851 in cash interest payments (2000 — $15,620,843).

     The credit facility will revolve until June 23, 2002, whereupon it is expected to be renewed for a further 364 days, subject to satisfactory review by the lenders. If the lenders were to convert the facility to a non-revolving term facility, then amounts outstanding under the facility become repayable in 12 equal quarterly installments. As at December 31, 2001, the obligation outstanding under the revolving credit facility is classified as long term debt as the lenders have advised management that subject to the Corporation complying with the terms and conditions of the Credit Agreement, no principal repayments are required in 2002.

     On June 15, 2002, the total amount of letters of credit outstanding will increase to $39 million.

7.     Trust Units

     The authorized capital of Pengrowth is 500,000,000 trust units.

	2001					2000
	Number of					Number of
Trust Units Issued	Units		Amount			Units		Amount
Balance, beginning of year		63,852,198	$	974,724			53,639,338	$	796,224
Issued for cash		17,622,500		311,974			8,165,000		155,135
Less: issue expenses		—		(18,727	)		—		(8,303	)
Issued for cash on exercise of stock options		628,828		10,060			1,915,833		29,299
Issued for cash under Distribution Reinvestment (“DRIP”) Plan		136,543		2,568			132,027		2,369
Balance, end of year		82,240,069	$	1,280,599			63,852,198	$	974,724

     Pursuant to the terms of the Royalty Indenture and the Trust Indenture, there is attached to each royalty unit granted by the Corporation the right to exchange such royalty unit for an equivalent number of trust units. ComputerShare, as Trustee has reserved 18,940 trust units for such future conversion.

     Distribution Reinvestment Plan

     The Distribution Reinvestment Plan (“DRIP”) entitles unitholders to reinvest cash distributions in additional units of EnergyTrust. The trust units under the plan may be acquired in the open market at prevailing market prices or issued from treasury at the weighted average price of all EnergyTrust units traded on the Toronto Stock Exchange for the 20 trading days preceding a distribution payment date.

     Trust Unit Option Plan

     Pengrowth has a trust unit option plan under which employees and directors of the Corporation and the Manager are eligible to receive options. As options are issued at the market price on date of grant, no compensation expense is recognized when new options are issued. Under the terms of the plan, up to 10% of the issued and outstanding trust units to a maximum of 7 million units may be reserved for these option grants. One third of the options vest on the grant date, one third on the first anniversary of the date of grant, and the

F-35

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

remaining third on the second anniversary. The options expire five years from the date of grant. As at December 31, 2001, options to purchase 3,106,635 trust units were outstanding (2000 — 2,893,554) that expire at various dates to August 31, 2006.

	2001					2000
				Weighted					Weighted
	Number of			Average		Number of			Average
Trust Unit Options	Options			Exercise Price		Options			Exercise Price
Outstanding at beginning of year		2,893,554		$	17.45		4,041,287		$	16.16
Granted		905,979			17.66		821,100			18.73
Exercised		(628,828	)		16.00		(1,915,833	)		15.29
Cancelled		(64,070	)		18.98		(53,000	)		16.85
Outstanding at year end		3,106,635			17.78		2,893,554			17.45
Exercisable at year end		2,238,406			17.69		2,171,087			17.51

     The following table summarizes information about trust unit options outstanding at December 31,2001:

	Options Outstanding						Options Exercisable
			Weighted
	Number		Average		Weighted		Number		Weighted
	Outstanding		Remaining		Average		Exercisable		Average
Range of Exercise Prices	At 12/31/01		Contractual Life		Exercise Price		At 12/31/01		Exercise Price
$12.00 to $14.99		181,650		2.3 years	$	12.68		181,650	$	12.68
$15.00 to $16.99		289,220		1.4		15.86		273,720		15.85
$17.00 to $17.99		1,504,759		3.0		17.49		935,953		17.49
$18.00 to $20.50		1,131,006		3.0		19.47		847,083		19.59
$12.00 to $20.50		3,106,635		2.8	$	17.78		2,238,406	$	17.69

     Share Appreciation Rights

     As at December 31, 2001 and 2000, 426,000 Share Appreciation Rights (“SAR’s”) were held by an officer of Pengrowth. They are fully vested, have a weighted average exercise price of $18.39 and expiry dates ranging from October 15 to December 1, 2002.

     The SAR’s grant the right to receive a Payment Amount equal to any increase in the market price of the 426,000 trust units above the exercise price. Pengrowth may, at its option, satisfy this Payment Amount with either a cash payment or the issue of trust units from treasury based on market prices at the time of exercise. No compensation expense is recognized for the SAR’s until a cash payment is made.

     Trust Unit Savings Plan

     Pengrowth has a trust unit savings plan whereby qualifying employees may contribute from 1 to 10 percent of their basic annual salary. Employee contributions are invested in EnergyTrust units purchased on the open market. Pengrowth matches the employees’ contribution, investing in additional trust units purchased on the open market. Pengrowth’s share of contributions is recorded as compensation expense and amounted to $729,730 in 2001 (2000 — $532,014).

     Trust Unit Margin Purchase Plan

     Pengrowth has a plan whereby the Manager, and employees, directors, and certain consultants of Corporation can purchase trust units and finance up to 75% of the purchase price through an investment

F-36

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

dealer, subject to certain participation limits and restrictions. Participants maintain personal margin accounts with the investment dealer and are responsible for all interest costs and obligations with respect to their margin loans. The Corporation has provided a $5 million letter of credit to the investment dealer to guarantee amounts owing with respect to the plan. The amount of the letter of credit may fluctuate depending on the amounts financed pursuant to the plan. At December 31, 2001, 2,446,896 trust units were deposited under the plan (2000 — 1,925,518) with a market value of $34.8 million (2000 — $37.0 million) and a corresponding margin loan of $13.9 million (2000 — $11.6 million).

     Redemption Rights

     Trust Units are redeemable at the request of a Unitholder. The redemption right permits Unitholders in the aggregate to redeem a maximum of $25,000 of Trust Units in a month.

8.     Change in Non-Cash Operating Working Capital

	2001			2000
Accounts receivable	$	5,244		$	(10,193	)
Inventory		5,822			(6,742	)
Accounts payable and accrued liabilities		(12,567	)		21,246
Due to Pengrowth Management Limited		(1,418	)		665
	$	(2,919	)	$	4,976

          Change in Non-Cash Investing Working Capital

	2001		2000
Accounts payable for capital accruals	$	3,530	$	(798	)

9.     Income Taxes

     During 2000, the Corporation changed its method of accounting for income taxes from the deferral method to the liability method as described in note 2, and has applied this change retroactively without restating prior periods.

     In 2001, the cost basis for income tax purposes of property, plant and equipment exceeded the net book value by $152,507,000 principally as a result of the acquisition of oil and gas properties during the year. A future tax asset of $64,968,000 has been reduced to nil through a valuation allowance of $64,968,000. In 2000, the net book value of property, plant and equipment exceeded the cost basis for income tax purposes by $102,040,000 and a future income tax liability of $45,510,000 was recorded in respect thereof.

     In 2001, the Corporation made cash payments of $2,702,000 in respect of capital taxes (2000 — $1,827,000).

10.     Related Party Transactions

     Pengrowth Management Limited provides certain services pursuant to a management agreement for which Pengrowth was charged $2,235,224 (2000 — $1,238,000) for acquisition fees and $7,120,419 (2000 — $6,872,570) for a management fee. The law firm controlled by the corporate secretary charged $147,850 (2000 — $284,456) for legal services provided to Pengrowth. A corporate finance firm controlled by a member of the immediate family of the corporate secretary charged $1,513,250 (2000 — nil) for acquisition-related advisory services provided to Pengrowth by the corporate secretary.

F-37

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

     The Corporation has provided a $5 million letter of credit to an investment dealer to guarantee amounts owing to the investment dealer. See note 7 — Trust Unit Margin Purchase Plan.

11.     Amounts Per Unit

     The per unit amounts for net income and distributable income are based on weighted average units outstanding for the year. The weighted average units outstanding for 2001 were 70,910,746 units (2000 — 55,672,865 units). In computing diluted net income per unit, 205,453 units were added to the weighted average number of units outstanding during the year ended December 31, 2001 (2000 — 354,331) for the dilutive effect of employee stock options. The per unit amount of distributions paid or declared reflect actual distributions paid or declared based on units outstanding at the time.

     Distributions are declared payable during the month following the month in which the distributions were earned. Distributions are paid to unitholders on the 15th day of the second month after the distributions are earned. As at December 31, 2001 there was a balance of $823,334 or $0.010 per unit that had been earned but had not yet been paid or declared (2000 — $700,188 or $0.011 per unit).

12.     Financial Instruments

     Interest Rate Risk

     As at December 31, 2001, Pengrowth had entered into interest rate swaps on $100 million of its long term debt for periods of three years ending November 30, 2004 ($75 million) and December 31, 2004 ($25 million) at an average borrowing cost of 4.7825%.

     The estimated fair value of the interest rate swaps has been determined based on the amount that Pengrowth would receive or pay to terminate the contracts at year-end. At December 31, 2001 the amount that Pengrowth would pay to terminate the interest rate swaps is $328,000.

     Foreign Currency Exchange Risk

     Pengrowth is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices. Pengrowth has mitigated some of this exchange risk by entering into fixed Canadian dollar crude oil price swaps as outlined below.

     Credit Risk

     A portion of Pengrowth’s accounts receivable are with joint venture partners in the oil and gas industry and are subject to normal industry credit risks. The use of commodity price swap agreements involves a degree of credit risk that Pengrowth manages through its credit policies which are designed to limit eligible counterparties to those with “A” credit ratings or better.

     Forward and Futures Contracts

     Pengrowth has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. Pengrowth sells forward a portion of its future production through a combination of fixed price sales contracts with customers and commodity swap agreements with financial counterparties. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates however, gains or losses on the contracts are offset by changes in the value of Pengrowth’s production.

F-38

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

     As at December 31, 2001, Pengrowth had fixed the price applicable to future production as follows:

Financial Swap Contracts

	Crude Oil				Natural Gas
	Volume		Price		Volume
	(bbl/d)		C$/bbl		(MMbtu/d)		Fixed Price
2002		2,000	$	35.04		7,000	$	3.90 US/MMbtu
2003		—		—		7,000	$	3.90 US/MMbtu
2004		—		—		7,000	$	3.90 US/MMbtu

     As well, Pengrowth had natural gas fixed price sales contracts which fixed the price on 7,262 mcf/d for 2002 at a price of $2.99 Cdn/mcf.

     The estimated fair value of the crude oil financial swap contracts and the natural gas fixed price sales contracts have been determined based on the amounts Pengrowth would receive or pay to terminate the contracts at year-end. At December 31, 2001, the amount Pengrowth would receive if the crude oil and natural gas contracts were terminated would be $1,727,600 and $36,000, respectively.

     Fair Value of Financial Instruments

     The carrying value of financial instruments included in the balance sheet, other than bank debt, approximate their fair value due to their short maturity. The fair value of the Remediation Trust Fund was $6,473,000 (2000 — $5,544,077).

13. Reconciliation of Financial Statements to United States Generally Accepted Accounting Principles

     The significant differences between Canadian generally accepted accounting principles (“Canadian GAAP”) which, in most respects, conforms to generally accepted accounting principles in the United States (“U.S. GAAP”), as they apply to Pengrowth, are as follows:

     (a) Under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at 10 percent (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproven properties. Under Canadian GAAP, this “ceiling test” is calculated without application of a discount factor. At December 31, 1998 and 1997 the application of the full cost ceiling test under U.S. GAAP resulted in a write-down of capitalized costs of $328.6 million and $49.8 million, respectively. At December 31, 2001 and 2000, the application of the full cost ceiling test under U.S. GAAP did not result in a write-down of capitalized costs.

     Where the amount of a ceiling test writedown under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion, depreciation, and amortization will differ in subsequent years.

     (b) Under U.S. GAAP, the provision for abandonment costs is recorded as a reduction of capital assets.

     (c) Under U.S. GAAP, interest and other income would not be included as a component of Net Revenue.

     (d) SFAS 123, “Accounting for Stock-based Compensation”, establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. As permitted by the SFAS 123, Pengrowth has elected to continue to follow the intrinsic value method of accounting for stock-based compensation arrangements, as provided for in Accounting Principles Board Opinion 25 (“APB 25”). Since

F-39

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

all options were granted with an exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income.

     Had compensation cost for Pengrowth’s stock options been determined based on the fair market value at the grant dates of the awards consistent with methodology prescribed by SFAS 123, “Accounting for Stock-Based Compensation”, Pengrowth’s net income and net income per unit for years ended December 31, 2001 and 2000 would have been the pro forma amounts indicated below:

		Years ended
		December 31,
		2001		2000
Net income:
	As reported	$	110,748	$	150,654
	Pro forma		110,457		150,498
Net income per unit:
	As reported	$	1.56	$	2.71
	Pro forma		1.56		2.70

     Under the provisions of SFAS 123 the pro forma disclosures above include only the effects of stock options granted by Pengrowth subsequent to December 31, 1996. During this initial phase-in period, the pro-forma disclosures as required by SFAS 123 are not representative of the effects on reported income for future years as options vest over several years and additional awards are generally made each year.

     The weighted average fair market value of options granted in 2001 and 2000 was $0.50 and $0.26 per option respectively. The fair value of each option granted was estimated on the date of grant using the Modified Black-Scholes option-pricing model with the following assumptions for 2001 and 2000 respectively: risk-free interest rate of 4 and 5 percent, dividend yield of 14.0 and 19.0 percent, volatility of 27 and 16 percent, normalized dilution of 7 percent and liquidity discount of 10 percent for both years, and expected life of five years in both years.

     APB 25 also requires recognition of compensation cost with respect to Stock Appreciation Rights granted to employees. No compensation cost results from application of the above provisions for the year ended December 31, 2001. Application of provisions of APB 25 resulted in a compensation cost of $510,000 for the year ended December 31, 2000 for U.S. GAAP purposes.

     (e) Marketable securities held by Pengrowth are classified as available-for-sale in accordance with definitions of SFAS 115. Under provisions of this Statement, available-for-sale securities are reported at the fair value, with unrealized holding gains and losses included in comprehensive income and reported as a separate component of unitholders’ equity until realized.

     (f) SFAS 130 requires the reporting of comprehensive income in addition to net earnings. Comprehensive income includes net income plus other comprehensive income; specifically, all changes in equity of a company during a period arising from non-owner sources.

     (g) Statement of Financial Accounting Standards No. 133, “Accounting for Derivative instruments and Hedging Activities” (SFAS 133), is effective for all fiscal years beginning after June 15, 2000. Pengrowth has implemented the standards set out in SFAS 133 for the fiscal year commencing January 1, 2001, with no restatement of prior periods. SFAS 133 establishes new accounting and reporting standards for derivative instruments and for hedging activities. This statement requires an entity to establish, at the inception of a hedge, the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity’s approach to managing risk.

F-40

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

     On initial adoption of SFAS No. 133 on January 1, 2001, additional liabilities of $2.1 million were recorded for U.S. GAAP purposes to reflect the fair value of derivatives designated as cash flow hedges. A charge of $2.1 million relating to the fair value of these hedges was recognized in other comprehensive income as the cumulative effect of the initial adoption of SFAS No. 133.

     At December 31, 2001, $2,522,000 has been recorded as an asset in respect of the fair value of crude oil and natural gas hedges outstanding at year-end with a corresponding increase in other comprehensive income. This amount will be amortized against crude oil and natural gas sales over the remaining terms of the related hedges. Also at December 31, 2001, a liability of $328,000 has been recorded in respect of the fair value of interest rate swaps outstanding at year-end with a corresponding decrease in other comprehensive income.

Consolidated Statements of Income and Distributable Income

     The application of U.S. GAAP would have the following effect on net earnings as reported:

		Years ended December 31
		2001			2000
		(Stated in thousands of
		Canadian Dollars, except
		per unit amounts)
Net income for the year, as reported		$	85,150		$	123,215
Adjustments net of tax
	Depletion and depreciation (a)		25,598			27,949
	Compensation cost (d)		—			(510	)
Net income for the year — U.S. GAAP		$	110,748		$	150,654
Other comprehensive income:
	Cumulative effect of the initial adoption of SFAS No. 133 (f)(g)		2,128			—
	Unrealized hedging gains (f)(g)		2,522			—
	Unrealized hedging losses (f)(g)		(328	)		—
	Realized gain on available-for-sale securities (e)(f)		—			(1,613	)
Comprehensive income — U.S. GAAP		$	115,070		$	149,041
Net income per unit — U.S. GAAP — Basic		$	1.56		$	2.71
— Diluted		$	1.56		$	2.67

F-41

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

Consolidated Balance Sheets

     The application of U.S. GAAP would have the following effect on the Balance Sheets as reported:

		As Reported		Increase (Decrease)			U.S. GAAP
		(Stated in thousands of Canadian Dollars)
December 31, 2001
Assets:
	Capital assets (a)(b)	$	1,208,526	$	(328,895	)	$	879,631
	Unrealized hedging gain (g)		—		2,522			2,522
				$	(326,373	)
Liabilities:
	Provision for abandonment costs (b)	$	32,591	$	(32,591	)	$	—
	Unrealized hedging loss (g)		—		328			328
Unitholders’ equity:
	Other comprehensive income (f)(g)		—		2,194			2,194
	Trust Unitholders’ Equity (a)		817,203		(296,304	)		520,899
				$	(326,373	)
December 31, 2000
Assets:
	Capital assets (a)(b)	$	1,038,823	$	(347,187	)	$	691,636
				$	(347,187	)
Liabilities:
	Provision for abandonment costs (b)	$	25,285	$	(25,285	)	$	—
	Other (d)		—		510			510
Unitholders’ equity:
	Trust Unitholders’ Equity (a)		641,965		(322,412	)		319,553
				$	(347,187	)

Additional Disclosures Required Under U.S. GAAP

     The components of accounts receivable are as follows:

	December 31,
	2001		2000
Trade	$	20,292	$	27,716
Prepaids		3,968		2,795
Other		3,599		2,592
	$	27,859	$	33,103

F-42

PENGROWTH ENERGY TRUST

Notes to Consolidated Financial Statements — (Continued)

     The components of accounts payable and accrued liabilities are as follows:

	December 31,
	2001		2000
Accounts payable	$	19,566	$	29,573
Accrued liabilities		11,793		10,823
	$	31,359	$	40,396

F-43

PENGROWTH ENERGY TRUST

SFAS NO. 69 SUPPLEMENTAL RESERVE INFORMATION

F-44

PENGROWTH ENERGY TRUST

SFAS NO. 69 SUPPLEMENTAL RESERVE INFORMATION

(Unaudited)

     The following disclosures have been prepared in accordance with SFAS No. 69 — “Disclosures about Oil and Gas Producing Activities”:

Oil and Gas Reserves

     Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

     Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

     Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

     Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Trust’s estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Trust’s share of future production from Canadian reserves to be materially different from that presented.

     Subsequent to December 31, 2001 no major discovery or other favourable or adverse event is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

Results of Operations for Producing Activities

     The following table sets forth revenue and direct cost information relating to the Trust’s oil and gas producing activities for the years ended December 31.

		2000		2001
		(Thousands of dollars)
Revenue
	Sales	$	345,160	$	405,040
Deduct
	Production Costs		62,239		101,953
	Amortization of injectant costs		32,463		47,448
	Technical support and other		2,956		2,990
	Depletion, depreciation and amortization and valuation provision		61,304		98,610
Results of operations from producing activities		$	186,198	$	154,039

(1)  The costs in this schedule exclude corporate overhead, interest expense and other operating costs which are not directly related to producing activities.

F-45

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND

DEVELOPMENT ACTIVITIES

     Costs incurred in oil and gas producing activities for the years ended December 31 are as follows:

	2000		2001
	(Thousands of dollars)
Property Acquisition Costs Proved	$	227,138	$	280,058
Development Costs		59,759		74,026
Injectant Costs		46,782		56,352
	$	333,679	$	410,436

     Acquisition costs include costs incurred to purchase, lease, or otherwise acquire oil and gas properties.

     Development costs include the costs of drilling and equipping development wells and facilities to extract, treat and gather and store oil and gas.

     Injectants (mostly ethane and methane) are used in miscible flood programs to stimulate incremental oil recovery. The cost of injectants purchased from third parties for miscible flood projects is deferred and amortized over the period of expected future economic benefit which is estimated as 30 months.

     General and administrative costs are not capitalized other than to the extent they are directly related to a successful acquisition, or to the extent of the Trust’s working interest in exploration or development projects to which overhead fees can be recovered from partners. Overhead fees are not charged on 100% owned projects.

     There were no oil and gas property costs not being amortized in any of the years presented.

CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

     The capitalized costs and related accumulated depreciation, depletion and amortization, including impairments, relating to the Trust’s oil and gas exploration, development and producing activities at December 31 consist of:

	2000			2001
	(Thousands of dollars)
Proved oil and gas properties	$	1,352,214		$	1,646,125
Less accumulated depletion, depreciation and amortization		(660,578	)		(766,494	)
Net capitalized costs	$	691,636		$	879,631

F-46

Oil and Gas Reserve Information

     All of the Trust’s proved oil, natural gas liquids, and natural gas reserves are located in Canada, primarily in the provinces of Alberta, Saskatchewan and Nova Scotia. The Trust’s proved developed and undeveloped reserves after deductions of royalties are summarized below:

	Crude Oil
	and Natural			Natural
	Gas Liquids			Gas
	MMbbls			Bcf
NET PROVED DEVELOPED AND UNDEVELOPED
RESERVES AFTER ROYALTIES
End of year 1999		86.3			193.6
Revision of previous estimates		(0.1	)		(8.0	)
Purchase of reserves in place		11.9			7.0
Discoveries and extensions		1.7			1.9
Production		(6.7	)		(16.2	)
End of year 2000		93.1			178.3
Revision of previous estimates		(0.8	)		22.2
Purchase of reserves in place		6.4			159.6
Sales of reserves in place		(1.9	)		(8.3	)
Discoveries and extensions		1.7			5.8
Production		(7.6	)		(27.3	)
End of year 2001		90.9			330.3
NET PROVED DEVELOPED
RESERVES AFTER ROYALTIES
End of year 1999		62.8			172.8
End of year 2000		68.1			160.7
End of year 2001		65.9			231.6

(1)	Net after royalty reserves are the Trust’s lessor royalty, overriding royalty, and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.
(2)	Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations, from a given date forward, by known technology, under existing operating conditions and prices in effect at year end.
(3)	Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
(4)	Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

     The following information has been developed utilizing procedures described by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the independent engineering consultants of the Trust. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Trust or its performance. Further, information contained in the following table should not be

F-47

considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Trust’s reserves.

     The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the period end date. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

     Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

     The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2001 was based on a crude price of $30.06/bbl and natural gas price of $3.14/mcf. The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2000 was based on the Trust’s crude oil price of $39.97/bbl and natural gas price of $10.26/mcf.

     The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Trust’s crude oil and natural gas reserves at December 31, for the years presented.

		2000			2001
		(Millions of dollars)
Future cash inflows
Future costs		$	6,208		$	3,633
	Future production and development costs		(1,952	)		(1,968	)
	Future income taxes		(46	)		0
Future net cash flows			4,210			1,665
Deduct: 10% annual discount factor			(2,058	)		(768	)
Standardized measure of discounted future net cash flows		$	2,152		$	897

F-48

Changes in Standardized Measure of Discounted Future Cash Flow Relating to Proved Oil and Gas Reserves

     The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for the years presented.

	2000			2001
	(Millions of dollars)
Future discounted net cash flows at beginning of year	$	1,150		$	2,152
Sales and transfer, net of production costs		(235	)		(251	)
Net change in sales and transfer prices, net of development and production costs		1,060			(1,372	)
Extensions, discoveries and improved recovery, net of related costs		19			16
Revisions of quantity estimates		(8	)		14
Accretion of discount		115			216
Sales of reserves in place		—			(20	)
Purchase of reserves in place		150			198
Changes in timing of future net cash flows and other		(88	)		(67	)
Net change in income taxes		(11	)		11
End of Year	$	2,152		$	897

(1)  The schedules above are calculated using year-end prices, costs, statutory tax rates and existing proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.

F-49

AUDITORS’ REPORT OF KPMG LLP AND SCHEDULE OF REVENUE AND EXPENSES ASSOCIATED WITH THE NORTHERN BRITISH COLUMBIA OIL AND NATURAL GAS ASSETS ACQUIRED FROM THE CALPINE CANADA NATURAL GAS PARTNERSHIP BY PENGROWTH CORPORATION

F-50

AUDITORS’ REPORT

To: The Board of Directors of Pengrowth Corporation, as Administrator of

Pengrowth Energy Trust

     At the request of Pengrowth Corporation, as Administrator of Pengrowth Energy Trust, we have audited the Schedule of Revenue and Expenses associated with the northern British Columbia oil and natural gas assets acquired from the Calpine Canada Natural Gas Partnership by Pengrowth Corporation for each of the years in the three year period ended December 31, 2001. This financial information is the responsibility of Pengrowth Corporation’s management. Our responsibility is to express an opinion on this financial information based on our audit.

     We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial information is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial information. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial information.

     In our opinion, this schedule presents fairly, in all material respects, the revenues and expenses associated with the northern British Columbia oil and natural gas assets acquired from the Calpine Canada Natural Gas Partnership by Pengrowth Corporation for each of the years in the three year period ended December 31, 2001 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants

Calgary, Canada

Octoberl, 2002

F-51

SCHEDULE OF REVENUE AND EXPENSES ASSOCIATED WITH THE NORTHERN BRITISH COLUMBIA OIL AND NATURAL GAS ASSETS ACQUIRED FROM CALPINE CANADA NATURAL GAS PARTNERSHIP BY PENGROWTH CORPORATION

											Six Months Ended
		Years Ended December 31,									June 30,
		1999			2000			2001			2001			2002
		(In thousands of dollars)
											(Unaudited)
REVENUE
	Oil and gas sales	$	98,403		$	203,483		$	191,253		$	120,778		$	81,474
	Royalties		(20,335	)		(46,999	)		(43,593	)		(28,010	)		(17,679	)
			78,068			156,484			147,660			92,768			63,795
Operating Expenses			15,916			19,079			21,080			10,186			10,561
Excess of revenue over expenses		$	62,152		$	137,405		$	126,580		$	82,582		$	53,234

See accompanying notes to schedule of revenue and expenses.

F-52

NOTES TO THE SCHEDULE OF REVENUE AND EXPENSES ASSOCIATED WITH THE NORTHERN BRITISH COLUMBIA OIL AND NATURAL GAS ASSETS ACQUIRED FROM THE CALPINE CANADA NATURAL GAS PARTNERSHIP BY PENGROWTH CORPORATION

Six month period ended June 30, 2002 (unaudited), and each of the years in the

three year period ended December 31, 2001

1.     Basis of Presentation

     For purposes of these financial statements “Pengrowth” refers to both Pengrowth Energy Trust (“EnergyTrust”) and Pengrowth Corporation. On October 1, 2002 Pengrowth acquired substantially all of the oil and natural gas assets in northern British Columbia held by Calpine Canada Natural Gas Partnership (“Calpine”). On October 4, 2002 Pengrowth sold a portion of the assets acquired from Calpine to Progress Energy Ltd.

     The Schedule has been prepared by Pengrowth based on information received from Calpine.

     The Schedule includes only those revenues, royalties and expenses directly related to the interest in the northern British Columbia oil and natural gas assets acquired from Calpine in the British Columbia assets less the revenues, royalties and expenses directly related to the oil and natural gas assets that were sold to Progress Energy Ltd., on October 4, 2002. It does not include any expenses related to general and administrative costs, interest expense, income and capital taxes or any provisions related to depreciation, depletion or site restoration and abandonments.

     The Schedule may not be indicative of the future revenues and expenses from the properties.

2.     Significant Accounting Policies

     (a) Revenue recognition:

     Oil, natural gas and natural gas liquids sales are recorded at the time the product is delivered and sold.

     (b) Operating Expenses:

     Operating expenses include all costs related to the lifting, gathering and processing of oil and natural gas.

3. Reconciliation of Statement to United States Generally Accepted Accounting Principles

     There are no significant differences between Canadian and United States generally accepted accounting principles for this financial statement.

F-53

PENGROWTH ENERGY TRUST

Trust Units

PROSPECTUS

October             , 2002

LEHMAN BROTHERS

RBC CAPITAL MARKETS

UBS WARBURG

MCDONALD INVESTMENTS INC.

RAYMOND JAMES

[Lehman Brothers Watermark]

ALTERNATE CANADIAN PAGE

This preliminary short form prospectus is a base PREP prospectus. No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise.

A copy of this preliminary short form prospectus has been filed with the securities regulatory authorities in each of the provinces of Canada but has not yet become final for the purpose of the sale of securities. Information contained in this preliminary short form prospectus may not be complete and may have to be amended. The securities may not be sold until a receipt for the short form prospectus is obtained from the securities regulatory authorities.

This short form prospectus has been filed under procedures in each of the provinces of Canada that permit certain information about these securities to be determined after the short form prospectus has become final and that permit the omission of that information from this short form prospectus. The procedures require the delivery to purchasers of a supplemental PREP short form prospectus containing the omitted information within a specified period of time after agreeing to purchase any of these securities.

PRELIMINARY SHORT FORM BASE PREP PROSPECTUS DATED OCTOBER 16, 2002

New Issue l, 2002

PENGROWTH ENERGY TRUST

Cdn$250,000,000

Trust Units

This is a public offering of trust units of Pengrowth Energy Trust. We are offeringl trust units. RBC Dominion Securities Inc., as lead underwriter, BMO Nesbitt Burns Inc., CIBC World Markets Inc., TD Securities Inc., National Bank Financial Inc., Scotia Capital Inc., UBS Bunting Warburg Inc., HSBC Securities (Canada) Inc., Canaccord Capital Corporation, Raymond James Ltd., Dundee Securities Corporation and FirstEnergy Capital Corp. are offering the trust units in each province of Canada and Lehman Brothers Inc., RBC Dain Rauscher Inc., UBS Warburg LLC, McDonald Investments Inc. and Raymond James & Associates, Inc. are offering the trust units in the United States. Our outstanding trust units are listed and posted for trading on the Toronto Stock Exchange under the symbol PGF.UN and on the New York Stock Exchange under the symbol PGH. On October 15, 2002, the closing price of the trust units was Cdn$14.78 on the Toronto Stock Exchange and US$9.34 on the New York Stock Exchange.

Pengrowth Energy Trust is a publicly traded oil and gas royalty trust created in 1988 that is governed by the laws of the Province of Alberta, Canada. Pengrowth Energy Trust is not a trust company and is not registered under legislation governing trust companies as it does not carry on, or intend to carry on, the business of a trust company. Our trust units are not “deposits” within the meaning of theCanada Deposit Insurance Corporation Actand are not insured under the provisions of that act or any other legislation.

Investing in our trust units involves certain risks. See “Risk Factors” beginning on page 19.

Owning our trust units may subject you to tax consequences. You should read the tax discussion under “Certain Income Tax Considerations”. You should also consult your tax advisor.

Distributions by Pengrowth Energy Trust are payable on the 15th day of each month to unitholders of record on the 10th business day preceding payment. Subscribers for trust units will be eligible to receive distributions commencing December 15, 2002.

In the opinion of counsel, our trust units are, as of the date hereof, qualified investments under theIncome Tax Act(Canada) for trusts governed by registered retirement savings plans (RRSPs), registered retirement income funds (RRIFs), registered education savings plans (RESPs) and deferred profit sharing plans (DPSPs) and are eligible for investment under certain statutes as set out under “Eligibility for Investment”.

Price: Cdn$              per Trust Unit

			Underwriting	Net Proceeds to
	Offering		Discounts and	Pengrowth Energy
	Price		Commissions	Trust(1)
Per trust unit(2)	$		$	$
Total(3)	$	250,000,000	$	$

(1)	Before deducting expenses of the issue estimated at $l, which will be paid from the general funds of Pengrowth Energy Trust.
(2)	For trust units sold in the United States, the offering price is payable in U.S. dollars at the approximate U.S. dollar equivalent of the Canadian dollar offering price based on the inverse of the noon buying rate of the Federal Reserve Bank of New York on  l , 2002 of US$ l per Cdn$1.00. For trust units sold in the United States, the offering price is payable in U.S. dollars.
(3)	Pengrowth Energy Trust has granted to the underwriters an over-allotment option to purchase up to an additionall trust units on the same terms as described above, exercisable in whole or in part for a period of 30 days from the date of closing, solely to cover over-allotments, if any. If the underwriters exercise the over-allotment option in full, the total offering price, underwriting discounts and commissions and net proceeds to Pengrowth Energy Trust will be $287,500,000, $l and $l, respectively. This prospectus also qualifies the grant of the over-allotment option and the distribution of any trust units that are issued pursuant to the exercise of the over-allotment option.

ALTERNATE CANADIAN PAGE

TABLE OF CONTENTS

	Page
Important Terms Used in this Prospectus		iv
Exchange Rate Table		vi
Presentation of our Financial Information		1
Presentation of our Reserve Information		2
Forward-Looking Statements		3
Summary		4
Risk Factors		20
Recent Acquisition		30
Distributions		33
Price Range and Trading Volume of Trust Units		35
Use of Proceeds		36
Capitalization of Pengrowth Trust		36
Selected Financial Information		38
Management’s Discussion and Analysis of Operating Results and Financial Condition		41
Business		53
Structure and Organization of Pengrowth		77
Directors and Officers		84
Corporate Governance and Conflicts of Interest		88
Certain Income Tax Considerations		91
ERISA Considerations		104
Underwriting		106
Relationship Between Pengrowth Corporation and Certain Underwriters		110
Documents Incorporated by Reference		112
Available Information		113
Documents filed as part of the U.S. Registration Statement		113
Auditors, Transfer Agent and Registrar		113
Eligibility for Investment		114
Legal Matters		114
Purchaser’s Statutory Rights		114
Index to Financial Statements		F-1
Certificates of Pengrowth		C-1
Certificate of the Underwriters		C-2

PRESENTATION OF OUR FINANCIAL INFORMATION

     Unless we indicate otherwise, financial information in this prospectus has been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”).Canadian GAAP differs in some significant respects from U.S. GAAP and thus our financial statements may not be comparable to the financial statements of U.S. companies. The principal differences as they apply to us are summarized in note 13 to the audited annual consolidated financial statements of Pengrowth Trust beginning on page F-24, the Reconciliation of Interim Consolidated Financial Statements of Pengrowth Energy Trust for the six months ended June 30, 2002 to United States generally accepted accounting principles beginning on page F-19, note 4 to the unaudited pro forma consolidated financial statements of Pengrowth Energy Trust beginning on page F-2, and note 3 to the Schedule of Revenue and Expenses beginning on page F-50.

     We present our financial information in Canadian dollars. In this prospectus, except where we indicate otherwise, all dollar amounts are in Canadian dollars.References to “$” or “Cdn$” are to Canadian dollars and references to “US$” are to U.S. dollars. This prospectus contains a translation of some Canadian dollar amounts into U.S. dollars at specified exchange rates solely for your convenience. Unless we indicate otherwise, U.S. dollar amounts have been translated from Canadian dollars at US$0.6306 per Cdn$1.00, which was the inverse of the noon buying rate of the Federal Reserve Bank of New York on October 15, 2002.

     The pro forma consolidated balance sheet was prepared as if the (i) acquisition of the B.C. Asset Package, (ii) the disposition of a portion of the B.C. Asset Package to Progress Energy Ltd., (iii) the issuance of 17,123,287 trust units for net proceeds of $234.25 million in this offering, and (iv) the other transactions described in the notes to the pro forma financial statements, had occurred on June 30, 2002 and the pro forma combined statements of income and distributable income for the year ended December 31, 2001 and for the six months ended June 30, 2002 were prepared as if such transactions had occurred on the first day of the period presented.

1

ALTERNATE CANADIAN PAGE

PURCHASER’S STATUTORY RIGHTS

     Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces the securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that such remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province for the particulars of these rights or consult with a legal adviser.

114

ALTERNATE CANADIAN PAGE

CERTIFICATES OF PENGROWTH

Dated: October 16, 2002

     This short form prospectus, together with the documents and information incorporated herein by reference, will, as of the date of the supplemented prospectus providing the information permitted to be omitted from this prospectus, constitute full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required under securities legislation of each of the provinces of Canada. For the purpose of the Province of Québec, this simplified prospectus, as supplemented by the permanent information record, will as of the date of the supplemented prospectus contain no misrepresentation likely to affect the value or the market price of the securities to be distributed.

PENGROWTH ENERGY TRUST

By: Pengrowth Management Limited, as Manager

(Signed) JAMES S. KINNEAR	(Signed) GORDON M. ANDERSON
President & Chief Executive Officer	Vice President, Financial Services

On behalf of the Board of Directors

(Signed) JAMES S. KINNEAR	(Signed) GREGORY S. FLETCHER
Director	Director

By: Pengrowth Corporation, as Administrator

(Signed) JAMES S. KINNEAR	(Signed) ROBERT B. HODGINS
President & Chief Executive Officer	Chief Financial Officer

On behalf of the Board of Directors

(Signed) FRANCIS G. VETSCH	(Signed) JOHN B. ZAOZIRNY
Director	Director

C-1

ALTERNATE CANADIAN PAGE

CERTIFICATE OF THE UNDERWRITERS

Dated: October 16, 2002

     To the best of our knowledge, information and belief, this short form prospectus, together with the documents incorporated herein by reference, will, as of the date of the supplemented prospectus providing the information permitted to be omitted from this prospectus, constitute full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required under securities legislation of each of the provinces of Canada. For the purpose of the Province of Québec, to our knowledge, this simplified prospectus, as supplemented by the permanent information record, will as the date of the supplemented prospectus contain no misrepresentation likely to affect the value or the market price of the securities to be distributed.

RBC DOMINION SECURITIES INC.

By: (Signed) BRIAN K. PETERSEN

BMO NESBITT BURNS INC.

By: (Signed) SHANE C. FILDES

CIBC WORLD MARKETS INC.

By: (Signed) BRENDA A. MASON

TD SECURITIES INC.

By: (Signed) DREW E. MACINTYRE

NATIONAL BANK FINANCIAL INC.	SCOTIA CAPITAL INC.	UBS BUNTING WARBURG INC.
By: (Signed) L. TREVOR ANDERSON	By: (Signed) ERIC MCFADDEN	By: (Signed) STEVEN A. LATIMER

HSBC SECURITIES (CANADA) INC.

By: (Signed) ROD A. MCISAAC

CANACCORD CAPITAL CORPORATION	RAYMOND JAMES LTD.
By: (Signed) STEPHEN J. MULLIE	By: (signed) NAVEEN DARGAN
DUNDEE SECURITIES CORPORATION	FIRSTENERGY CAPITAL CORP.
By: (Signed) DAVID G. ANDERSON	By: (Signed) JOHN S. CHAMBERS

C-2

ALTERNATE CANADIAN PAGE

PART II

INFORMATION NOT REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS

     TheBusiness Corporations Act(Alberta) provides that a corporation may, in certain circumstances, indemnify a director or officer of the corporation, a former director or officer of the corporation, a person who acts or acted at the corporation’s request as a director or officer of a body corporate of which the corporation is or was a shareholder or creditor and the heirs and legal representatives of any such persons (collectively, “Indemnified Persons”) against all costs, charges and expenses incurred by any such Indemnified Person in respect of any civil, criminal or administrative proceedings to which he is made a party by reason of being or having been a director or officer of the corporation or other body corporate, if (a) he acted honestly and in good faith with a view to the best interests of the corporation, and (b) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, he had reasonable grounds for believing that his conduct was lawful.

     The by-laws of Pengrowth Corporation and Pengrowth Management Limited (“Pengrowth Management”), respectively, provide that it shall indemnify Indemnified Persons of Pengrowth Corporation and Pengrowth Management, respectively, in the manner contemplated by theBusiness Corporations Act (Alberta).

     As contemplated by Section 124(4) of theBusiness Corporations Act (Alberta), Pengrowth Corporation and Pengrowth Management, respectively, has purchased insurance against potential claims against the directors and officers of Pengrowth Corporation and Pengrowth Management, respectively, and against loss for which Pengrowth Corporation and Pengrowth Management, respectively, may be required or permitted by law to indemnify such directors and officers.

     Pursuant to the Amended and Restated Management Agreement (the “Management Agreement”) dated April 23, 2002 among Pengrowth Corporation, Pengrowth Energy Trust, Computershare Trust Company of Canada and Pengrowth Management, Pengrowth Management and these persons having served as a director, officer or employee thereof shall be indemnified by Pengrowth Corporation (out of its assets and out of the royalty provided for in the Amended and Restated Royalty Indenture dated April 23, 2002 between Pengrowth Corporation and Computershare Trust Company of Canada, as trustee) for all liabilities and expenses arising from or in any matter related to the Management Agreement, so long as the party seeking such indemnification shall not be adjudged liable for or guilty of willful misfeasance, bad faith, gross negligence or reckless disregard of duty to Pengrowth Corporation or Pengrowth Energy Trust, and shall not be adjudged to be in breach of any material covenants and duties of Pengrowth Management under the Management Agreement.

     Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the Registrant pursuant to the foregoing provisions, the Registrant has been informed that in the opinion of the of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

EXHIBITS

Exhibit
No.		Description
	3.1	Form of Underwriting Agreement.†
	3.2	Comfort letter of KPMG LLP, Chartered Accountants, to the Canadian securities regulatory authorities.†
	4.1	Renewal Annual Information Form dated May 17, 2002.
	4.2	Management’s Discussion and Analysis for the year ended December 31, 2001 contained on pages 32 to 43, inclusive, of the 2001 Annual Report.*
	4.3	Comparative financial statements for the year ended December 31, 2001, together with the report of the auditors thereon, contained on pages 45 to 61 of the 2001 Annual Report.
	4.4	Comparative financial statements for the year ended December 31, 2000 together with the report of the auditors thereon, contained on pages 50 to 60 of the 2000 Annual Report.**
	4.5	Information Circular — Proxy Statement dated March 15, 2002 for the Special and Annual Meeting of Trust Unitholders held on April 23, 2002 (excluding those portions which, in accordance with National Instrument 44-101 (Canada), need not be incorporated by reference).
	4.6	Management’s Discussion and Analysis for the six month period ended June 30, 2002.
	4.7	Comparative financial statements for the six month periods ended June 30, 2002 and June 30, 2001.
	4.8	Material Change Report dated September 26, 2002 relating to the acquisition of the New B.C. Properties.
	5.1	Consents of Gilbert Laustsen Jung Associates Ltd.††
	5.2	Consents of KPMG LLP, Chartered Accountants.††
	5.3	Awareness Letter of KPMG LLP
	5.4	Consents of Bennett Jones LLP.††
	5.5	Consents of Fraser Milner Casgrain LLP.††
	5.6	Consents of Carter, Ledyard & Milburn.††
	7.1	Amended and Restated Trust Indenture dated April 23, 2002.
	7.2	Amended and Restated Royalty Indenture dated April 23, 2002.
	7.3	Amended and Restated Management Agreement dated April 23, 2002.
	7.4	Amended and Restated Unanimous Shareholder Agreement dated April 23, 2002.

†	To be filed by amendment.
*	Incorporated by reference from Registrant’s Annual Report on Form 40-F filed with the Securities and Exchange Commission.
**	Incorporated by reference from Registrant’s registration statement on Form 40-F filed with the Securities and Exchange Commission.
††	Consents filed with the Canadian securities regulatory authorities to be filed by amendment.

PART III

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Item 1.     Undertaking

     The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities registered pursuant to Form F-10 or to transactions in said securities.

Item 2.     Consent to Service of Process

     (a) The Registrant is filing herewith an Irrevocable Consent and Power of Attorney on Form F-X.

     (b) Any changes to the name or address of the agent for service of the Registrant or the trustee shall be communicated promptly to the Commission by amendment to Form F-X referencing the file number of the relevant registration statement.

SIGNATURES

     Pursuant to the requirements of the Securities Act, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing Form F-10 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Alberta, Canada, on October      , 2002.

PENGROWTH ENERGY TRUST

By:	Pengrowth Corporation, Administrator
By:	/s/ JAMES S. KINNEAR

James S. Kinnear

President

POWER OF ATTORNEY

     Each person whose signature appears below hereby constitutes James S. Kinnear, Robert B. Hodgins and Charles V. Selby, and each of them singly, his true and lawful attorneys-in-fact with full power to sign on behalf of such person, in the capacities indicated below, any and all amendments to this registration statement and any subsequent related registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, and generally to do all such things in the name and on behalf of such person, in the capacities indicated below, to enable the Registrant to comply with the provisions of the Securities Act of 1933 and all requirements of the Securities and Exchange Commission thereunder, hereby ratifying and confirming the signature of such person as it may be signed by said attorneys-in-fact, or any of them, on any and all amendments to this registration statement or any such subsequent related registration statement.

     Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities* and on the dates indicated.

Signature	Capacity	Date
/s/ JAMES S. KINNEAR James S. Kinnear	President, Chief Executive Officer and Director (Principal executive officer)	October   , 2002
/s/ ROBERT B. HODGINS Robert B. Hodgins	Chief Financial Officer (Principal financial officer)	October   , 2002
/s/ CHRISTOPHER G. WEBSTER Christopher G. Webster	Treasurer (Principal accounting officer)	October   , 2002
/s/ THOMAS A. CUMMING Thomas A. Cumming	Director	October   , 2002

* The Registrant is a trust and the persons (other than the Authorized Representative in the United States) are signing in their capacities as officers or directors of Pengrowth Corporation, the administrator of the Registrant.

Signature	Capacity	Date
/s/ MICHAEL A. GRANDIN Michael A. Grandin	Director	October 16, 2002
/s/ FRANCIS G. VETSCH Francis G. Vetsch	Director	October 16, 2002
/s/ STANLEY H. WONG Stanley H. Wong	Director	October 16, 2002
/s/ JOHN B. ZAOZIRNY John B. Zaozirny	Director	October 16, 2002
/s/ JAMES S. KINNEAR James S. Kinnear	Authorized Representative in the United States	October 16, 2002

INDEX TO EXHIBITS

Exhibit
No.		Description
	3.1	Form of Underwriting Agreement.†
	3.2	Comfort letter of KPMG LLP, Chartered Accountants, to the Canadian securities regulatory authorities.†
	4.1	Renewal Annual Information Form dated May 17, 2002.
	4.2	Management’s Discussion and Analysis for the year ended December 31, 2001 contained on pages 32 to 43, inclusive, of the 2001 Annual Report.*
	4.3	Comparative financial statements for the year ended December 31, 2001, together with the report of the auditors thereon, contained on pages 45 to 61 of the 2001 Annual Report.
	4.4	Comparative financial statements for the year ended December 31, 2000 together with the report of the auditors thereon, contained on pages 50 to 60 of the 2000 Annual Report.**
	4.5	Information Circular — Proxy Statement dated March 15, 2002 for the Special and Annual Meeting of Trust Unitholders held on April 23, 2002 (excluding those portions which, in accordance with National Instrument 44-101 (Canada), need not be incorporated by reference).
	4.6	Management’s Discussion and Analysis for the six month period ended June 30, 2002.
	4.7	Comparative financial statements for the six month periods ended June 30, 2002 and June 30, 2001.
	4.8	Material Change Report dated September 26, 2002 relating to the acquisition of the New B.C. Properties.
	5.1	Consents of Gilbert Laustsen Jung Associates Ltd.††
	5.2	Consents of KPMG LLP, Chartered Accountants.††
	5.3	Awareness Letter of KPMG LLP
	5.4	Consents of Bennett Jones LLP.††
	5.5	Consents of Fraser Milner Casgrain LLP.††
	5.6	Consents of Carter, Ledyard & Milburn.††
	7.1	Amended and Restated Trust Indenture dated April 23, 2002.
	7.2	Amended and Restated Royalty Indenture dated April 23, 2002.
	7.3	Amended and Restated Management Agreement dated April 23, 2002.
	7.4	Amended and Restated Unanimous Shareholder Agreement dated April 23, 2002.

†	To be filed by amendment.
*	Incorporated by reference from Registrant’s Annual Report on Form 40-F filed with the Securities and Exchange Commission.
**	Incorporated by reference from Registrant’s registration statement on Form 40-F filed with the Securities and Exchange Commission.
††	Consents filed with the Canadian securities regulatory authorities to be filed by amendment.