U.S. SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, D.C. 20549
 FORM 40-F/A
 AMENDMENT NO. 1
 o
    
    REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934.þ
    
    ANNUAL REPORT PURSUANT TO SECTION13(a)OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended: December 31, 2007 Commission File Number: 1-31253
 PENGROWTH ENERGY TRUST
 Alberta, Canada
 1311
(Primary Standard Industrial
Classification Code Number)
    
    None
(I.R.S. Employer
Identification Number)
 Suite 2100, 222 Third Avenue S.W.
Calgary, Alberta Canada T2P 0B4
(403) 233-0224
 CT Corporation System
111-8 th Avenue, New York, New York 10011
 (212) 894-8940
  Brad D. Markel
Bennett Jones LLP
4500 Bankers Hall East
855 
2ndStreet SW
Calgary, Alberta T2P 4K7 Canada
(403) 298-3100
    
    Andrew J. Foley
Paul, Weiss, Rifkind, Wharton & Garrison LLP
1285 Avenue of the Americas
New York, New York 10019-6064 USA
(212) 373-3000
 Securities registered or to be registered pursuant to Section 12(b) of the Act.
 Title of each class
Trust Units
    
    Name of each exchange on which registered
New York Stock Exchange
 Securities registered or to be registered pursuant to Section 12(g) of the Act.
 None
 Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
 None
  þ   Annual information form
    
    o   Audited annual financial statements
    Yes   o
    
    No   þ
  Yes   þ
    
    No   o




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##### 



EXPLANATORY NOTE
   DOCUMENTS FILED AS PART OF THIS AMENDMENT
  Appendix
    
    DocumentsA
    
    Pengrowth Energy Trust Revised Annual Information Form for the year ended December 31, 2007.B*
    
    Managements Discussion and Analysis.C*
    
    Consolidated Financial Statements of Pengrowth Energy Trust, including Managements Report
to Unitholders, the Auditors Reports and note 23 thereof which includes a reconciliation
of the Consolidated Financial Statements to United States generally accepted accounting
principles.D*
    
    Comments by Auditors for U.S. Readers on Canada  U.S. Reporting Differences.E*
    
    Oil and Gas Producing Activities Prepared in Accordance with SFAS No. 69  Disclosures
about Oil and Gas Producing Activities.F*
    
    Pengrowth Energy Trust Code of Business Conduct and Ethics dated February 19, 2008.
  CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES
 Certifications




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##### 



UNDERTAKING
  CONSENT
TO SERVICE OF PROCESS




---



##### 



EXHIBITS
  ExhibitNumber
    
    Description1
    
    Consent of GLJ Petroleum Consultants Ltd.2
    
    Certification of the CEO pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code.3
    
    Certification of the CFO pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code.4
    
    Certification of the CEO pursuant to Rule 13a-14(a) of the Exchange Act.5
    
    Certification of the CFO pursuant to Rule 13a-14(a) of the Exchange Act.




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##### 



SIGNATURES
  Date: September 15, 2008
    PENGROWTH ENERGY TRUST
by its Administrator
PENGROWTH CORPORATIONBy:

/s/  James S. KinnearJames S. KinnearChairman, President and
Chief Executive Officer




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##### 



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




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##### 



PENGROWTH ENERGY TRUST
 REVISED ANNUAL INFORMATION FORM
For the year ended December 31, 2007
 March 19, 2008
(except for pages 37, 40 and 51 which are as of September 15, 2008)




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##### 



TABLE OF CONTENTS
 GLOSSARY OF TERMS AND ABBREVIATIONS
    
    
    1Corporate
    
    
    1Engineering
    
    
    2Abbreviations
    
    
    3CONVERSION
    
    
    4PRESENTATION OF OUR FINANCIAL INFORMATION
    
    
    5PRESENTATION OF OUR RESERVE INFORMATION
    
    
    5FORWARD-LOOKING STATEMENTS
    
    
    5PENGROWTH ENERGY TRUST
    
    
    7Introduction
    
    
    7The Trust
    
    
    7The Corporation
    
    
    7The Trusts Subsidiaries
    
    
    7The Corporations Subsidiaries
    
    
    8The Manager
    
    
    8Intercorporate Relationships
    
    
    8Business Strategy and Strengths
    
    
    9SIFT Legislation Considerations
    
    
    11GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST
    
    
    12Recent Developments
    
    
    12Historical Developments
    
    
    17Trends
    
    
    19PENGROWTH MANAGEMENT LIMITED
    
    
    20Business
    
    
    20Management Agreement
    
    
    20Bonus Pool
    
    
    22Management Agreement Second Term
    
    
    22PENGROWTH  OPERATIONAL INFORMATION
    
    
    23Principle Properties
    
    
    23Light Oil Properties
    
    
    24Heavy Oil Properties
    
    
    27Conventional Gas Properties
    
    
    28Shallow Gas Properties
    
    
    31Offshore Gas Properties
    
    
    33Statement of Oil and Gas Reserves and Reserves Data
    
    
    35Additional Information Relating to Reserves Data
    
    
    45Future Development Costs
    
    
    47Finding, Development and Acquisition Costs
    
    
    47Future Development Capital
    
    
    48Other Oil and Gas Information
    
    
    49Additional Information Concerning Abandonment & Reclamation Costs
    
    
    50Costs Incurred
    
    
    51Exploration and Development Activities
    
    
    51Production Estimates
    
    
    51Production History (Netback)
    
    
    52Replacement of Properties
    
    
    53TRUST UNITS
    
    
    54The Trust Indenture
    
    
    54The Trustee
    
    
    54Stock Exchange Listings
    
    
    55Ownership Restrictions
    
    
    55Redemption Right
    
    
    55




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




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CONFLICTS OF INTEREST
    
    
    99LEGAL PROCEEDINGS
    
    
    100INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    
    
    100INTERESTS OF EXPERTS
    
    
    100AUDITORS, TRANSFER AGENT AND REGISTRAR
    
    
    100MATERIAL CONTRACTS
    
    
    100CODE OF ETHICS
    
    
    101OFF-BALANCE SHEET ARRANGEMENTS
    
    
    101DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
    
    
    101ADDITIONAL INFORMATION
    
    
    102
 Appendix A  Report on Reserves Data by Independent Qualified Reserves Evaluator on Form 51-102F2
 Appendix B  Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3
 Appendix C  Audit Committee Terms of Reference
 Unless otherwise indicated, all
of the information provided in this Annual Information Form is as at December 31, 2007.
 - iv -




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##### 



GLOSSARY OF TERMS AND ABBREVIATIONS
  Corporate
 Board Board of Directors
 Canada-U.S. Convention Canada-United States Tax Convention, 1980
 Computershare
 Corporation
 CP Acquisition
 Credit Facility General Development of Pengrowth Energy
Trust  Recent Developments  Borrowing
 Debenture
 Debenture Indenture
 Manager
 Pengrowth we us and our
 Protocol
 Royalty Indenture
 Royalty Unitholder
 Royalty Units
 SIFT Legislation Certain Canadian Federal Income Tax Considerations
 Trust
 Trust Indenture
 Trust Units
 Unitholders




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##### 



Engineering
 Company Interest
 Developed Non-Producing Reserves
 Developed Producing Reserves
 Developed Reserves
 GLJ
 GLJ Report
 Gross
 Net
 Probable Reserves
 Proved Reserves
 Remaining Reserve Life
 Reserve Life Index
 Reserves
 - 2 -




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##### 



Royalty Interest
 Total Proved Plus Probable Reserves
 Undeveloped Reserves
 Working Interest
 Abbreviations
 API
 o API
 bbl bbls Mbbls MMbbls
 bblpd
 boe Mboe MMboe
 boepd
 CBM
 EDGAR
 GAAP Canadian GAAP
 $M $MM
 MMBtu MMBtupd
 Mcf MMcf bcf tcf
 Mcfpd MMcfpd
 NGLs
 NYSE
 P+P
 SAGD
 - 3 -




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##### 



SEC
 SEDAR
 SIFT Legislation
 Tax Act Income Tax Act
 TSX
 WTI
 Disclosure provided herein in respect of a boe may be misleading, particularly if used in
isolation. A boe conversation ratio of six Mcf of natural gas to one barrel of crude oil
equivalent is based on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.
 CONVERSION
  To Convert From
    
    To
    
    Multiply byMcf
    
    cubic metre
    
    
    28.174cubic metre
    
    cubic feet
    
    
    35.494bbls
    
    cubic metre
    
    
    0.159cubic metre
    
    bbls
    
    
    6.29feet
    
    metre
    
    
    0.305metre
    
    feet
    
    
    3.281miles
    
    kilometre
    
    
    1.609kilometre
    
    miles
    
    
    0.621acres
    
    hectares
    
    
    0.405hectares
    
    acres
    
    
    2.471
  - 4 -




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##### 



PRESENTATION OF OUR FINANCIAL INFORMATION
  PRESENTATION OF OUR RESERVE INFORMATION
 Standards of Disclosure for Oil and Gas Activities Risk Factors  Canadian and United States practices differ in
reporting reserves and production and our estimates may not be comparable to those of companies in
the United States
 FORWARD-LOOKING STATEMENTS
 Private Securities Litigation Reform Act of 1995
 - 5 -




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Risk Factors Business
Risks
  - 6 -




---



##### 



PENGROWTH ENERGY TRUST
 Introduction
  The Trust
   The Corporation
   Exchangeable Shares
 The Trusts Subsidiaries
  - 7 -




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##### 



General Development of Pengrowth Energy Trust  Historical Developments
 The Corporations Subsidiaries
  General Development of Pengrowth Energy Trust  Historical
Developments
 General Development of Pengrowth Energy Trust  Recent Developments  CP Acquisition
 The Manager
  Pengrowth Management Limited
 Intercorporate Relationships
  - 8 -




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##### 



Business Strategy and Strengths
 2
  - 9 -




---



##### 



Acquisitions
 
    
    Acquisitions should be accretive on a per Trust Unit basis based upon current
forecast parameters. In determining whether an acquisition is accretive, we examine
the profile of production, operating costs, capital costs, abandonment expenses and
other key variables and compare that with our existing asset base to understand the
impact over time in terms of production, reserves and distributions on a per Trust Unit
basis.
    
    The undiscounted aggregate projected future net cash flow from the properties should
exceed the aggregate purchase price of the properties and provide a reasonable rate of
return.
    
    Properties to be acquired should be high quality, relatively long life and proven
producing properties. Pengrowth gives priority to properties with:
 o
    
    low anticipated capital expenditures relative to the cash
generation potential of the properties;o
    
    relatively low operating costs or high netbacks;o
    
    experienced, well regarded industry operators or where
operatorship may be assumed by Pengrowth;o
    
    favourable production history;o
    
    upside potential through infill drilling, improved field
operations and other development activities;o
    
    potential synergies with our current properties and areas of our core expertise; ando
    
    low environmental and site remediation risk.
 
    
    Each purchase of new properties must be based on an independent engineering report
except for properties where the purchase price is less than $5 million.
 Development
 
    
    Development investments should provide a high rate of return and provide production
within a short period of time, or be necessary to maintain existing production
operations. Pengrowth prioritizes its development investments based on:
 o
    
    rate of return;o
    
    timing of production;o
    
    potential for continued development; ando
    
    those investments necessary to maintain existing facilities and wells.
 Certain Canadian Federal Income Tax Considerations Risk
Factors  SIFT
Legislation is expected to materially and adversely affect the Trust, the Unitholders and the value
of the Trust Units
 - 10 -




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##### 



SIFT Legislation Considerations
     - 11 -




---



##### 



GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST
 Recent Developments
 2008 Forecast Capital, Production and Operating Costs
  General Development of Pengrowth
Energy Trust  Recent Developments  At-the-Market Equity Distribution Program
  Planned Capital Expenditures
    
    ($ millions)
    
    (% of Total)Drilling and Completions
    
    $
    281
    
    
    
    80
    %Plant and Facilities
    
    $
    44
    
    
    
    12
    %Land and Seismic
    
    $
    25
    
    
    
    7
    %Other (e.g.,
CO2 Pilot)
    
    $
    5
    
    
    
    1
    %Total Development Capital
    
    $
    355
    
    
    
    100
    %Long Term Investments (Lindbergh, Building, IT)
    
    $
    32Total Capital
    
    $
    387Average Daily Production Volume (boepd)
    
    80,000 - 82,000 (1)Operating Costs (per boe)
    
    $
    13.20
    (2)General and Administrative Costs (per boe)
    
    $
    2.20
    (3)
 Notes:
 (1)
    
    The 2008 estimate excludes potential additions through acquisitions.(2)
    
    Assuming production targets for 2008 are achieved.(3)
    
    Includes management fees of approximately $0.40 per boe.
 Asset Rationalization Program
  At-the-Market Equity Distribution Program
  - 12 -




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##### 



Changes to Royalty Legislation Affecting Pengrowth and its Unitholders
   ad valorem
     - 13 -




---



##### 



Risk Factors  Changes in
government regulations that affect the crude oil and natural gas industry could adversely affect
Pengrowth and reduce our distributions to our Unitholders
 Pengrowths production, reserves and future net revenues associated therewith contained in this
Annual Information Form do not reflect the impact of the proposed changes discussed above.
 Taxability of Distributions Paid to U.S. Residents
  Senior Unsecured Notes
  General
Development of Pengrowth Energy Trust  Historical Developments Distributions  Restrictions on
Distributions
 General Development of Pengrowth Energy Trust  Historical Developments Risk Factors  Our indebtedness may limit the amount of distributions that we are able to pay
our Unitholders, and if we default on our debts, the net proceeds of any foreclosure sale would be
allocated to the
 - 14 -




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##### 



repayment of our lenders, note holders and other creditors and only the remainder, if any, would be
available for distribution to our Unitholders.
 U.S. DRIP
  Changes to Tax Legislation Affecting Pengrowth and its Unitholders and Debentureholders
 Certain Canadian Federal Income Tax Considerations Risk
Factors  The SIFT Legislation is expected to materially and adversely affect the Trust, the
Unitholders and the value of the Trust Units
  Greenhouse Gas Emissions
  - 15 -




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##### 



Borrowing
  Distributions
 Restrictions on Distributions
 Risk Factors  Our indebtedness may limit the amount of distributions that
we are able to pay our Unitholders, and if we default on our debts, the net proceeds of any
foreclosure sale would be allocated to the repayment of our lenders, note holders and other
creditors and only the remainder, if any, would be available for distribution to our Unitholders.
 CP Acquisition
     - 16 -




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Historical Developments
    Trust Units  Redemption Right Trust Units  Conversion
Rights
   Business Corporations Act
 - 17 -




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- 18 -




---



##### 



Trends
    - 19 -




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Managements Discussion and Analysis  Outlook
 PENGROWTH MANAGEMENT LIMITED
 Business
  Management Agreement
   
    
    two distinct three-year terms with a declining fee structure in the second three year term;
    
    a base fee determined on a sliding scale:
 o
    
    in the first three year contract term:
 §
    
    two percent of the first $200 million of Income; and§
    
    one percent of the balance of Income over $200 million; and
 o
    
    in the second three year contract term:
 §
    
    1.5 percent of the first $200 million of Income; and§
    
    0.5 percent of the balance of Income over $200 million.
  
    
    a performance based fee based on total returns received by Unitholders which
essentially compensates the Manager for total annual returns which average in excess of
eight percent per annum over a three year period;
 - 20 -




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##### 




    
    a ceiling on total fees payable determined in reference to a percentage of the fees
paid under the previous management agreement: 80 percent each year in the first three
year contract term and 60 percent each year in the second three year contract term and
subject to a further ceiling essentially equivalent to $12 million annually during the
second three year contract term;
    
    requirement for the Manager to pay certain expenses of the Corporation and the Trust
of approximately $2 million per year;
    
    an annual minimum management fee of $3.6 million comprised of $1.6 million of
management fees and $2.0 million of expenses;
    
    key man provisions in respect of James S. Kinnear, the President of the Manager;
    
    an annual bonus pool based on 10 percent of the Managers base fee and performance
fee for employees of, and special consultants to, the Corporation; and
    
    an optional buyout of the Management Agreement at the election of the Board of
Directors upon the expiry of the first three year contract term with a termination
payment of approximately 2/3 of the management fee paid during the first three year
contract term plus expenses of termination.
  
    
    reviewing and negotiating acquisitions for the Corporation and the Trust;
    
    providing written reports to the Board of Directors to keep the Corporation fully
informed about the acquisition, exploration, development, operation and disposition of
properties, the marketing of petroleum substances, risk management practices and
forecasts as to market conditions;
    
    supervising the Corporation in connection with it acting as operator of certain of
its properties;
    
    arranging for, and negotiating on behalf of, and in the name of, the Corporation all
contracts with third parties for the proper management and operation of the properties
of the Corporation;
    
    supervising, training and providing leadership to the employees and consultants of
the Corporation and assisting in recruitment of key employees of the Corporation;
    
    arranging for professional services for the Corporation and the Trust;
    
    arranging for borrowings by the Corporation and equity issuances by the Trust; and
    
    conducting general Unitholder services, including investor relations, maintaining
regulatory compliance, providing information to Unitholders in respect of material
changes in the business of the Corporation or the Trust and all other reports required
by law, and calling, holding and distributing material in respect of meetings of
Unitholders and Royalty Unitholders.
  - 21 -




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Bonus Pool
  Management Agreement Second Term
    
    
    The termination fee payable to the Manager on termination of the Management
Agreement;
    
    The estimated cost of internal management, until June 30, 2009, in the event of a
termination of the Management Agreement;
    
    The estimated maximum management fees that would be payable to the Manager over the
final three years of the term of the Management Agreement;
    
    The advice of its financial advisor;
    
    The management fee ceiling applicable during the final three years of the Management
Agreement, which will result in lower management fees in the second term of the
Management Agreement ending June 30, 2009 as compared to the first term of the
Management Agreement ended June 30, 2006; and
    
    The commitment by the Manager to certain key governance standards relating to the
conduct of the affairs of the Trust and a continuing commitment to overall corporate
governance practices (as such practices would apply to Pengrowth in an internalized
management structure); and a further commitment to assist and work with the Board in
establishing a plan for the orderly transition to a traditional corporate management
structure at the end of the final term of the Management Agreement on June 30, 2009.
  - 22 -




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




---



##### 



P+PValueReserve
    
    Before TaxP+P
    
    Remaining
    
    Life
    
    at 10%
    
    2007 Oil
    
    2007 Gas
    
    2007 NGL
    
    2007 TotalReserves(3)
    
    Reserve Life
    
    Index
    
    Discount
    
    Production
    
    Production
    
    Production
    
    ProductionField
    
    Mboe)
    
    (years)
    
    (years)
    
    ($MM)
    
    (bblpd)
    
    (MMcfd)
    
    (bblpd)
    
    (boepd)(3)Shallow GasThree Hills/Twining
    
    
    13,704
    
    
    
    50
    
    
    
    10.2
    
    
    
    218.2
    
    
    
    537
    
    
    
    17.7
    
    
    
    447
    
    
    
    3,939Coal Bed Methane
    
    
    9,312
    
    
    
    41
    
    
    
    11.3
    
    
    
    123.9
    
    
    
    1
    
    
    
    6.2
    
    
    
    6
    
    
    
    1,032Monogram
    
    
    8,044
    
    
    
    32
    
    
    
    8.9
    
    
    
    127.0
    
    
    
    
    
    
    
    12.1
    
    
    
    
    
    
    
    2,015Jenner
    
    
    7,435
    
    
    
    33
    
    
    
    9.4
    
    
    
    90.7
    
    
    
    4
    
    
    
    11.5
    
    
    
    2
    
    
    
    1,922Lethbridge
    
    
    3,685
    
    
    
    50
    
    
    
    7.6
    
    
    
    51.2
    
    
    
    
    
    
    
    7.2
    
    
    
    
    
    
    
    1,193Other(2)
    
    
    16,728
    
    
    
    
    
    
    
    10.0
    
    
    
    247.5
    
    
    
    600
    
    
    
    30.2
    
    
    
    18
    
    
    
    5,713Sub-Total
    
    
    58,908
    
    
    
    
    
    
    
    9.9
    
    
    
    858.4
    
    
    
    1,142
    
    
    
    84.8
    
    
    
    533
    
    
    
    15,813Offshore GasSable Island
    
    
    11,731
    
    
    
    9
    
    
    
    4.3
    
    
    
    266.6
    
    
    
    
    
    
    
    33.2
    
    
    
    1,362
    
    
    
    6,895Sub-Total
    
    
    11,731
    
    
    
    
    
    
    
    4.3
    
    
    
    266.6
    
    
    
    
    
    
    
    33.2
    
    
    
    1,362
    
    
    
    6,895Total
    
    
    319,921
    
    
    
    
    
    
    
    10.4
    
    
    
    5,455.9
    
    
    
    33,495
    
    
    
    267.0
    
    
    
    9,409
    
    
    
    87,401
 Notes:
 (1)
    
    The estimates of reserves and future net revenue for individual properties may not reflect
the same confidence level as estimates of reserves and future net revenue for all properties,
due to the effects of aggregation.(2)
    
    Other includes Pengrowths Working Interests and Royalty Interests in approximately 100
other properties.(3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 Light Oil Properties
 Judy Creek
  2007 Development Activity
  Carbon Dioxide
(CO 2 ) Pilot
 2 2 2 2 2 2
 - 24 -




---



##### 



2008 Development Activity
 2
 Weyburn Unit
 2
 2007 Development Activity
 2 2
 2008 Development Activity
 2
 Swan Hills
  2007 Development Activity
  2008 Development Activity
  Carson
Creek  Light Oil
  - 25 -




---



##### 



2007 Development Activity
  2008 Development Activity
  Fenn Big Valley
  2007 Development Activity
  2008 Development Activity
 2
 Deer Mountain Unit No. 1
  2007 Development Activity
  - 26 -




---



##### 



2008 Development Activity
  Heavy Oil Properties
 Jenner  Heavy Oil
 ° °
 2007 Development Activity
  2008 Development Activity
  Bodo
  2007 Development Activity
  2008 Development Activity
  Tangleflags
  - 27 -




---



##### 



2007 Development Activity
  2008 Development Activity
  Conventional Gas Properties
 Olds
 2
  2007 Development Activity
  2008 Development Activity
  Harmattan
  - 28 -




---



##### 



2007 Development Activity
  2008 Development Activity
  Dunvegan Gas Unit No. 1
  2007 Development Activity
  2008 Development Activity
  Quirk Creek
  - 29 -




---



##### 



2007 Development Activity
  2008 Development Activity
  Kaybob
  2007 Development Activity
  2008 Development Activity
  McLeod River
  2007 Development Activity
  2008 Development Activity
  Blackstone
  - 30 -




---



##### 



2007 Development Activity
  2008 Development Activity
  Carson Creek  Conventional Gas
   2007 Development Activity
  2008 Development Activity
  Shallow Gas Properties
 Twining/Three Hills Creek
  2007 Development Activity
  2008 Development Activity
  - 31 -




---



##### 



Coal Bed Methane (CBM)
  2007 Development Activity
  2008 Development Activity
  Monogram Gas Unit
  2007 Development Activity
  2008 Development Activity
  Jenner  Shallow Gas
  2007 Development Activity
  - 32 -




---



##### 



2008 Development Activity
  Lethbridge
  2007 Development Activity
  2008 Development Activity
  Offshore Gas Properties
 Sable Offshore Energy Project (SOEP)
   2007 Development Activity
  - 33 -




---



##### 



2008 Development Activity
  - 34 -




---



##### 



Statement of Oil and Gas Reserves and Reserves Data
 Disclosure of Reserves Data
   The Trusts future net revenues associated with the reserves contained in this Annual Information
Form do not reflect the impact of the proposed changes to royalties payable to the Government of
Alberta. See  General Development of Pengrowth Energy Trust 
Recent Developments  Changes to Royalty Legislation Affecting Pengrowth and its Unitholders .
  The GLJ forecasts of future net cash flow are stated
prior to any provision for income taxes, interest costs or general and administrative costs and
after the deduction of estimated future capital expenditures for wells to which reserves have been
assigned. It should not be assumed that the estimated future net cash flow shown below is
representative of the fair market value of the properties. There is no assurance that such price
and cost assumptions will be attained and variances could be material. The recovery and estimates
of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no
guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas
reserves may be greater than or less than the estimates provided herein.
 The future net cash flow and present value of future net revenue after income taxes were determined
by Pengrowth after taking into account the impact of the SIFT Legislation.
 
    
    SIFT tax starting January 2011 at 26.5 percent (and 25 percent in 2012 and
thereafter) and corporate taxes as currently expected;
 - 35 -




---



##### 




    
    Annual general and administration expenses at the current level;
    
    Interest expense at the current level;
    
    Inclusion of tax pools and deductions at the trust level as well as at the operating
entity level;
    
    Royalties paid to the Trust in the amount of the operating income;
    
    Distributions to Unitholders; and
    
    Any such other additional deductions and adjustments as is and would be consistent
with the manner in which Pengrowth files and would file future tax returns. See
Canadian Income Tax Considerations.
   - 36 -




---



##### 



Reserves Data (Forecast Prices and Costs)
 Summary of Oil and Gas Reserves
as of December 31, 2007
(Forecast Prices and Costs)
 Light and Medium Oil
    
    Heavy Oil
    
    Natural Gas LiquidsCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)Proved ReservesProved Developed
Producing
    
    
    73,509
    
    
    
    73,350
    
    
    
    63,961
    
    
    
    14,682
    
    
    
    14,674
    
    
    
    13,196
    
    
    
    19,920
    
    
    
    19,813
    
    
    
    14,312Proved Developed
Non-Producing
    
    
    482
    
    
    
    482
    
    
    
    406
    
    
    
    30
    
    
    
    30
    
    
    
    29
    
    
    
    504
    
    
    
    504
    
    
    
    325Proved Undeveloped
    
    
    18,986
    
    
    
    18,985
    
    
    
    15,690
    
    
    
    2,194
    
    
    
    2,194
    
    
    
    1,899
    
    
    
    1,361
    
    
    
    1,361
    
    
    
    1,053Total Proved Reserves
    
    
    92,977
    
    
    
    92,817
    
    
    
    80,057
    
    
    
    16,906
    
    
    
    16,898
    
    
    
    15,124
    
    
    
    21,786
    
    
    
    21,677
    
    
    
    15,691Probable Reserves
    
    
    31,211
    
    
    
    31,180
    
    
    
    26,533
    
    
    
    4,885
    
    
    
    4,883
    
    
    
    4,273
    
    
    
    7,208
    
    
    
    7,185
    
    
    
    5,195Total Proved Plus
Probable Reserves
    
    
    124,188
    
    
    
    123,997
    
    
    
    106,590
    
    
    
    21,792
    
    
    
    21,781
    
    
    
    19,397
    
    
    
    28,994
    
    
    
    28,862
    
    
    
    20,885
 Natural Gas
    
    Coal Bed Methane
    
    Total Oil Equivalent Basis(1)Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (Mboe)
    
    (Mboe)
    
    (Mboe)Proved ReservesProved Developed
Producing
    
    
    547,462
    
    
    
    543,054
    
    
    
    437,824
    
    
    
    21,257
    
    
    
    20,460
    
    
    
    19,101
    
    
    
    202,898
    
    
    
    201,755
    
    
    
    167,624Proved Developed
Non-Producing
    
    
    21,168
    
    
    
    21,084
    
    
    
    16,044
    
    
    
    2,712
    
    
    
    2,632
    
    
    
    2,405
    
    
    
    4,997
    
    
    
    4,968
    
    
    
    3,835Proved Undeveloped
    
    
    50,351
    
    
    
    50,224
    
    
    
    41,057
    
    
    
    14,049
    
    
    
    13,911
    
    
    
    12,341
    
    
    
    33,275
    
    
    
    33,230
    
    
    
    27,542Total Proved Reserves
    
    
    618,981
    
    
    
    614,363
    
    
    
    494,925
    
    
    
    38,018
    
    
    
    37,002
    
    
    
    33,847
    
    
    
    241,169
    
    
    
    239,953
    
    
    
    199,000Probable Reserves
    
    
    195,282
    
    
    
    193,874
    
    
    
    155,116
    
    
    
    17,402
    
    
    
    17,115
    
    
    
    15,579
    
    
    
    78,752
    
    
    
    78,414
    
    
    
    64,450Total Proved Plus
Probable Reserves
    
    
    814,263
    
    
    
    808,237
    
    
    
    650,041
    
    
    
    55,420
    
    
    
    54,117
    
    
    
    49,426
    
    
    
    319,921
    
    
    
    318,367
    
    
    
    263,450
 Note:(1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 - 37 -




---



##### 



Summary of Net Present Value
of Future Net Revenue
as of December 31, 2007
Before and After Income Taxes
(Forecast Prices and Costs)
 Unit Value Before Income TaxBefore Income Taxes Discounted At (%/Year)
    
    Discounted At 10%/Year(1)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    $/boe
    
    $/McfeProved ReservesProved Developed Producing
    
    
    6,212
    
    
    
    4,744
    
    
    
    3,885
    
    
    
    3,321
    
    
    
    2,921
    
    
    
    23.18
    
    
    
    3.86Proved Developed
Non-Producing
    
    
    134
    
    
    
    100
    
    
    
    79
    
    
    
    65
    
    
    
    55
    
    
    
    20.57
    
    
    
    3.43Proved Undeveloped
    
    
    1,126
    
    
    
    688
    
    
    
    459
    
    
    
    322
    
    
    
    234
    
    
    
    16.66
    
    
    
    2.78Total Proved Reserves
    
    
    7,473
    
    
    
    5,532
    
    
    
    4,423
    
    
    
    3,708
    
    
    
    3,210
    
    
    
    22.22
    
    
    
    3.70Probable Reserves
    
    
    2,960
    
    
    
    1,602
    
    
    
    1,033
    
    
    
    740
    
    
    
    565
    
    
    
    16.03
    
    
    
    2.67Total Proved Plus Probable
Reserves
    
    
    10,433
    
    
    
    7,134
    
    
    
    5,456
    
    
    
    4,448
    
    
    
    3,775
    
    
    
    20.71
    
    
    
    3.45
 After Income Taxes Discounted At (%/Year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    5,478
    
    
    
    4,344
    
    
    
    3,638
    
    
    
    3,149
    
    
    
    2,793Proved Developed
Non-Producing
    
    
    99
    
    
    
    77
    
    
    
    63
    
    
    
    53
    
    
    
    46Proved Undeveloped
    
    
    707
    
    
    
    439
    
    
    
    293
    
    
    
    206
    
    
    
    149Total Proved Reserves
    
    
    6,284
    
    
    
    4,860
    
    
    
    3,994
    
    
    
    3,408
    
    
    
    2,988Probable Reserves
    
    
    1,813
    
    
    
    1,001
    
    
    
    667
    
    
    
    493
    
    
    
    387Total Proved Plus Probable
Reserves
    
    
    8,097
    
    
    
    5,861
    
    
    
    4,661
    
    
    
    3,901
    
    
    
    3,375
 Note:(1)
    
    Unit values are based on Pengrowths Net reserves
 - 38 -




---



##### 



Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2007
(Forecast Prices and Costs)
 Future NetRevenueCapital
    
    
    
    
    
    Before
    
    
    
    
    
    Future netOperating
    
    Development
    
    Abandonment
    
    Income
    
    Income
    
    RevenueRevenue
    
    Royalties(1)
    
    Costs
    
    Costs
    
    Costs(2)
    
    Taxes
    
    Tax
    
    After IncomeReserves category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    Taxes($MM)Proved Reserves
    
    
    15,750
    
    
    
    2,600
    
    
    
    4,898
    
    
    
    566
    
    
    
    214
    
    
    
    7,473
    
    
    
    1,189
    
    
    
    6,284Total Proved Plus Probable Reserves
    
    
    21,467
    
    
    
    3,584
    
    
    
    6,391
    
    
    
    819
    
    
    
    240
    
    
    
    10,433
    
    
    
    2,336
    
    
    
    8,097
 Notes:
 (1)
    
    Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova
Scotia. Does not include the impact of the proposed royalty regime announced by the
Government of Alberta on October 25, 2007, to become effective on January 1, 2009. Based on
the interpretations by GLJ of the proposed royalty changes and based on the January 2008
commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result
in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as
compared to the current royalty structure.
 (2)
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See
Pengrowth  Operational Information  Additional Information Concerning Abandonment &
Reclamation Costs.
 Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2007
(Forecast Prices and Costs)
 Future NetRevenue BeforeIncome Taxes(discounted at 10%/yr)
    
    Unit Value(3)Reserves Category
    
    Production Group
    
    ($MM)
    
    ($/Boe)
    
    ($/Mcf)Total Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products) (1)
    
    
    2,365
    
    
    
    25.57
    
    
    
    4.26Heavy Oil (including solution gas and other by-products) (1)
    
    
    305
    
    
    
    18.07
    
    
    
    3.01Natural Gas (including by-products but excluding solution gas from oil wells)(2)
    
    
    1,645
    
    
    
    19.85
    
    
    
    3.31Non-conventional Oil & Gas Activities
    
    
    108
    
    
    
    15.94
    
    
    
    2.66Total
    
    
    4,423
    
    
    
    22.22
    
    
    
    3.70Total Proved Plus Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products) (1)
    
    
    2,881
    
    
    
    23.53
    
    
    
    3.92Heavy Oil (including solution gas and other by-products) (1)
    
    
    369
    
    
    
    17.03
    
    
    
    2.84Natural Gas (including by-products but excluding solution gas from oil wells) (2)
    
    
    2,065
    
    
    
    18.89
    
    
    
    3.15Non-conventional Oil & Gas Activities
    
    
    141
    
    
    
    14.52
    
    
    
    2.42Total
    
    
    5,456
    
    
    
    20.74
    
    
    
    3.46
 Notes:
 (1)
    
    NGLs associated with the production of solution gas are included as a by-product.(2)
    
    NGLs associated with the production of natural gas are included as a by-product.(3)
    
    Unit values are based on Pengrowths Net reserves.
 - 39 -




---



##### 



Reserves Data (Constant Prices and Costs)
 Summary of Oil And Gas Reserves
as of December 31, 2007
(Constant Prices and Costs)
 Height and Medium Oil
    
    Heavy Oil
    
    Natural Gas LiquidsCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)Proved ReservesProved Developed Producing
    
    
    73,715
    
    
    
    73,550
    
    
    
    64,184
    
    
    
    14,591
    
    
    
    14,583
    
    
    
    13,185
    
    
    
    19,922
    
    
    
    19,814
    
    
    
    14,274Proved Developed Non-
Producing
    
    
    1,040
    
    
    
    1,040
    
    
    
    914
    
    
    
    95
    
    
    
    95
    
    
    
    89
    
    
    
    559
    
    
    
    558
    
    
    
    381Proved Undeveloped
    
    
    19,014
    
    
    
    19,013
    
    
    
    15,555
    
    
    
    2,194
    
    
    
    2,194
    
    
    
    1,899
    
    
    
    1,363
    
    
    
    1,363
    
    
    
    1,053Total Proved Reserves
    
    
    93,769
    
    
    
    93,603
    
    
    
    80,653
    
    
    
    16,880
    
    
    
    16,872
    
    
    
    15,173
    
    
    
    21,845
    
    
    
    21,736
    
    
    
    15,708Probable Reserves
    
    
    31,338
    
    
    
    31,311
    
    
    
    26,655
    
    
    
    4,863
    
    
    
    4,861
    
    
    
    4,260
    
    
    
    7,203
    
    
    
    7,180
    
    
    
    5,186Total Proved Plus Probable
Reserves
    
    
    125,107
    
    
    
    124,914
    
    
    
    107,308
    
    
    
    21,744
    
    
    
    21,733
    
    
    
    19,433
    
    
    
    29,048
    
    
    
    28,916
    
    
    
    20,893
 Natural Gas
    
    Coal Bed Methane
    
    Total Oil Equivalent Basis(1)Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestRESERVES CATEGORY
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (Mboe)
    
    (Mboe)
    
    (Mboe)Proved ReservesProved Developed Producing
    
    
    546,528
    
    
    
    542,127
    
    
    
    437,085
    
    
    
    21,173
    
    
    
    20,376
    
    
    
    19,026
    
    
    
    202,845
    
    
    
    201,698
    
    
    
    167,661Proved Developed Non-
Producing
    
    
    21,555
    
    
    
    21,462
    
    
    
    16,328
    
    
    
    2,797
    
    
    
    2,716
    
    
    
    2,481
    
    
    
    5,752
    
    
    
    5,722
    
    
    
    4,519Proved Undeveloped
    
    
    50,778
    
    
    
    50,646
    
    
    
    41,437
    
    
    
    14,049
    
    
    
    13,911
    
    
    
    12,341
    
    
    
    33,376
    
    
    
    33,330
    
    
    
    27,470Total Proved Reserves
    
    
    618,861
    
    
    
    614,234
    
    
    
    494,850
    
    
    
    38,019
    
    
    
    37,003
    
    
    
    33,848
    
    
    
    241,974
    
    
    
    240,751
    
    
    
    199,650Probable Reserves
    
    
    195,196
    
    
    
    193,799
    
    
    
    155,060
    
    
    
    17,403
    
    
    
    17,116
    
    
    
    15,579
    
    
    
    78,838
    
    
    
    78,505
    
    
    
    64,541Total Proved Plus Probable
Reserves
    
    
    814,057
    
    
    
    808,033
    
    
    
    649,910
    
    
    
    55,422
    
    
    
    54,119
    
    
    
    49,427
    
    
    
    320,812
    
    
    
    319,256
    
    
    
    264,191
 Note:
 (1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 - 40 -




---



##### 



Summary of Net Present Value
of Future Net Revenue
as of December 31, 2007
Before and After Income Tax
(Constant Prices and Costs)
 Unit Value Before IncomeTax Discounted atBefore Income Taxes Discounted at (%/Year)
    
    10%/Year(1)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    $/boe
    
    $/McfeProved ReservesProved Developed Producing
    
    
    6,463
    
    
    
    4,900
    
    
    
    3,984
    
    
    
    3,383
    
    
    
    2,959
    
    
    
    23.76
    
    
    
    3.96Proved Developed Non-Producing
    
    
    170
    
    
    
    124
    
    
    
    96
    
    
    
    79
    
    
    
    66
    
    
    
    21.34
    
    
    
    3.56Proved Undeveloped
    
    
    1,205
    
    
    
    747
    
    
    
    505
    
    
    
    359
    
    
    
    263
    
    
    
    18.37
    
    
    
    3.06Total Proved Reserves
    
    
    7,839
    
    
    
    5,770
    
    
    
    4,585
    
    
    
    3,821
    
    
    
    3,288
    
    
    
    22.96
    
    
    
    3.83Probable Reserves
    
    
    2,810
    
    
    
    1,574
    
    
    
    1,034
    
    
    
    747
    
    
    
    572
    
    
    
    16.02
    
    
    
    2.67Total Proved Plus Probable Reserves
    
    
    10,649
    
    
    
    7,345
    
    
    
    5,619
    
    
    
    4,567
    
    
    
    3,861
    
    
    
    21.27
    
    
    
    3.54
 After Income Taxes Discounted at (%/u/c year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    5,614
    
    
    
    4,423
    
    
    
    3,681
    
    
    
    3,171
    
    
    
    2,802Proved Developed Non-Producing
    
    
    122
    
    
    
    83
    
    
    
    75
    
    
    
    63
    
    
    
    54Proved Undeveloped
    
    
    668
    
    
    
    413
    
    
    
    279
    
    
    
    197
    
    
    
    141Total Proved Reserves
    
    
    6,404
    
    
    
    4,929
    
    
    
    4,035
    
    
    
    3,431
    
    
    
    2,997Probable Reserves
    
    
    1,823
    
    
    
    1,054
    
    
    
    717
    
    
    
    534
    
    
    
    422Total Proved Plus Probable Reserves
    
    
    8,227
    
    
    
    5,983
    
    
    
    4,752
    
    
    
    3,965
    
    
    
    3,419
 Note:
 (1)
    
    Unit values are based on Pengrowths Net reserves.
 - 41 -




---



##### 



Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2007
(Constant Prices and Costs)
 Future NetCapital
    
    
    
    
    
    Future Net
    
    
    
    
    
    RevenueOperating
    
    Development
    
    Abandonment
    
    Revenue Before
    
    
    
    
    
    After IncomeRevenue
    
    Royalties(1)
    
    Costs
    
    Costs
    
    Costs(2)
    
    Income Taxes
    
    Income Tax
    
    TaxesReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    15,186
    
    
    
    2,526
    
    
    
    4,131
    
    
    
    526
    
    
    
    164
    
    
    
    7,839
    
    
    
    1,435
    
    
    
    6,404Total Proved Plus
Probable Reserves
    
    
    20,154
    
    
    
    3,402
    
    
    
    5,175
    
    
    
    758
    
    
    
    170
    
    
    
    10,649
    
    
    
    2,422
    
    
    
    8,227
 Notes:(1)
    
    Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova
Scotia. Does not include the impact of the proposed royalty regime announced by the
Government of Alberta on October 25, 2007, to become effective on January 1, 2009. Based on
the interpretations by GLJ of the proposed royalty changes and based on the January 2008
commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result
in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as
compared to the current royalty structure.(2)
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See
Pengrowth  Operational Information  Additional Information Concerning Abandonment &
Reclamation Costs.
 Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2007
(Constant Prices and Costs)
 Future Net RevenueBefore Income Taxes(discounted at 10%/yr)
    
    Unit Value(3)Reserves Category
    
    Production Group
    
    ($MM)
    
    ($/boe)
    
    ($/Mcf)Total Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products) (1)
    
    
    2,755
    
    
    
    29.58
    
    
    
    4.93Heavy Oil (including solution gas and other by-products)(1)
    
    
    241
    
    
    
    14.19
    
    
    
    2.37Natural Gas (including by-products but excluding solution gas from oil wells) (2)
    
    
    1,500
    
    
    
    18.11
    
    
    
    3.02Non-conventional Oil & Gas Activities
    
    
    89
    
    
    
    13.16
    
    
    
    2.19Total
    
    
    4,585
    
    
    
    22.96
    
    
    
    3.83Total Proved Plus
Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products)(1)
    
    
    3,340
    
    
    
    27.11
    
    
    
    4.52Heavy Oil (including solution gas and other by-products) (1)
    
    
    291
    
    
    
    13.42
    
    
    
    2.24Natural Gas (including by-products but excluding solution gas from oil wells) (2)
    
    
    1,873
    
    
    
    17.14
    
    
    
    2.86Non-conventional Oil & Gas Activities
    
    
    114
    
    
    
    11.75
    
    
    
    1.96Total
    
    
    5,619
    
    
    
    21.29
    
    
    
    3.55
 Notes:(1)
    
    NGLs associated with the production of solution gas are included as a by-product.(2)
    
    NGLs associated with the production of natural gas are included as a by-product.(3)
    
    Unit values are based on Pengrowths Net reserves.
 - 42 -




---



##### 



Pricing Assumptions
 Forecast Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)WTI
    
    Edmonton
    
    Cromer
    
    HardistyCushing
    
    Par Price
    
    Medium

    
    Heavy 120
    
    AECO Gas
    
    
    
    
    
    
    
    
    
    Pentanes
    
    Inflation
    
    ExchangeOklahoma
    
    400API
    
    29.30API
    
    API
    
    Price
    
    Propane
    
    Butane
    
    Plus
    
    Rates(2)
    
    Rate(3)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/MMbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    (%/Year)
    
    ($US/Cdn)2007(4)
    
    
    72.24
    
    
    
    77.02
    
    
    
    66.30
    
    
    
    44.37
    
    
    
    6.65
    
    
    
    46.85
    
    
    
    58.35
    
    
    
    77.33
    
    
    
    
    
    
    
    2008
    
    
    92.00
    
    
    
    91.10
    
    
    
    79.26
    
    
    
    54.02
    
    
    
    6.75
    
    
    
    58.30
    
    
    
    72.88
    
    
    
    92.92
    
    
    
    2.0
    
    
    
    1.002009
    
    
    88.00
    
    
    
    87.10
    
    
    
    75.78
    
    
    
    51.61
    
    
    
    7.55
    
    
    
    55.74
    
    
    
    69.68
    
    
    
    88.84
    
    
    
    2.0
    
    
    
    1.002010
    
    
    84.00
    
    
    
    83.10
    
    
    
    72.30
    
    
    
    49.19
    
    
    
    7.60
    
    
    
    53.18
    
    
    
    66.48
    
    
    
    84.76
    
    
    
    2.0
    
    
    
    1.002011
    
    
    82.00
    
    
    
    81.10
    
    
    
    70.56
    
    
    
    47.98
    
    
    
    7.60
    
    
    
    51.90
    
    
    
    64.88
    
    
    
    82.72
    
    
    
    2.0
    
    
    
    1.002012
    
    
    82.00
    
    
    
    81.10
    
    
    
    70.56
    
    
    
    47.98
    
    
    
    7.60
    
    
    
    51.90
    
    
    
    64.88
    
    
    
    82.72
    
    
    
    2.0
    
    
    
    1.002013
    
    
    82.00
    
    
    
    81.10
    
    
    
    70.56
    
    
    
    49.04
    
    
    
    7.60
    
    
    
    51.90
    
    
    
    64.88
    
    
    
    82.72
    
    
    
    2.0
    
    
    
    1.002014
    
    
    82.00
    
    
    
    81.10
    
    
    
    70.56
    
    
    
    50.09
    
    
    
    7.80
    
    
    
    51.90
    
    
    
    64.88
    
    
    
    82.72
    
    
    
    2.0
    
    
    
    1.002015
    
    
    82.00
    
    
    
    81.10
    
    
    
    70.56
    
    
    
    51.15
    
    
    
    7.97
    
    
    
    51.90
    
    
    
    64.88
    
    
    
    82.72
    
    
    
    2.0
    
    
    
    1.002016
    
    
    82.02
    
    
    
    81.12
    
    
    
    70.57
    
    
    
    52.21
    
    
    
    8.14
    
    
    
    51.91
    
    
    
    64.89
    
    
    
    82.74
    
    
    
    2.0
    
    
    
    1.002017
    
    
    83.66
    
    
    
    82.76
    
    
    
    72.00
    
    
    
    53.29
    
    
    
    8.31
    
    
    
    52.97
    
    
    
    66.21
    
    
    
    84.42
    
    
    
    2.0
    
    
    
    1.00Thereafter
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    
    2.0
    
    
    
    1.00
 Notes:(1)
    
    FOB Edmonton.(2)
    
    Inflation rates for forecasting prices and costs.(3)
    
    The exchange rates used to generate the benchmark reference prices in this table.(4)
    
    Actual average prices for 2007.
 Constant Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)WTI
    
    Edmonton
    
    Cromer
    
    LLB CrudeCushing
    
    Par Price
    
    Medium
    
    Oil at
    
    AECO Gas
    
    
    
    
    
    
    
    
    
    Pentanes
    
    ExchangeOklahoma
    
    400API
    
    29.30API
    
    Hardisty
    
    Price
    
    Propane
    
    Butane
    
    Plus
    
    Rate(2)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/MMbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($US/Cdn)December 31, 2007
    
    
    95.92
    
    
    
    93.39
    
    
    
    74.26
    
    
    
    53.74
    
    
    
    6.63
    
    
    
    59.77
    
    
    
    74.71
    
    
    
    94.24
    
    
    
    1.012
 Notes:(1)
    
    FOB Edmonton.(2)
    
    The exchange rate used to generate the benchmark reference prices in this table.
 - 43 -




---



##### 



Reserves Reconciliation
  Reserves Reconciliation
By Principle Product Type
(Forecast Prices and Costs)
 Light and Medium Oil
    
    Heavy Oil
    
    Natural Gas LiquidsGrossGross
    
    
    
    
    
    
    
    
    
    Gross
    
    
    
    
    
    
    
    
    
    ProvedGross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    PlusProved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable(Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)
    
    (Mbbls)December 31, 2006
    
    
    84,648
    
    
    
    27,467
    
    
    
    112,115
    
    
    
    14,236
    
    
    
    4,090
    
    
    
    18,326
    
    
    
    22,400
    
    
    
    6,682
    
    
    
    29,082Extensions
    
    
    932
    
    
    
    (141
    )
    
    
    791
    
    
    
    30
    
    
    
    10
    
    
    
    40
    
    
    
    496
    
    
    
    (1
    )
    
    
    495Infill Drilling
    
    
    1,188
    
    
    
    956
    
    
    
    2,144
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    235
    
    
    
    160
    
    
    
    395Improved Recovery
    
    
    482
    
    
    
    421
    
    
    
    903
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    25
    
    
    
    15
    
    
    
    40Technical Revisions
    
    
    3,119
    
    
    
    (1,421
    )
    
    
    1,698
    
    
    
    742
    
    
    
    (177
    )
    
    
    565
    
    
    
    591
    
    
    
    174
    
    
    
    765Discoveries
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    23
    
    
    
    3
    
    
    
    26Acquisitions
    
    
    14,256
    
    
    
    4,893
    
    
    
    19,149
    
    
    
    5,939
    
    
    
    1,542
    
    
    
    7,481
    
    
    
    2,828
    
    
    
    629
    
    
    
    3,457Dispositions
    
    
    (2,227
    )
    
    
    (993
    )
    
    
    (3,220
    )
    
    
    (1,432
    )
    
    
    (582
    )
    
    
    (2,014
    )
    
    
    (1,509
    )
    
    
    (478
    )
    
    
    (1,987
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (9,582
    )
    
    
    
    
    
    
    (9,582
    )
    
    
    (2,616
    )
    
    
    
    
    
    
    (2,616
    )
    
    
    (3,411
    )
    
    
    
    
    
    
    (3,411
    )December 31, 2007
    
    
    92,817
    
    
    
    31,180
    
    
    
    123,997
    
    
    
    16,898
    
    
    
    4,883
    
    
    
    21,781
    
    
    
    21,677
    
    
    
    7,185
    
    
    
    28,862Natural Gas
    
    Coal Bed Methane
    
    Total Oil Equivalent Basis(1)GrossGross
    
    
    
    
    
    
    
    
    
    Gross
    
    
    
    
    
    
    
    
    
    ProvedGross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    PlusProved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable(MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (Mboe)
    
    (Mboe)
    
    (Mboe)December 31, 2006
    
    
    608,105
    
    
    
    191,206
    
    
    
    799,311
    
    
    
    14,230
    
    
    
    9,427
    
    
    
    23,657
    
    
    
    225,007
    
    
    
    71,677
    
    
    
    296,684Extensions
    
    
    16,729
    
    
    
    5,195
    
    
    
    21,924
    
    
    
    14,055
    
    
    
    4,883
    
    
    
    18,938
    
    
    
    6,588
    
    
    
    1,548
    
    
    
    8,136Infill Drilling
    
    
    11,350
    
    
    
    7,846
    
    
    
    19,196
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,314
    
    
    
    2,424
    
    
    
    5,738Improved Recovery
    
    
    508
    
    
    
    221
    
    
    
    729
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    592
    
    
    
    472
    
    
    
    1,064Technical Revisions
    
    
    14,661
    
    
    
    (19,175
    )
    
    
    (4,514
    )
    
    
    1,791
    
    
    
    (1,543
    )
    
    
    248
    
    
    
    7,193
    
    
    
    (4,877
    )
    
    
    2,316Discoveries
    
    
    519
    
    
    
    234
    
    
    
    753
    
    
    
    338
    
    
    
    112
    
    
    
    450
    
    
    
    165
    
    
    
    62
    
    
    
    227Acquisitions
    
    
    155,961
    
    
    
    36,584
    
    
    
    192,545
    
    
    
    8,434
    
    
    
    4,235
    
    
    
    12,669
    
    
    
    50,422
    
    
    
    13,867
    
    
    
    64,289Dispositions
    
    
    (99,088
    )
    
    
    (28,236
    )
    
    
    (127,324
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (21,682
    )
    
    
    (6,760
    )
    
    
    (28,442
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (94,384
    )
    
    
    
    
    
    
    (94,384
    )
    
    
    (1,845
    )
    
    
    
    
    
    
    (1,845
    )
    
    
    (31,648
    )
    
    
    
    
    
    
    (31,648
    )December 31, 2007
    
    
    614,363
    
    
    
    193,874
    
    
    
    808,237
    
    
    
    37,002
    
    
    
    17,115
    
    
    
    54,117
    
    
    
    239,953
    
    
    
    78,413
    
    
    
    318,366
 Note:(1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 - 44 -




---



##### 



Company Interest Reserves Reconciliation
on Total Oil Equivalent Basis
(Forecast Prices and Costs)
 Proved PlusProved Producing
    
    Proved
    
    ProbableReserves
    
    Reserves
    
    Reserves(Mboe) (1)
    
    (Mboe) (1)
    
    (Mboe) (1)December 31, 2006
    
    
    188,961
    
    
    
    225,875
    
    
    
    297,774Extensions
    
    
    4,898
    
    
    
    6,588
    
    
    
    8,136Infill Drilling
    
    
    3,956
    
    
    
    3,314
    
    
    
    5,738Improved Recovery
    
    
    755
    
    
    
    592
    
    
    
    1,180Technical Revisions
    
    
    11,094
    
    
    
    7,170
    
    
    
    2,094Discoveries
    
    
    109
    
    
    
    165
    
    
    
    227Acquisitions
    
    
    44,721
    
    
    
    51,046
    
    
    
    65,115Dispositions
    
    
    (19,696
    )
    
    
    (21,682
    )
    
    
    (28,442
    )Production
    
    
    (31,901
    )
    
    
    (31,901
    )
    
    
    (31,901
    )December 31, 2007
    
    
    202,897
    
    
    
    241,169
    
    
    
    319,921
 Note:(1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
  
    
    Reserve additions from drilling activity, improved recovery and technical revisions
replaced 2007 production by 56 percent and 54 percent for Total Proved and Proved Plus
Probable Reserves, respectively. Based on all changes, including acquisitions and
dispositions, reserve replacement was 148 percent and 169 percent for Total Proved and
Proved Plus Probable Reserves, respectively.
    
    The net increase of 36.7 MMboe from acquisitions and dispositions accounted for
approximately 68 percent of the Total Proved Plus Probable Reserves added in 2007.
Acquisition adds were almost entirely from the ConocoPhillips properties acquired in
January 2007. Acquisitions were offset by the planned sale of non-core assets closing
at various times during 2007.
    
    New reserves were added from development activity. Most significant were drilling
extensions for Horseshoe Canyon CBM and infill drilling and drilling extensions at
Twining, Harmattan and Monogram. Reserve increases in the Proved Producing category
also resulted from reclassification of Proved and Probable Undeveloped Reserves
primarily for additional drilling and tie-in of Horseshoe Canyon CBM, infill drilling
at Monogram and infill drilling and improved recovery in the Weyburn and Swan Hills
miscible flood projects.
    
    Various performance related revisions were made to previous estimates resulting in a
net positive change. The largest revisions to Proved Reserves occurred at Sable Island
(+1,308 Mboe), Fenn Big Valley (+965 Mboe), Jenner (+887 Mboe) and Winnifred (-520
Mboe).
 Additional Information Relating to Reserves Data
 Undeveloped Reserves
   - 45 -




---



##### 



Timing of Initial Undeveloped Reserves Booking
Company Gross Reserves
Reserves First Attributed By Year
 Units
    
    Prior
    
    2005
    
    2006
    
    2007
    
    TotalProved UndevelopedLight & Medium Oil
    
    Mbbl
    
    
    8,498
    
    
    
    7,221
    
    
    
    1,334
    
    
    
    1,932
    
    
    
    18,985Heavy Oil
    
    Mbbl
    
    
    1,852
    
    
    
    
    
    
    
    
    
    
    
    342
    
    
    
    2,194Natural Gas
    
    MMcf
    
    
    7,236
    
    
    
    3,508
    
    
    
    18,575
    
    
    
    20,905
    
    
    
    50,224Natural Gas Liquids
    
    Mbbl
    
    
    120
    
    
    
    
    
    
    
    843
    
    
    
    398
    
    
    
    1,361Coal Bed Methane
    
    MMcf
    
    
    
    
    
    
    
    
    
    
    2,555
    
    
    
    11,356
    
    
    
    13,911Total
    
    Mboe(1)
    
    
    11,754
    
    
    
    7,730
    
    
    
    5,698
    
    
    
    8,048
    
    
    
    33,230Probable UndevelopedLight & Medium Oil
    
    Mbbl
    
    
    5,995
    
    
    
    3,123
    
    
    
    1,315
    
    
    
    3,065
    
    
    
    13,498Heavy Oil
    
    Mbbl
    
    
    1,343
    
    
    
    
    
    
    
    200
    
    
    
    726
    
    
    
    2,269Natural Gas
    
    MMcf
    
    
    2,744
    
    
    
    3,598
    
    
    
    33,258
    
    
    
    25,386
    
    
    
    64,986Natural Gas Liquids
    
    Mbbl
    
    
    112
    
    
    
    648
    
    
    
    1,286
    
    
    
    670
    
    
    
    2,716Coal Bed Methane
    
    MMcf
    
    
    
    
    
    
    
    
    
    
    1,985
    
    
    
    8,170
    
    
    
    10,155Total
    
    Mboe(1)
    
    
    7,907
    
    
    
    4,371
    
    
    
    8,674
    
    
    
    10,054
    
    
    
    31,006
 Note:(1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 Proved Undeveloped Reserves
  2 2 2 2
  - 46 -




---



##### 



Probable Undeveloped Reserves
  Future Development Costs
  Undiscounted
    
    Discounted2008
    
    2009
    
    2010
    
    2011
    
    2012
    
    Remainder
    
    Total
    
    at 10% TotalReserve Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves (Constant
Prices and Costs)
    
    
    183
    
    
    
    103
    
    
    
    63
    
    
    
    33
    
    
    
    18
    
    
    
    126
    
    
    
    526
    
    
    
    393Proved Reserves (Forecast
Prices and Costs)
    
    
    183
    
    
    
    105
    
    
    
    65
    
    
    
    35
    
    
    
    19
    
    
    
    158
    
    
    
    566
    
    
    
    408Proved & Probable Reserves
(Forecast Prices and Costs)
    
    
    230
    
    
    
    180
    
    
    
    100
    
    
    
    47
    
    
    
    29
    
    
    
    234
    
    
    
    819
    
    
    
    584
  Finding, Development and Acquisition Costs
 Finding and Development Costs
     2
 - 47 -




---



##### 



Acquisitions and Divestitures
    Future Development Capital
  - 48 -




---



##### 



2007 Finding, Development and Acquisition Costs
Company Interest Reserves
 Proved plusProved
    
    ProbableFD&A Costs Excluding Future Development CapitalExploration and Development Capital Expenditures ($thousands)
    
    $
    283,100
    
    
    $
    283,100Exploration and Development Reserve Additions including Revisions (Mboe)
    
    
    17,830
    
    
    
    17,376Finding and Development Cost ($/boe)
    
    $
    15.88
    
    
    $
    16.29Net Acquisition Capital ($thousands)
    
    $
    577,100
    
    
    $
    577,100Net Acquisition Reserve Additions (Mboe)
    
    
    29,364
    
    
    
    36,673Net Acquisition Cost ($/boe)
    
    $
    19.65
    
    
    $
    15.74Total Capital Expenditures including Net Acquisitions ($thousands)
    
    $
    860,200
    
    
    $
    860,200Reserve Additions including Net Acquisitions (Mboe)
    
    
    47,194
    
    
    
    54,049Finding Development and Acquisition Cost ($/boe)
    
    $
    18.23
    
    
    $
    15.92FD&A Costs Including Future Development CapitalExploration and Development Capital Expenditures ($thousands)
    
    $
    283,100
    
    
    $
    283,100Exploration and Development Change in FDC ($thousands)
    
    $
    8,000
    
    
    $
    20,000Exploration and Development Capital including Change in FDC ($thousands)
    
    $
    291,100
    
    
    $
    303,100Exploration and Development Reserve Additions including Revisions (Mboe)
    
    
    17,830
    
    
    
    17,376Finding and Development Cost ($/boe)
    
    $
    16.33
    
    
    $
    17.44Net Acquisition Capital ($thousands)
    
    $
    577,100
    
    
    $
    577,100Net Acquisition FDC ($thousands)
    
    $
    115,000
    
    
    $
    145,000Net Acquisition Capital including FDC ($thousands)
    
    $
    692,100
    
    
    $
    722,100Net Acquisition Reserve Additions (Mboe)
    
    
    29,364
    
    
    
    36,673Net Acquisition Cost ($/boe)
    
    $
    23.57
    
    
    $
    19.69Total Capital Expenditures including Net Acquisitions ($thousands)
    
    $
    860,200
    
    
    $
    860,200Total Change in FDC ($thousands)
    
    $
    123,000
    
    
    $
    165,000Total Capital including Change in FDC ($thousands)
    
    $
    983,300
    
    
    $
    1,025,300Reserve Additions including Net Acquisitions (Mboe)
    
    
    47,194
    
    
    
    54,049Finding Development and Acquisition Cost including FDC ($/boe)
    
    $
    20.83
    
    
    $
    18.97
 Note:
 (1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 Other Oil and Gas Information
 Oil and Gas Wells
  Producing
    
    Non-ProducingGross
    
    Net
    
    Gross
    
    NetCrude Oil WellsAlberta
    
    
    2,346
    
    
    
    1,473
    
    
    
    473
    
    
    
    277British Columbia
    
    
    151
    
    
    
    105
    
    
    
    47
    
    
    
    43Saskatchewan
    
    
    1,134
    
    
    
    279
    
    
    
    187
    
    
    
    81Nova Scotia
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Natural Gas WellsAlberta
    
    
    5,515
    
    
    
    2,827
    
    
    
    571
    
    
    
    322British Columbia
    
    
    124
    
    
    
    77
    
    
    
    25
    
    
    
    27Saskatchewan
    
    
    51
    
    
    
    48
    
    
    
    87
    
    
    
    47Nova Scotia
    
    
    19
    
    
    
    1
    
    
    
    
    
    
    
    
 - 49 -




---



##### 



Producing
    
    Non-ProducingGross
    
    Net
    
    Gross
    
    NetOther(1)Alberta
    
    
    250
    
    
    
    217
    
    
    
    165
    
    
    
    115British Columbia
    
    
    
    
    
    
    
    
    
    
    50
    
    
    
    46Saskatchewan
    
    
    14
    
    
    
    10
    
    
    
    22
    
    
    
    19Total
    
    
    9,604
    
    
    
    5,038
    
    
    
    1,627
    
    
    
    976
 Note:
 (1)
    
    Pengrowth cannot classify these wells as either oil or gas.
 Properties with No Attributed Reserves
  Unproved Properties
as at December 31, 2007
 Net Area May ExpireLocation
    
    Gross Acres
    
    Net Acres
    
    During 2008Alberta
    
    
    1,095,994
    
    
    
    754,253
    
    
    
    129,887British Columbia
    
    
    255,172
    
    
    
    116,763
    
    
    
    13,847Ontario
    
    
    4,766
    
    
    
    
    
    
    
    Saskatchewan
    
    
    90,989
    
    
    
    76,335
    
    
    
    30,039Montana
    
    
    3,520
    
    
    
    3,520
    
    
    
    3,520Nova Scotia
    
    
    200,650
    
    
    
    15,957
    
    
    
    Total
    
    
    1,651,091
    
    
    
    966,828
    
    
    
    177,293
  Additional Information Concerning Abandonment & Reclamation Costs
   - 50 -




---



##### 



Asset Retirement Obligations
 2008
    
    2009
    
    2010
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment, Reclamation,
Remediation & Dismantling
    
    
    17,287
    
    
    
    18,046
    
    
    
    21,363
    
    
    
    1,958,381
    
    
    
    2,015,077Discounted at 10 percent
    
    
    16,483
    
    
    
    15,642
    
    
    
    16,834
    
    
    
    220,908
    
    
    
    269,867
  Costs Incurred
  AmountNature of Cost
    
    ($M)Acquisition Costs(1)Proved
    
    
    823,566Unproved
    
    
    212,317Exploration Costs
    
    
    21,192Development Costs
    
    
    261,866Total
    
    
    1,318,941
 Note:
 (1)
    
    Based on the values assigned to property, plant and equipment in the purchase price
allocations for the CP Acquisition and for several minor property acquisitions.
 Exploration and Development Activities
  Development
    
    Exploration
    
    TotalGross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetWellsGas
    
    
    383
    
    
    
    130.7
    
    
    
    6
    
    
    
    2.2
    
    
    
    389
    
    
    
    132.9Oil
    
    
    84
    
    
    
    19.9
    
    
    
    6
    
    
    
    5.3
    
    
    
    90
    
    
    
    25.2Service
    
    
    15
    
    
    
    8.4
    
    
    
    
    
    
    
    
    
    
    
    15
    
    
    
    8.4Dry
    
    
    12
    
    
    
    5.6
    
    
    
    5
    
    
    
    2.6
    
    
    
    17
    
    
    
    8.2Total
    
    
    494
    
    
    
    164.6
    
    
    
    17
    
    
    
    10.1
    
    
    
    511
    
    
    
    174.7
 Production Estimates
  - 51 -




---



##### 



Estimated ProductionConstant Prices and Costs
    
    Forecast Prices and CostsTotal Proved Plus
    
    
    
    
    
    Total Proved PlusTotal Proved
    
    Probable
    
    Total Proved
    
    ProbableLight and Medium Crude Oil
(bblpd)
    
    
    24,933
    
    
    
    26,169
    
    
    
    24,933
    
    
    
    26,169Heavy Oil (bblpd)
    
    
    6,485
    
    
    
    6,711
    
    
    
    6,485
    
    
    
    6,711Natural Gas (Mcfpd)
    
    
    245,006
    
    
    
    255,631
    
    
    
    245,007
    
    
    
    255,631Natural Gas Liquids (bblpd)
    
    
    8,250
    
    
    
    8,526
    
    
    
    8,250
    
    
    
    8,526
 Production History (Netback)
  Quarter EndedMarch 31,
    
    June 30,
    
    September 30,
    
    December 31,2007
    
    2007
    
    2007
    
    2007Light Crude OilAverage Daily Oil Production(1) (bblpd)
    
    
    27,461
    
    
    
    27,083
    
    
    
    24,903
    
    
    
    25,892Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    67.24
    
    
    
    71.81
    
    
    
    75.10
    
    
    
    73.69Processing and other income ($/bbl)
    
    
    0.39
    
    
    
    0.42
    
    
    
    0.90
    
    
    
    0.69Royalties ($/bbl)
    
    
    (9.88
    )
    
    
    (11.90
    )
    
    
    (10.65
    )
    
    
    (13.86
    )Amortization of injectants ($/bbl)
    
    
    (3.84
    )
    
    
    (3.51
    )
    
    
    (3.69
    )
    
    
    (3.14
    )Production Costs
(2)($/bbl)
    
    
    (13.31
    )
    
    
    (15.11
    )
    
    
    (16.93
    )
    
    
    (15.69
    )Operating Netback ($/bbl)
    
    
    40.60
    
    
    
    41.71
    
    
    
    44.73
    
    
    
    41.69Heavy OilAverage Daily Oil Production(1) (bblpd)
    
    
    6,773
    
    
    
    7,254
    
    
    
    7,205
    
    
    
    7,434Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    41.54
    
    
    
    43.52
    
    
    
    47.30
    
    
    
    45.47Processing and other income ($/bbl)
    
    
    0.18
    
    
    
    0.18
    
    
    
    0.50
    
    
    
    0.19Royalties ($/bbl)
    
    
    (5.23
    )
    
    
    (5.33
    )
    
    
    (6.90
    )
    
    
    (5.91
    )Production Costs
(2)($/bbl)
    
    
    (13.15
    )
    
    
    (15.37
    )
    
    
    (9.43
    )
    
    
    (12.92
    )Operating Netback ($/bbl)
    
    
    23.34
    
    
    
    23.00
    
    
    
    31.47
    
    
    
    26.83NGLsAverage Daily NGL Production(1) (bblpd)
    
    
    9,918
    
    
    
    8,519
    
    
    
    9,883
    
    
    
    9,319Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    49.67
    
    
    
    56.42
    
    
    
    61.69
    
    
    
    67.64Royalties ($/bbl)
    
    
    (14.05
    )
    
    
    (17.53
    )
    
    
    (18.82
    )
    
    
    (23.61
    )Production Costs(2)($/bbl)
    
    
    (12.02
    )
    
    
    (13.57
    )
    
    
    (10.96
    )
    
    
    (14.29
    )Operating Netback ($/bbl)
    
    
    23.60
    
    
    
    25.32
    
    
    
    31.91
    
    
    
    29.74Natural GasAverage
Daily Gas Production(1) (Mcfpd)
    
    
    275,495
    
    
    
    280,667
    
    
    
    261,976
    
    
    
    250,117Sales Price (net of hedging gains/losses) ($/Mcf)
    
    
    7.91
    
    
    
    7.61
    
    
    
    6.67
    
    
    
    6.90Processing and other income ($/Mcf)
    
    
    0.15
    
    
    
    0.16
    
    
    
    0.19
    
    
    
    0.18Royalties ($/Mcf)
    
    
    (1.67
    )
    
    
    (1.47
    )
    
    
    (0.92
    )
    
    
    (1.22
    )Production Costs(2)($/Mcf)
    
    
    (2.10
    )
    
    
    (2.24
    )
    
    
    (1.58
    )
    
    
    (2.11
    )Operating Netback ($/Mcf)
    
    
    4.29
    
    
    
    4.06
    
    
    
    4.36
    
    
    
    3.75
 - 52 -




---



##### 



Quarter EndedMarch 31,
    
    June 30,
    
    September 30,
    
    December 31,2007
    
    2007
    
    2007
    
    2007Barrels of Oil Equivalent Basis(3)Average
Daily Production(1) (boepd)
    
    
    90,068
    
    
    
    89,633
    
    
    
    85,654
    
    
    
    84,331Sales Price (net of hedging gains/losses) ($/boe)
    
    
    53.30
    
    
    
    54.39
    
    
    
    53.34
    
    
    
    54.58Processing and other income ($/boe)
    
    
    0.58
    
    
    
    0.66
    
    
    
    0.90
    
    
    
    0.76Royalties ($/boe)
    
    
    (10.06
    )
    
    
    (10.30
    )
    
    
    (8.67
    )
    
    
    (11.01
    )Amortization of injectants ($/boe)
    
    
    (1.17
    )
    
    
    (1.06
    )
    
    
    (1.07
    )
    
    
    (0.97
    )Production Costs(2) ($/boe)
    
    
    (12.78
    )
    
    
    (14.13
    )
    
    
    (11.84
    )
    
    
    (13.80
    )Operating Netback ($/boe)
    
    
    29.87
    
    
    
    29.56
    
    
    
    32.66
    
    
    
    29.56
 Notes:
 (1)
    
    Before the deduction of royalties.(2)
    
    Includes transportation costs. Net of processing and other income.(3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one boe.
 Replacement of Properties
  Net Asset Value (NAV) at December 31, 2007
  ($ thousands,unless otherwise indicated)Value of Total Proved Plus Probable Reserves discounted at 10%
    
    
    5,455,881Undeveloped lands (1)
    
    
    239,893Working
capital deficit (2)
    
    
    (34,423
    )Reclamation funds
    
    
    18,094Long-term debt
    
    
    (1,203,236
    )Fair value of risk management contracts (3)
    
    
    (79,401
    )Other liabilities (4)
    
    
    (87,192
    )Asset retirement obligations (5)
    
    
    (206,868
    )Net asset value
    
    
    4,102,748Units outstanding (000s)
    
    
    246,846NAV per unit
    
    $
    16.62
 Notes:
 (1)
    
    Pengrowths internal estimate, calculated using the average land sale prices paid in 2007 in
Alberta, Saskatchewan and British Columbia.(2)
    
    Excludes distributions payable, current portion of risk management contracts and future
income taxes.(3)
    
    Represents the total fair value of risk management contracts at December 31, 2007.(4)
    
    Other liabilities include convertible debt and non-current contract liabilities.(5)
    
    The asset retirement obligation is based on Pengrowths estimate of future site restoration
and abandonment liabilities, discounted at 10 percent, less that portion of the asset
retirement obligations costs that are included in the value of Total Proved Plus Probable
Reserves.
 - 53 -




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##### 



TRUST UNITS
 The Trust Indenture
   Canadian Deposit Insurance Corporation Act
 The Trustee
    - 54 -




---



##### 



Stock Exchange Listings
  Ownership Restrictions
  Redemption Right
 in specie
 Conversion Rights
  Voting at Meetings of Unitholders
   - 55 -




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Voting at Meetings of Corporation
  Termination of the Trust
  
    
    a vote may be held only if: (i) requested in writing by the holders of not less than
25 percent of the Trust Units and class A trust units, in the aggregate; or (ii) if the
Trust Units and the class A trust units have become ineligible for investment by RRSPs,
RRIFs, RESPs and DPSPs;
    
    the termination must be approved by extraordinary resolution of the Unitholders; and
    
    a quorum representing 5 percent of the issued and outstanding Trust Units and class
A trust units, in the aggregate, must be present or represented by proxy at the meeting
at which the vote is taken.
  Unitholder Limited Liability
  - 56 -




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##### 



THE ROYALTY INDENTURE
 Royalty Units
    The Royalty
  
    
    operating costs and capital expenditures;
    
    general and administrative costs;
    
    management fees and debt service charges;
    
    taxes or other charges payable by the Corporation; and
    
    any amounts paid into the reserve.
   - 57 -




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The Trustee
   EXCHANGEABLE SHARES
    - 58 -




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##### 



DISTRIBUTIONS
 General
  Historical Distributions
 Risk Factors
  2007
    
    2006
    
    2005
    
    2004
    
    2003
    
    2002First Quarter
    
    $
    0.75
    
    
    $
    0.75
    
    
    $
    0.69
    
    
    $
    0.63
    
    
    $
    0.75
    
    
    $
    0.41Second Quarter
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.64
    
    
    
    0.67
    
    
    
    0.54Third Quarter
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.67
    
    
    
    0.63
    
    
    
    0.52Fourth Quarter
    
    
    0.675
    (1)
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.63
    
    
    
    0.60Total
    
    $
    2.93
    
    
    $
    3.00
    
    
    $
    2.82
    
    
    $
    2.63
    
    
    $
    2.68
    
    
    $
    2.07
 Notes:(1)
    
    On October 15, 2007, November 15, 2007 and December 15, 2007, the monthly distribution paid
to Unitholders was $0.225 per Trust Unit, representing a reduction of 10 percent from the
monthly distribution of $0.25 per Trust Unit for the first three quarters of 2007.
 - 59 -




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(2)
    
    Based on actual distributions declared.
  2007
    
    2006
    
    2005
    
    2004
    
    2003
    
    2002Taxable Income(1) (per Trust Unit)
    
    $
    2.78
    
    
    $
    2.40
    
    
    $
    2.22
    
    
    $
    1.43
    
    
    $
    1.47
    
    
    $
    0.45(percent of distributions classified as taxable income)
    
    
    (95
    %)
    
    
    (80
    %)
    
    
    (80
    %)
    
    
    (55
    %)
    
    
    (55
    %)
    
    
    (22
    %)
 Note:(1)
    
    For Canadian residents, amounts treated as a return of capital generally are not required to
be included in a Unitholders income but such amounts will reduce the adjusted cost base to
the Unitholder of the Trust Units.
  Cash distributions are not guaranteed. Risk Factors
 Certain
Canadian Federal Income Tax Considerations United States Federal Income Tax Considerations
 Restrictions on Distributions
  - 60 -




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Revolving Credit Facility
   
    
    the ratio of Consolidated Senior Debt (as defined below) to Consolidated EBITDA (as
defined below) at the end of any fiscal quarter shall not exceed 3:1, except that upon
the completion of a Material Acquisition (as defined below), and for a period extending
to the end of the second full fiscal quarter thereafter, this limit increases to 3.5:1;
    
    the ratio of Consolidated Total Debt (as defined below) to Consolidated EBITDA at
the end of any fiscal quarter shall not exceed 3.5:1; except that upon the completion
of a Material Acquisition, and for a period extending to the end of the second full
fiscal quarter thereafter, this limit increases to 4:1; and
    
    the ratio of Consolidated Senior Debt (as defined below) to Total Capitalization (as
defined below) shall not exceed 50 percent, except that upon the completion of a
Material Acquisition, and for a period extending to the end of the second full fiscal
quarter thereafter, this limit increases to 55 percent.
  Consolidated Senior Debt:
    
    All obligations, liabilities and indebtedness that would be classified as debt on
the consolidated balance sheet of the Trust, including, without limitation, certain
items including all indebtedness for borrowed money, but excluding certain items.Consolidated Total Debt:
    
    The aggregate of Consolidated Senior Debt and Subordinated Debt.Consolidated EBITDA:
    
    The aggregate of the last four quarters net income from operations plus the sum of:   income taxes;   interest expense;   all provisions for federal, provincial or other income and capital taxes;   depreciation, depletion and amortization expense; and   other non-cash amounts.
 - 61 -




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Material Acquisition:
    
    An acquisition or series of acquisitions which increases the consolidated tangible
assets of Pengrowth by more than 5 percent.Subordinated Debt:
    
    Debt which, by its terms, is subordinated to the obligations to the lenders under
the Credit Facility.Total Capitalization:
    
    The aggregate of Consolidated Total Debt and the Unitholders equity (calculated in
accordance with GAAP as shown on the Trusts consolidated balance sheet)
 Senior Unsecured Notes
   
    
    the ratio of Consolidated EBITDA (as defined below) to interest expense for the four
immediately preceding fiscal quarters shall be not less than 4:1;
    
    with respect to the 2003 U.S. Senior Notes and the U.K. Senior Notes only, the
Consolidated Total Debt (as defined below) is limited to 60 percent of the Consolidated
Total Established Reserves (as defined below) determined and calculated not later than
the last day of the first fiscal quarter of the next succeeding fiscal year of the
Trust;
    
    with respect to the 2007 U.S. Senior Notes only, the Consolidated Total Debt (as
defined below) to Total Capitalization (as defined below) shall not exceed 55 percent
at the end of each fiscal quarter; and
    
    the ratio of Consolidated Total Debt to Consolidated EBITDA for each period of four
consecutive fiscal quarters shall not exceed 3.5:1.
  Consolidated EBITDA:
    
    The sum of the last four quarters of: (i) net income
determined in accordance with GAAP; (ii) all provisions for
federal, provincial or other income and capital taxes;
(iii) all provisions for depletion, depreciation, and
amortization; (iv) interest expense; and (v) non-cash
items.Consolidated Total Debt:
    
    Has substantially the same meaning as Consolidated Senior
Debt in the definitions relating to the Credit Facility.Consolidated Total 
Established Reserves:
    
    The sum of: (i) 100 percent of the present value of
Pengrowths proved reserves; and (ii) 50 percent of the
present value of Pengrowths probable reserves.
 - 62 -




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##### 



Total Capitalization:
    
    Consolidated Total Debt plus Unitholder equity in the Trust.
 Convertible Debentures
 General Development of Pengrowth Energy
Trust  Recent Developments  Changes to Tax Legislation Affecting Pengrowth and its Unitholders
and its Debentureholders
   
    
    the Trust is required to punctually pay or cause to be paid all principal, premium
and interest amounts as prescribed by the Debenture Indenture, as amended;
    
    the Trust is required to pay the trustee under the Debenture Indenture reasonable
remuneration for its services as trustee and repay on demand all monies which have been
paid by the trustee in execution of its obligations thereunder;
    
    the Trust is required to provide the trustee under the Debenture Indenture with
notification immediately upon obtaining knowledge of any Event of Default;
    
    the Trust is required to carry on its business in a proper, efficient and
business-like manner and in accordance with good business practices;
    
    the Trust is required to deliver to the trustee under the Debenture Indenture,
within 120 days of the end of each calendar year, an officers certificate as to
compliance with the terms and conditions of the Debenture Indenture; and
    
    the Trust is prohibited from issuing additional debentures, which are convertible at
the option of the holder into Trust Units of equal ranking to the Debentures if the
principal amount of all
 - 63 -




---



##### 



issued and outstanding convertible debentures of the Trust would exceed 25 percent of
the Trusts total market capitalization after the issuance of such additional
debentures.
 CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
 Taxation of the Trust
 SIFT Legislation
     - 64 -




---



##### 



No assurance can be provided
that the SIFT Legislation will not apply to the Trust prior to 2011.
   Taxation of Unitholders Resident in Canada
   - 65 -




---



##### 



Taxation of Unitholders who are Non-Residents of Canada
     - 66 -




---



##### 



This Annual Information Form may not describe the United States tax consequences of the purchase,
holding or disposition of the Trust Units fully. Non-Resident Unitholders should obtain
independent tax advice as necessary.
 The SIFT Legislation will have a material and adverse impact on the Trust and its Unitholders.
Unitholders are urged to consult their own tax advisors having regard to their own particular
circumstances including the impact of the SIFT Legislation on the Trust and Unitholders. See  Risk
Factors  The SIFT Legislation is expected to materially and adversely affect the Trust, the
Unitholders and the value of the Trust Units .
 UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
 U.S. Internal Revenue
Code of 1986
   - 67 -




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##### 



Classification of Pengrowth Energy Trust as a Partnership
  Certain Income Tax
Considerations  United States Federal Income Tax Considerations  Tax Consequences of Trust Unit
Ownership
  Possible Classification as a Corporation; PFIC Rules
  - 68 -




---



##### 



Consequences of Possible PFIC Classification
    
    
    the excess distribution or gain would be allocated ratably over the United States
holders holding period;
    
    the amount allocated to the current taxable year and any year prior to the first
year in which we were a PFIC would be taxed as ordinary income in the current year;
    
    the amount allocated to each of the other taxable years in the United States
holders holding period would be subject to tax at the highest rate of tax in effect
for the applicable class of taxpayer for that year; and
    
    an interest charge for the deemed deferral benefit would be imposed with respect to
the resulting tax attributable to each such other taxable year.
    - 69 -




---



##### 



Tax Consequences of Trust Unit Ownership
 Flow-through of Taxable Income
    Treatment of Distributions
 Certain Income Tax Considerations  United States
Federal Income Considerations  Disposition of Trust Units
 Basis of Trust Units
 Certain Income Tax Considerations  United
States Federal Income Tax Considerations  Disposition of Trust Units Recognition of Gain or
Loss
 Limitations on Deductibility of Losses
   - 70 -




---



##### 



Limitations on Interest Deductions
  Foreign Tax Credits
  Functional Currency
  Tax Treatment of Trust Operations
 Accounting Method and Taxable Year
  Depletion
  - 71 -




---



##### 



Depreciation
  Valuation of Our Properties
  Section 754 Election
   - 72 -




---



##### 



Disposition of Trust Units
 Recognition of Gain or Loss
    Allocations between Transferors and Transferees
  Notification Requirements
  - 73 -




---



##### 



Constructive Termination
 Certain Income Tax Considerations  United States Federal Income Tax
Considerations  Classification of the Trust as a Partnership
 Treatment of Trust Unit Lending and Short Sales
   Disposition of Trust Units by Redemption
 Certain Income Tax Considerations  United States Federal Income Tax Considerations
 Disposition of Trust Units  Recognition of Gain or Loss
 - 74 -




---



##### 



Uniformity of Trust Units
   Tax-Exempt Organizations
    Administrative Matters
 Trust Information Returns
  Registration as a Tax Shelter
  - 75 -




---



##### 



Reportable Transactions
  Foreign Partnership Reporting
  INDUSTRY CONDITIONS
 Government Regulation
  Pricing and Marketing  Oil
  - 76 -




---



##### 



Pricing and Marketing  Natural Gas
 3
  Pricing and Marketing  Natural Gas Liquids
    Alberta
 General Development of Pengrowth Energy
Trust  Recent Developments  Changes to Royalty Legislation Affecting Pengrowth and its
Unitholders
  - 77 -




---



##### 



British Columbia
   Saskatchewan
   Nova Scotia
  Environmental Regulation
   - 78 -




---



##### 



- 79 -




---



##### 



RISK FACTORS
 If any of the following risks occur, our production, revenues and financial condition could be
materially harmed, with a resulting decrease in distributions on, and the market price of, our
Trust Units. As a result, the trading price of our Trust Units could decline, and you could lose
all or part of your investment. Additional risks are described under the heading Business Risks
in the Managements Discussion Analysis for the year ended December 31, 2007.
 The SIFT Legislation is expected to materially and adversely affect the Trust, the Unitholders and
the value of the Trust Units.
   Volatility in oil and natural gas prices could have a material adverse effect on results of
operations and financial condition, which, in turn, could negatively affect the amount of
distributions to our Unitholders.
  
    
    global energy policy, including the ability of OPEC to set and maintain production
levels for oil;
    
    political conditions in the Middle East;
    
    worldwide economic conditions;
 - 80 -




---



##### 




    
    weather conditions including weather-related disruptions to the North American
natural gas supply;
    
    the supply and price of foreign oil and natural gas;
    
    the level of consumer demand;
    
    the price and availability of alternative fuels;
    
    the proximity to, and capacity of, transportation facilities;
    
    the effect of worldwide energy conservation measures; and
    
    government regulation.
  Distributions may be reduced during periods in which the Corporation makes capital expenditures
using cash flow, which could also negatively affect the market price of the Trust Units.
   Actual reserves will vary from reserve estimates, and those variations could be material, and
negatively affect the market price of the Trust Units and distributions to our Unitholders.
  
    
    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;
 - 81 -




---



##### 




    
    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.
   Continued uncertainty in the credit markets may restrict the availability or increase the cost of
borrowing required for future development and acquisitions.
  If the Corporation is unable to acquire additional reserves, the value of the Trust Units and
distributions to our Unitholders may decline.
  Our operation of oil and natural gas wells could subject us to environmental claims and liability
which would be funded out of our cash flow and could therefore reduce cash flow otherwise payable
to our Unitholders.
  - 82 -




---



##### 



We may be unable to successfully compete with other companies in our industry, which could
negatively affect the market price of the Trust Units and distributions to our Unitholders.
  Incorrect assessments of value at the time of acquisitions could adversely affect the value of our
Trust Units and distributions to our Unitholders.
  Our indebtedness may limit the amount of distributions that we are able to pay our Unitholders, and
if we default on our debts, the net proceeds of any foreclosure sale would be allocated to the
repayment of our lenders, note holders and other creditors and only the remainder, if any, would be
available for distribution to our Unitholders.
 Distributions  Restrictions on
Distributions
 We are dependent on our management and the loss of our key management and other personnel could
negatively impact our business.
  - 83 -




---



##### 



A decline in the Corporations ability to market its oil and natural gas production could have a
material adverse effect on production levels or on the price received for production, which, in
turn, could reduce distributions to our Unitholders and affect the market price of the Trust Units.
  The operation of a significant portion of our properties is largely dependent on the ability of
third party operators, and harm to their business could cause delays and additional expenses in our
receiving revenues, which could negatively affect the market price of the Trust Units and
distributions to our Unitholders.
   Our distributions could be adversely affected by unforeseen title defects, which could reduce
distributions to our Unitholders.
  Fluctuations in foreign currency exchange rates could adversely affect our business, and adversely
affect the market price of the Trust Units as well as distributions to our Unitholders.
  - 84 -




---



##### 



Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of
the Corporation. If the oil and natural gas reserves associated with the Corporations resource
properties are not supplemented through additional development or the acquisition of oil and
natural gas properties, the ability of the Corporation to continue to generate cash flow for
distribution to Unitholders may be adversely affected.
  Management may have conflicts of interest that may create incentives for the Manager to act
contrary to or in competition with the interests of our Unitholders.
    We may incur material costs as a result of compliance with health, safety and environmental laws
and regulations which could negatively affect our financial condition and, therefore, reduce
distributions to our Unitholders and decrease the market price of the Trust Units.
  Lower oil and gas prices increase the risk of write-downs of our oil and gas property investments
which could be viewed unfavourably in the market or could limit our ability to borrow funds or
comply with covenants contained in our current or future credit agreements or other debt
instruments.
  - 85 -




---



##### 



Changes in Canadian legislation could adversely affect the value of our Trust Units.
  If the Trust ceases to qualify as a mutual fund trust it would adversely affect the value of our
Trust Units.
   
    
    The Trust Units would cease to be a qualified investment for trusts governed by
RRSPs, RRIFs, RESPs and DPSPs, as defined in the Tax Act. Where, at the end of a
month, a RRSP, RRIF, RESP or DPSP holds Trust Units that ceased to be a qualified
investment, the RRSP, RRIF, RESP or DPSP, as the case may be, must, in respect of that
month, pay a tax under Part XI.1 of the Tax Act equal to 1 percent of the fair market
value of the Trust Units at the time such Trust Units were acquired by the RRSP, RRIF,
RESP or DPSP. In addition, trusts governed by a RRSP or a RRIF which hold Trust Units
that are not qualified investments will be subject to tax on the income attributable to
the Trust Units while they are non-qualified investments, including the full capital
gains, if any, realized on the disposition of such Trust Units. Where a trust governed
by a RRSP or a RRIF acquires Trust Units that are not qualified investments, the value
of the investment will be included in the income of the annuitant for the year of the
acquisition. Trusts governed by RESPs which hold Trust Units that are not qualified
investments can have their registration revoked by the Canada Revenue Agency.
    
    The Trust would be required to pay a tax under Part XII.2 of the Tax Act. The
payment of Part XII.2 tax by the Trust may have adverse income tax consequences for
certain Unitholders, including non-resident persons and residents of Canada who are
exempt from Part I tax.
    
    The Trust would not be entitled to use the capital gains refund mechanism otherwise
available for mutual fund trusts.
    
    The Trust Units would constitute taxable Canadian property for the purposes of the
Tax Act, potentially subjecting non-residents of Canada to tax pursuant to the Tax Act
on the disposition (or deemed disposition) of such Trust Units.
 The ability of investors resident in the United States to enforce civil remedies may be negatively
affected for a number of reasons.
  - 86 -




---



##### 



Securities
Act of 1933
 
    
    will enforce judgments of United States courts obtained in actions against the Trust
or such persons predicated upon the civil liability provisions of the United States
federal securities laws or the securities or blue sky laws of any state within the
United States; or
    
    will enforce, in original actions, liabilities against the Trust or such persons
predicated upon the United States federal securities laws or any such state securities
or blue sky laws.
 Your rights as a Unitholder differ from the rights associated with other types of investments and
we cannot assure you that the distributions you receive over the life of your investment will meet
or exceed your initial capital investment.
   Future acquisitions may result in substantial future dilution of your Trust Units.
  Canadian and United States practices differ in reporting reserves and production and our estimates
may not be comparable to those of companies in the United States.
   - 87 -




---



##### 



You may be required to pay taxes even if you do not receive any cash distributions.
  Unitholders who are United States persons face certain income tax risks.
  
    
    We have elected under applicable United States Treasury Regulations to be treated as
a partnership for United States federal income tax purposes. Section 7704 of the
Internal Revenue Code of 1986, as amended (the Code) provides that publicly-traded
partnerships such as the Trust will, as a general rule, be taxed as corporations. We
will not be treated as a corporation for U.S. federal income tax purposes only if 90
percent or more of its gross income consists of qualifying income. Although we
expect to satisfy the 90 percent requirement at all times, if we fail to satisfy this
requirement, we will be treated as a foreign corporation. Such conversion will be
taxable unless a certain filing is made.
    
    If we were treated as a foreign corporation, we could be a passive foreign
investment company or PFIC. If we were considered a PFIC, United States holders of
Trust Units could be subject to substantially increased United States tax liability,
including an interest charge upon the sale or other disposition of the United States
holders Trust Units, or upon the receipt of excess distributions from the Trust.
Certain elections may be available to a United States holder if we were classified as a
PFIC to alleviate these adverse tax consequences.
    
    We treat the Royalty between the Trust and the Corporation as a royalty interest for
all legal purposes, including United States federal income tax purposes. The Royalty
Indenture in some respects differs from more conventional net profits interests as to
which the courts and the IRS have ruled regarding the federal income tax treatment as a
royalty, and as a result the propriety of such treatment is not free from doubt. It is
possible that the IRS could contend, for example, that we should be considered to have
a working interest in the properties of the Corporation. If the IRS were successful in
making such a contention, the United States federal income tax consequences to United
States holders could be different, perhaps materially worse, than indicated in the
discussion herein, which generally assumes that the Royalty Indenture will be respected
as a royalty.
    
    Gain or loss will be recognized on a sale of Trust Units equal to the difference
between the amount realized and the United States holders tax basis for the Trust
Units sold. Gain or loss recognized by a United States holder on the sale or exchange
of Trust Units will generally be taxable as capital gain or loss, and will be long-term
capital gain or loss if such United States holders holding period of the Trust Units
exceeds one year. A portion of any amount realized on a sale or exchange of Trust
Units (which portion could be substantial) will be separately
 - 88 -




---



##### 



computed and taxed as ordinary income under Section 751 of the Code to the extent
attributable to the recapture of depletion or depreciation deductions. Ordinary
income attributable to depletion deductions and depreciation recapture could exceed
net taxable gain realized upon the sale of the Trust Units and may be recognized even
if there is a net taxable loss realized on the sale of the Trust Units. Thus, a
United States holder may recognize both ordinary income and a capital loss upon a
taxable disposition of Trust Units.
    
    We have registered as a tax shelter with the United States Secretary of the
Treasury because of the absence of assurance that we will not be subject to tax shelter
registration and in light of the substantial penalties which otherwise might be imposed
if we failed to register and it were subsequently determined that registration was
required. Registration as a tax shelter may increase the risk of an IRS audit of us
or a Unitholder. Any Unitholder owning less than a 1 percent profits interest in us
has very limited rights to participate in the income tax audit process. Further, any
adjustments in our tax returns will lead to adjustments in our Unitholders tax returns
and may lead to audits of Unitholders tax returns and adjustments of items unrelated
to us. You will bear the cost of any expense incurred in connection with an
examination of your personal tax return.
    
    Because we cannot match transferors and transferees of Trust Units, we must maintain
uniformity of the economic and tax characteristics of the Trust Units to a purchaser of
these Trust Units. In the absence of such uniformity, the Trust may be unable to
comply completely with a number of federal income tax requirements. A lack of
uniformity, however, can result from a literal application of some Treasury
regulations. If any non-uniformity was required by the IRS, it could have a negative
impact on the value of the Trust Units.
    
    The Trust may not be an appropriate investment for certain types of entities. For
example, there is a risk that some of the Trusts income could be unrelated business
taxable income with respect to tax-exempt organizations. Prospective purchasers of
Trust Units that are tax-exempt organizations are encouraged to consult their tax
advisors regarding investments in Trust Units.
    
    The present U.S. federal income tax treatment of publicly traded partnerships,
including us, or an investment in our Trust Units may be modified by administrative,
legislative or judicial interpretation at any time. For example, in response to
certain recent developments, members of Congress are considering substantive changes to
the existing U.S. tax laws that would affect certain publicly traded partnerships. Any
modification to the U.S. federal income tax laws and interpretations thereof may or may
not be applied retroactively. Although the currently proposed legislation would not
appear to affect our tax treatment, we are unable to predict whether any of these
changes, or other proposals, will ultimately be enacted. Any such changes could
negatively impact the value of an investment in our Trust Units.
    
    We prorate our items of income, gain, loss and deduction between transferors and
transferees of our Trust Units each month based upon the ownership of our Trust Units
on the first day of each month, instead of on the basis of the date a particular Trust
Unit is transferred. The use of the proration method may not be permitted under
existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to
the validity of this method. If the IRS were to challenge this method or new Treasury
Regulations were issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our Unitholders.
    
    On September 21, 2007, Canada and the United States signed the Protocol to the
Canada-U.S. Convention. On December 14, 2007, Canada completed the steps required to
give effect to the Protocol. The Protocol will come into force once it has been
ratified by the United States, and the two countries have formally notified each other
that their procedures are complete. The Protocol contains new Article IV(7)(b), a
treaty benefit denial rule, which would increase the Canadian withholding tax on
Pengrowths distributions (which for the purposes of this paragraph
 - 89 -




---



##### 



includes deemed dividends pursuant to the SIFT Legislation) to Non-Resident
Unitholders who are residents of the U.S. for the purposes of the Canada-U.S.
Convention. Article IV(7)(b) of the Protocol will not come into force until the
first day of the third calendar year that ends after the Protocol is in force.
Article IV(7)(b) of the Protocol generally denies benefits under the Canada-U.S.
Convention in circumstances where (i) a Unitholder who is a resident of the U.S. for
the purposes of the Canada-U.S. Convention receives an amount, such as a
distribution, from an entity that is a resident of Canada, such as Pengrowth, (ii)
Pengrowth is treated as a fiscally transparent entity for U.S. federal income tax
purposes, which is the case inasmuch as Pengrowth is treated as a partnership for
U.S. federal income tax purposes, and (iii) the tax treatment of the amount (or
distribution) received by the U.S. Resident Unitholder would, for U.S. federal income
tax purposes, be different if Pengrowth were not treated as fiscally transparent for
U.S. federal income tax purposes. The effect of Article IV(7)(b) of the Protocol is
that the Canadian withholding tax rate on distributions of income would be 25 percent
instead of 15 percent or such lower rate otherwise available under the Canada-U.S.
Convention. Returns of capital would still be subject to a 15 percent Canadian
withholding tax and such rate is not modified by the Protocol. The Protocol also
contains measures which, generally speaking, are designed to limit the benefits under
the Canada-U.S. Convention to treaty shopping transactions or arrangements.
 Distributions to our Unitholders may be reduced during periods in which Pengrowth makes capital
expenditures using cash flow.
  Changes in government regulations that affect the crude oil and natural gas industry could
adversely affect Pengrowth and reduce our distributions to our Unitholders.
     - 90 -




---



##### 



General Development of Pengrowth
Energy Trust  Recent Developments  Changes to Royalty Legislation Affecting Pengrowth and its
Unitholders
 If Pengrowth expands operations beyond oil and natural gas production in Canada, Pengrowth may face
new challenges and risks. If Pengrowth is unsuccessful in managing these challenges and risks, its
results of operations and financial condition could be adversely affected, which could affect the
market price of the Trust Units and distributions to Unitholders.
  Delays in business operations could adversely affect the Trusts distributions to Unitholders and
the market price of the Trust Units.
  
    
    restrictions imposed by lenders;
    
    accounting delays;
    
    delays in the sale or delivery of products;
    
    delays in the connection of wells to a gathering system;
    
    blowouts or other accidents;
    
    adjustments for prior periods;
    
    recovery by the operator of expenses incurred in the operation of the properties; or
    
    the establishment by the operator of reserves for these expenses.
 
 - 91 -




---



##### 



Changes in market-based factors may adversely affect the trading price of the Trust Units.
  The limited liability of Unitholders is uncertain.
  The redemption right of Unitholders is limited.
 Description of Trust Units  Redemption Right in specie
 The industry in which Pengrowth operates exposes Pengrowth to potential liabilities that may not be
covered by insurance.
  - 92 -




---



##### 



MARKET FOR SECURITIES
  Toronto Stock Exchange
    
    New York Stock ExchangeTrust Unit Price Range
    
    
    
    
    
    Trust Unit Price RangeHigh
    
    Low
    
    Close
    
    Volume
    
    High
    
    Low
    
    Close
    
    Volume(Canadian $ per Trust Unit)
    
    (thousands)
    
    (U.S. $ per Trust Unit)
    
    (thousands)2007January
    
    
    20.55
    
    
    
    18.62
    
    
    
    19.85
    
    
    
    15,459
    
    
    
    17.41
    
    
    
    15.82
    
    
    
    16.94
    
    
    
    10,566February
    
    
    20.85
    
    
    
    19.50
    
    
    
    19.98
    
    
    
    9,312
    
    
    
    17.96
    
    
    
    16.67
    
    
    
    17.23
    
    
    
    6,983March
    
    
    20.37
    
    
    
    18.71
    
    
    
    19.45
    
    
    
    12,971
    
    
    
    17.59
    
    
    
    15.95
    
    
    
    16.87
    
    
    
    9,085April
    
    
    19.83
    
    
    
    18.82
    
    
    
    19.11
    
    
    
    9,615
    
    
    
    17.74
    
    
    
    16.45
    
    
    
    17.27
    
    
    
    7,127May
    
    
    20.62
    
    
    
    19.00
    
    
    
    19.92
    
    
    
    9,382
    
    
    
    19.05
    
    
    
    17.18
    
    
    
    18.73
    
    
    
    9,519June
    
    
    21.04
    
    
    
    19.68
    
    
    
    20.27
    
    
    
    9,351
    
    
    
    19.84
    
    
    
    18.50
    
    
    
    19.09
    
    
    
    7,021July
    
    
    20.70
    
    
    
    18.71
    
    
    
    19.51
    
    
    
    8,746
    
    
    
    19.85
    
    
    
    17.51
    
    
    
    18.30
    
    
    
    5,870August
    
    
    19.50
    
    
    
    17.40
    
    
    
    18.04
    
    
    
    7,886
    
    
    
    18.43
    
    
    
    16.25
    
    
    
    17.06
    
    
    
    6,396September
    
    
    18.78
    
    
    
    16.92
    
    
    
    18.64
    
    
    
    11,608
    
    
    
    18.87
    
    
    
    16.65
    
    
    
    18.84
    
    
    
    7,019October
    
    
    18.68
    
    
    
    17.65
    
    
    
    18.00
    
    
    
    8,144
    
    
    
    19.10
    
    
    
    17.90
    
    
    
    18.92
    
    
    
    5,681November
    
    
    18.45
    
    
    
    17.00
    
    
    
    18.11
    
    
    
    8,417
    
    
    
    19.21
    
    
    
    17.70
    
    
    
    18.13
    
    
    
    5,239December
    
    
    18.50
    
    
    
    17.31
    
    
    
    17.62
    
    
    
    6,998
    
    
    
    18.24
    
    
    
    17.30
    
    
    
    17.77
    
    
    
    3,060
 - 93 -




---



##### 



Toronto Stock ExchangeDebenture Price RangeHigh
    
    Low
    
    Close
    
    Volume(Canadian $ per Debenture)
    
    (thousands)2007January
    
    
    102.49
    
    
    
    98.51
    
    
    
    101.01
    
    
    
    1,738February
    
    
    102.25
    
    
    
    101.00
    
    
    
    101.25
    
    
    
    828March
    
    
    102.55
    
    
    
    100.00
    
    
    
    100.51
    
    
    
    767April
    
    
    102.55
    
    
    
    99.77
    
    
    
    102.00
    
    
    
    661May
    
    
    104.00
    
    
    
    100.60
    
    
    
    101.10
    
    
    
    279June
    
    
    102.50
    
    
    
    100.00
    
    
    
    100.51
    
    
    
    494July
    
    
    102.99
    
    
    
    100.03
    
    
    
    100.04
    
    
    
    327August
    
    
    100.02
    
    
    
    98.00
    
    
    
    99.50
    
    
    
    590September
    
    
    99.75
    
    
    
    98.50
    
    
    
    99.00
    
    
    
    560October
    
    
    100.80
    
    
    
    99.00
    
    
    
    99.75
    
    
    
    518November
    
    
    101.00
    
    
    
    98.50
    
    
    
    99.50
    
    
    
    633December
    
    
    102.89
    
    
    
    98.00
    
    
    
    100.00
    
    
    
    1,149.3
 - 94 -




---



##### 



DIRECTORS AND OFFICERS
  Directors and Officers of the Manager
  Name and Jurisdiction
    
    Position withof Residence
    
    Pengrowth Management
    
    Principal OccupationJames S. Kinnear 
Alberta, Canada
    
    President and Director (since 1982)
    
    President
Pengrowth Management LimitedGordon M. Anderson 
Alberta, Canada
    
    Vice President, Financial Services (since 2001)
Vice President, Treasurer (1998-2001) 
Treasurer (1995-1998)
    
    Vice President, Financial Services
Pengrowth Management LimitedGrant A. Henschel 
Alberta, Canada
    
    Vice President, Engineering
    
    Vice President, Engineering
Pengrowth Management LimitedLeslie F. Kende 
Alberta, Canada
    
    Vice President, New Ventures
    
    Vice President, New Ventures
Pengrowth Management LimitedRobert M. Nicolay 
Alberta, Canada
    
    Vice President, Business Development
    
    Vice President, Business Development
Pengrowth Management LimitedCharles V. Selby 
Alberta, Canada
    
    Corporate Secretary (since 1993)
Treasurer
    
    President
Selby Professional Corporation
  Principal Holders of Shares of the Manager
  - 95 -




---



##### 



Directors and Officers of the Corporation
  Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)James S. Kinnear
    
    President, Chairman, Director and
    
    President
    
    
    5,996,238Alberta, Canada
    
    Chief Executive Office (since 1988)
    
    Pengrowth Management LimitedThomas A. Cumming(2)(4)(5)
    
    Director (since 2000)
    
    Business Consultant
    
    
    8,678Alberta, CanadaWayne K. Foo(2)(3)
    
    Director (since 2006)
    
    President
    
    
    3,843Alberta, Canada
    
    
    
    Petro Andina Resources Ind.Kirby L. Hedrick(2)(5)
    
    Director (since 2005)
    
    Business Consultant
    
    
    4,000Wyoming, United States ofAmericaMichael S. Parrett(3)(4)(5)
    
    Director (since 2004)
    
    Business Consultant
    
    
    4,000Ontario, CanadaA. Terence Poole(3)(5)
    
    Director (since 2005)
    
    Business Consultant
    
    
    30,000Alberta, CanadaD. Michael G. Stewart(2)(4)
    
    Director (since 2006)
    
    Principal of the Ballinacurra Group,
    
    
    13,370Alberta, Canada
    
    
    
    Corporate DirectorNicholas C.H. Villiers
    
    Director (since 2007)
    
    Business Consultant
    
    
    London, EnglandJohn B.
Zaozirny(3)(4)
    
    Director (since 1988)
    
    Counsel, McCarthy Tétrault
    
    
    35,100Alberta, Canada
    
    
    
    Barristers and SolicitorsGordon M. Anderson
    
    Vice President (since 2001)
    
    Vice President, Financial Services
    
    
    21,066Alberta, Canada
    
    Vice President, Treasurer (1997-2001)
    
    Pengrowth Management LimitedTreasurer (1995-1997)Chief Financial Officer (1991-1998)Douglas C. Bowles
    
    Vice President and Controller
    
    Vice President and Controller
    
    
    11,446Alberta, Canada
    
    (since March 1, 2006)
    
    Pengrowth CorporationController (since 2005)James E.A. Causgrove
    
    Vice President, Production and
    
    Vice President, Production and
    
    
    23,621Alberta, Canada
    
    Operations (since 2005)
    
    Operations Pengrowth CorporationPeter Cheung
    
    Vice President (since 2008)
    
    Vice President and Treasurer
    
    
    17,428Alberta, Canada
    
    Treasurer (since 2005)
    
    Pengrowth CorporationWilliam G. Christensen
    
    Vice President, Strategic Planning and
    
    Vice President, Strategic
    
    
    15,821Alberta, Canada
    
    Reservoir Exploitation (since 2005)
    
    Planning and Reservoir Exploitation
Pengrowth CorporationJames M. Donihee
    
    Vice-President and Chief of Staff
    
    Vice-President and Chief of Staff
    
    
    7,086Alberta, Canada
    
    (since 2007)
    
    Pengrowth Corporation
 - 96 -




---



##### 



Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)Charles V. SelbyAlberta, Canada
    
    Vice President and Corporate Secretary (since 2005)
    
    PresidentSelby Professional Corporation
    
    
    146,916Corporate Secretary (since 1993)Larry B. Strong
    
    Vice President, Geosciences (since 2005)
    
    Vice President, Geosciences
    
    
    37,118Alberta, Canada
    
    
    
    Pengrowth CorporationChristopher G. Webster
    
    Chief Financial Officer (since 2005)
    
    Chief Financial Officer
    
    
    37,065Alberta, Canada
    
    Treasurer (2000  2005)
    
    Pengrowth Corporation
 Notes:(1)
    
    As at December 31, 2007 and excluding Trust Units issuable upon the exercise of outstanding
options, rights or deferred entitlement units.(2)
    
    Member of Reserves, Operations and Environmental, Health and Safety Committee.(3)
    
    Member of Corporate Governance Committee.(4)
    
    Member of Compensation Committee.(5)
    
    Member of Audit Committee.
    Corporate Cease Trade Orders or Bankruptcies
  (i)
    
    was the subject of a cease trade or similar order or an order that denied the
relevant company access to any exemption under securities legislation for a period of
more than 30 consecutive days; or
 - 97 -




---



##### 



(ii)
    
    was subject to an event that resulted, after the person ceased to be a director
or executive officer, in the company being the subject of a cease trade or similar
order or an order that denied the relevant company access to any exemption under
securities legislation for a period of more than 30 consecutive days; or(iii)
    
    within a year of that person ceasing to act in that capacity, became bankrupt,
made a proposal under any legislation relating to bankruptcy or insolvency or was
subject to or instituted any proceedings, arrangement or compromise with creditors or
had a receiver, receiver manager or trustee appointed to hold its assets.
 Personal Bankruptcies
  Penalties or Sanctions
  (i)
    
    been subject to any penalties or sanctions imposed by a court relating to
securities legislation or by a securities regulatory authority or has entered into a
settlement agreement with a securities regulatory authority, other than penalties for
late filing of insider reports; or(ii)
    
    been subject to any other penalties or sanctions imposed by a court or
regulatory body that would likely be considered important to a reasonable investor in
making an investment decision.
 AUDIT COMMITTEE
 Audit Committees
 FinanciallyName
    
    Independent
    
    Literate
    
    Relevant Education and ExperienceThomas A. Cumming
    
    Yes
    
    Yes
    
    Mr. Cumming was President and
Chief Executive Officer of the
Alberta Stock Exchange from 1988
to 1999. His career also
includes 25 years with a major
Canadian bank both nationally
and internationally. He is
currently Chairman of Albertas
Electricity Balancing Pool, and
serves as a Director of the
Alberta Capital Market
Foundation. He is also a past
president of the Calgary Chamber
of Commerce. Mr. Cumming is a
professional engineer and holds
a Bachelor of Applied Science
degree in Engineering and
Business from the University of
Toronto.Michael S. Parrett
    
    Yes
    
    Yes
    
    Mr. Parrett is currently an
independent consultant providing
advisory service to various
companies in Canada and the
United States. Mr. Parrett is
Chairman of Gabriel Resources
Limited, a member of the board
of Fording Inc. and is serving
as a Trustee for Fording
Canadian Coal Trust. He was
formerly President of Rio Algom
Limited and prior to that Chief
Financial Officer of Rio Algom
and Falconbridge Limited. Mr.
Parrett is a chartered
accountant and holds a Bachelor
of Arts in Economics from York
University.
 - 98 -




---



##### 



FinanciallyName
    
    Independent
    
    Literate
    
    Relevant Education and ExperienceA. Terence Poole
    
    Yes
    
    Yes
    
    Mr. Poole brings extensive
senior financial management,
accounting, capital and debt
market experience to Pengrowth.
He retired from Nova Chemicals
Corporation in 2006 where he had
held various senior management
positions including Executive
Vice-President, Corporate
Strategy and Development. Mr.
Poole currently serves on the
board of directors for Methanex
Corporation and Synenco Energy
Inc. Mr. Poole received a
Bachelor of Commerce degree from
Dalhousie University and holds a
Chartered Accountant
designation.Kirby L. Hedrick
    
    Yes
    
    Yes
    
    Mr. Hedrick has extensive
engineering and senior
management experience in the
United States and
internationally, retiring in
2000 as Executive
Vice-President, Upstream of
Phillips Petroleum. He
currently serves on the board of
directors of Noble Energy Inc.
and has recently been appointed
to the Wyoming Environmental
Quality Council. Mr. Hedrick
received a Bachelor of Science
and Mechanical Engineering
degree from the University of
Evansville, Indiana in 1975. He
completed the Stanford Executive
Program in 1997 and the Stanford
Corporate Governance Program in
2003.
 Principal Accountant Fees and Services
  2007
    
    2006Audit Fees
    
    
    1,393
    
    
    
    980Audit Related Fees
    
    
    
    
    
    
    Tax Fees
    
    
    163
    
    
    
    138All Other Fees
    
    
    
    
    
    
    Total
    
    
    1,556
    
    
    
    1,118
 Audit Fees
  Audit-Related Fees
  Tax Fees
  Pre-approval Policies and Procedures
  - 99 -




---



##### 



de minimis
 CONFLICTS OF INTEREST
   
    
    the issuance of additional Trust Units;
    
    material acquisitions and dispositions of properties;
    
    material capital expenditures;
    
    borrowing; and
    
    the payment of distributable cash.
 Insider Bids, Issuer Bids, Going Private Transactions and Related
Party Transactions.
  - 100 -




---



##### 



LEGAL PROCEEDINGS
  INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
   INTERESTS OF EXPERTS
  AUDITORS, TRANSFER AGENT AND REGISTRAR
  MATERIAL CONTRACTS
  1.
    
    Trust Indenture;2.
    
    Royalty Indenture;3.
    
    Unanimous Shareholders Agreement;4.
    
    Management Agreement;5.
    
    the Fifth Amended and Restated Credit Agreement dated June 17, 2007 between Pengrowth and a
syndicate of eleven financial institutions concerning the Credit Facility;6.
    
    the Bridge Credit Agreement dated January 22, 2007 between Pengrowth and a syndicate of ten
financial institutions entered into in conjunction with the CP Acquisition;7.
    
    the Acquisition Agreement dated November 28, 2006 in connection with the CP Acquisition;
 - 101 -




---



##### 



8.
    
    the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes;9
    
    the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes;10.
    
    the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes;11.
    
    the Debenture Indenture;12.
    
    the first supplemental trust indenture relating to the Debentures dated October 2, 2006; and12.
    
    the Distribution Agreement.
  CODE OF ETHICS
 U.S.
Securities Exchange Act of 1934 www.pengrowth.com
   OFF-BALANCE SHEET ARRANGEMENTS
  DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE
   - 102 -




---



##### 



ADDITIONAL INFORMATION
    Investor Relations
    
    Toronto Investor RelationsPengrowth Energy Trust
    
    Scotia Plaza, 40 King Street WestSuite 2100, 222  3rd Avenue S.W.
    
    Suite 3006, Box 106Calgary, Alberta T2P 0B4
    
    Toronto, Ontario M5H 3Y2Telephone: (403) 233-0224
    
    Telephone: (416) 362-1748(888) 744-1111
    
    (888) 744-1111Fax: (866) 341-3586
 www.pengrowth.com  investorrelations@pengrowth.com
 - 103 -




---



##### 



APPENDIX A
 Report On Reserves Data By Independent
 Qualified Reserves Evaluator On Form 51-101F2




---



##### 



FORM 51-101F2
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
  1.
    
    We have prepared an evaluation of the Companys reserves data as at December 31, 2007. The
reserves data are estimates of proved reserves and probable reserves and related future net
revenue as at December 31, 2007, estimated using forecast prices and costs.2.
    
    The reserves data are the responsibility of the Companys management. Our responsibility is
to express an opinion on the reserves data based on our evaluation.We carried out our evaluation in accordance with standards set out in the Canadian Oil and
Gas Evaluation Handbook (the COGE Handbook) prepared jointly by the Society of Petroleum
Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy &
Petroleum (Petroleum Society).3.
    
    Those standards require that we plan and perform an evaluation to obtain reasonable assurance
as to whether the reserves data are free of material misstatement. An evaluation also
includes assessing whether the reserves data are in accordance with principles and definitions
in the COGE Handbook.4.
    
    The following table sets forth the estimated future net revenue (before deduction of income
taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs
and calculated using a discount rate of 10 percent, included in the reserves data of the
Company evaluated by us for the year ended December 31, 2007, and identifies the respective
portions thereof that we have audited, evaluated and reviewed and reported on to the Companys
board of directors:
 Description andPreparation Date
    
    Location of Reserves
    
    Net Present Value of Future Net RevenueIndependent Qualified
    
    of Evaluation
    
    (Country or Foreign
    
    (before income taxes, 10% discount rate - $MM)Reserves Evaluator
    
    Report
    
    Geographic Area)
    
    Audited
    
    Evaluated
    
    Reviewed
    
    TotalGLJ Petroleum Consultants
    
    January 15, 2008
    
    Canada
    
    
    
    $5,456
    
    
    
    $5,456
 5.
    
    In our opinion, the reserves data respectively evaluated by us have, in all material
respects, been determined and are in accordance with the COGE Handbook.6.
    
    We have no responsibility to update our reports referred to in paragraph 4 for events and
circumstances occurring after their respective preparation dates.




---



##### 



7.
    
    Because the reserves data are based on judgments regarding future events, actual results will
vary and the variations may be material.
    (signed) Doug R. SuttonDoug R. Sutton, P.Eng.Vice-President
 - 2 -




---



##### 



APPENDIX B
 Report Of Management And Directors On
 Oil And Gas Disclosure On Form 51-101F3




---



##### 



FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
    (a)
    
    reviewed the Companys procedures for providing information to the independent qualified
reserves evaluator;
 (b)
    
    met with the independent qualified reserves evaluator to determine whether any restrictions
affected the ability of the independent qualified reserves evaluator to report without
reservation; and(c)
    
    reviewed the reserves data with management and the independent qualified reserves evaluator.
  (a)
    
    the content and filing with securities regulatory authorities of Form 51-101F1 containing
reserves data and other oil and gas information;
 (b)
    
    the filing of Form 51-101F2 which is the report of the independent qualified reserves
evaluator on the reserves data; and(c)
    
    the content and filing of this report.




---



##### 



(signed) James S. KinnearJames S. KinnearChairman, President and Chief Executive OfficerPengrowth Corporation(signed) William G. ChristensenWilliam G. ChristensenVice President, Strategic Planning and Reservoir ExploitationPengrowth Corporation(signed) Kirby L. HedrickKirby L. HedrickDirectorPengrowth Corporation(signed) D. Michael G. StewartD. Michael G. StewartDirectorPengrowth CorporationSeptember 15, 2008
 - 2 -




---



##### 



APPENDIX C
 Audit Committee Terms of Reference




---



##### 



TERMS OF REFERENCE
AUDIT COMMITTEE
 PENGROWTH CORPORATION
PENGROWTH ENERGY TRUST
 Objectives
   
    
    monitor the performance of Pengrowths internal audit function and the integrity of
Pengrowths financial reporting process and systems of internal controls regarding
finance, accounting, and legal compliance;
    
    assist Board oversight of: (i) the integrity of Pengrowths financial statements;
(ii) Pengrowths compliance with legal and regulatory requirements; and (iii) the
performance of Pengrowths internal audit function and independent auditors;
    
    monitor the independence, qualification and performance of Pengrowths external
auditors; and
    
    provide an avenue of communication among the external auditors, the internal
auditors, management and the Board.
  Composition
 Audit Committees Securities Exchange Act of 1934




---



##### 



- 3 - Meetings and Minutes
    in camera
    Scope, Duties and Responsibilities
 Mandatory Duties
 Review Procedures
  1.
    
    Review and reassess the adequacy of the Audit Committees Terms of Reference at least
annually, submit the Terms of Reference to the Board for approval and have the document
published at least every three years in accordance with the regulations of the United States
Securities and Exchange Commission.2.
    
    Prior to filing or public distribution, review, discuss with management and the internal and
external auditors and recommend to the Board for approval, Pengrowths audited annual
financial statements, annual earnings press releases, annual information form, all statements
including the related managements discussion and analysis required in prospectuses and other
offering memoranda, financial statements required by regulatory authorities, all prospectuses
and all documents which may




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##### 



- 4 - be incorporated by reference into a prospectus, including without limitation, the annual
proxy circular. Approve, on behalf of the Board, Pengrowths interim financial statements
and related managements discussion and analysis and interim earnings press releases. This
review should include discussions with management, the internal auditors and the external
auditors of significant issues regarding accounting principles, practices and judgements.
Discuss any significant changes to Pengrowths accounting principles and any items required
to be communicated by the external auditors in accordance with Assurance and Related
Services Guideline #11 (AuG-11).
 3.
    
    Ensure that adequate procedures are in place for the review of Pengrowths public disclosure
of financial information extracted or derived from Pengrowths financial statements, other
than the public disclosure referred to in paragraph 2 above and periodically assess the
adequacy of those procedures.
 4.
    
    Be responsible for reviewing the disclosure contained in Pengrowths annual information form
as required by Form 52-110F1 Audit Committee Information Required in an AIF, attached to MI
52-110. If proxies are solicited for the election or directors of the Corporation, the Audit
Committee shall be responsible for ensuring that Pengrowths information circular includes a
cross-reference to the sections in Pengrowths annual information form that contain the
information required by Form 52-110F1.
 External Auditors
 1.
    
    The Audit Committee shall advise the external auditors of their accountability to the Audit
Committee and the Board as representatives of the unitholders of the Trust to whom the
external auditors are ultimately responsible. The external auditors shall report directly to
the Audit Committee. The Audit Committee is directly responsible for overseeing the work of
the external auditors, shall review at least annually the independence and performance of the
external auditors and shall annually recommend to the Board the appointment of the external
auditors or approve any discharge of auditors when circumstances warrant. The Audit Committee
shall, on an annual basis, obtain and review a report by the external auditor describing: (i)
the external auditors internal quality-control procedures; (ii) any material issues raised by
the most recent internal quality-control review, or peer review, of the external auditors, or
by any inquiry or investigation by governmental or professional authorities, within the
preceding five years, respecting one or more independent audits carried out by the external
auditors, and any steps taken to deal with any such issues; and (iii) all relationships
between the independent auditor and Pengrowth.2.
    
    Approve the fees and other compensation to be paid to the external auditors.3.
    
    Pre-approve all services to be provided to Pengrowth or its subsidiary entities by
Pengrowths external auditors and all related terms of engagement.
 Other Audit Committee Responsibilities
 4.
    
    Establish procedures for: (i) the receipt, retention and treatment of complaints received by
Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii)
the confidential and anonymous submission by employees of Pengrowth of concerns regarding
questionable accounting or auditing matters.5.
    
    Review and approve Pengrowths hiring policies regarding partners, employees and former
partners and employees of the present and former external auditors of Pengrowth.
 Discretionary Duties




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##### 



- 5 - Review Procedures
 1.
    
    In consultation with management, the internal auditors and the external auditors, consider
the integrity of Pengrowths financial reporting processes and controls and the performance of
Pengrowths internal financial accounting staff; discuss significant financial risk exposures
and the steps management has taken to monitor, control and report such exposures; and review
significant findings prepared by the internal or external auditors together with managements
responses.2.
    
    Review with financial management, the internal auditors and the external auditors Pengrowths
policies relating to risk management and risk assessment.3.
    
    Meet separately with each of management, the internal auditors and the external auditors to
discuss difficulties or concerns, specifically: (i) any difficulties encountered in the course
of the audit work, including any restrictions on the scope of activities or access to
requested information, and any significant disagreements with management; (ii) any changes
required in the planned scope of the audit; and (iii) the responsibilities, budget, and
staffing of the internal audit function, and report to the Board on such meetings.4.
    
    Conduct an annual performance evaluation of the Audit Committee.
 Internal Auditors
 1.
    
    Review the annual audit plans of the internal auditors.2.
    
    Review the significant findings prepared by the internal auditors and recommendations issued
by any external party relating to internal audit issues, together with managements response.3.
    
    Review the adequacy of the resources of the internal auditors to ensure the objectivity and
independence of the internal audit function.4.
    
    Consult with management on managements appointment, replacement, reassignment or dismissal
of the internal auditors.5.
    
    Ensure that the internal auditors have access to the Lead Director, the Chair of the Board
and the Chief Executive Officer.
 External Auditors
 1.
    
    On an annual basis, the Audit Committee should review and discuss with the external auditors
all significant relationships they have with Pengrowth that could impair the auditors
independence.2.
    
    The Audit Committee shall review the external auditors audit plan  discuss scope, staffing,
locations, and reliance upon management and general audit approach.3.
    
    Consider the external auditors judgments about the quality and appropriateness of
Pengrowths accounting principles as applied in its financial reporting.4.
    
    Be responsible for the resolution of disagreements between management and the external
auditors regarding financial performance.5.
    
    Ensure compliance by the external auditors with the requirements set forth in National
Instrument 52-108 Auditor Oversight.




---



##### 



- 6 - 6.
    
    Ensure that the external auditors are participants in good standing with the Canadian Public
Accountability Board (CPAB) and participate in the oversight programs established by the
CPAB from time to time and that the external auditors have complied with any restrictions or
sanctions imposed by the CPAB as of the date of the applicable auditors report relating to
Pengrowths annual audited financial statements.7.
    
    Monitor compliance with the lead auditor rotation requirements of Regulation S-X.
 Other Audit Committee Responsibilities
 1.
    
    On at least an annual basis, review with Pengrowths counsel any legal matters that could
have a significant impact on the organizations financial statements, Pengrowths compliance
with applicable laws and regulations, and inquiries received from regulators or governmental
agencies.2.
    
    Annually prepare a report to unitholders as required by the United States Securities and
Exchange Commission; the report should be included in Pengrowths annual proxy statement.3.
    
    Ensure the preparation and filing of each annual certificate in Form 52-109F1 and each
interim certificate in Form 52-109F2 to be signed by each of the Chief Executive Officer and
Chief Financial Officer of the Corporation in accordance with the requirements set forth under
Multilateral Instrument 52-109 Certification of Disclosure in Issuers Annual and Interim
Filings, as amended from time to time (MI 52-109).4.
    
    In respect of annual filings only, the Audit Committee is responsible for ensuring that
management evaluates the effectiveness of Pengrowths disclosure controls and procedures as of
the end of the period covered by the annual filings and has caused Pengrowth to disclose in
the annual managements discussion and analysis its conclusions about the effectiveness of the
disclosure controls and procedures as of the end of the period covered by the annual filings
based on such evaluation. The terms annual filings, interim filings, disclosure controls
and procedures and internal control over financial reporting shall have the meanings set
forth under MI 52-109.5.
    
    Be responsible for monitoring any changes in Pengrowths internal control over financial
reporting and for ensuring that any change that occurred during Pengrowths most recent
interim period that has materially affected, or is reasonably likely to materially affect,
Pengrowths internal control over financial reporting is disclosed in Pengrowths most recent
annual or interim managements discussion and analysis.6.
    
    Review all exceptions to established policies, procedures and internal controls of Pengrowth,
which have been approved by any two officers of the Corporation.7.
    
    Perform any other activities consistent with this Charter, the Trust Indenture, the
Corporations by-laws, and other governing law as the Audit Committee or the Board deems
necessary or appropriate.8.
    
    Maintain minutes of meetings and periodically report to the Board on significant results of
the foregoing activities.
 Communication, Authority to Engage Advisors and Expenses




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##### 



- 7 -




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##### 



Schedule A
 Excerpt from Multilateral Instrument 52-110
 Standard of Independence
 1.
    
    An audit committee member is independent if he or she has no direct or indirect material
relationship with Pengrowth.
 2.
    
    For the purposes of paragraph 1, a material relationship is a relationship which could, in
the view of the Board, be reasonably expected to interfere with the exercise of a members
independent judgment.
 3.
    
    Despite paragraph 2, the following individuals are considered to have a material relationship
with Pengrowth:
 (a)
    
    an individual who is, or has been within the last three years, an employee or
executive officer of Pengrowth;(b)
    
    an individual whose immediate family member is, or has been within the last
three years, an executive officer of Pengrowth;(c)
    
    an individual who:
 (i)
    
    is a partner of a firm that is Pengrowths internal or external
auditor,(ii)
    
    is an employee of that firm, or(iii)
    
    was within the last three years a partner or employee of that
firm and personally worked on Pengrowths audit within that time;
 (d)
    
    an individual whose spouse, minor child or stepchild, or child or stepchild who shares a home with the individual:
 (i)
    
    is a partner of a firm that is Pengrowths internal or external
auditor,(ii)
    
    is an employee of that firm and participates in its audit,
assurance or tax compliance (but not tax planning) practice, or(iii)
    
    was within the last three years a partner or employee of that
firm and personally worked on Pengrowths audit within that time;
 (e)
    
    an individual who, or whose immediate family member, is or has been within the
last three years, an executive officer of an entity if any of Pengrowths current
executive officers serves or served at that same time on the entitys compensation
committee; and(f)
    
    an individual who received, or whose immediate family member who is employed as
an executive officer of Pengrowth received, more than $75,000 in direct compensation
from the issuer during any 12 month period within the last three years.
 4.
    
    Despite paragraph 3, an individual will not be considered to have a material relationship
with Pengrowth solely because he or she had a relationship identified in paragraph 3 if that
relationship ended before March 30, 2004.




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##### 



A-2 
 5.
    
    For the purposes of paragraphs 3(c) and 3(d), a partner does not include a fixed income
partner whose interest in the firm that is the internal or external auditor is limited to the
receipt of fixed compensation (including deferred compensation) for prior service with that
firm if the compensation is not contingent in any way on continued service.
 6.
    
    For the purposes of paragraph 3(f), direct compensation does not include
 (a)
    
    remuneration for acting as a member of the Board or any Board committee of
Pengrowth, and(b)
    
    the receipt of fixed amounts of compensation under a retirement plan (including
deferred compensation) for prior service with Pengrowth if the compensation is not
contingent in any way on continued service.
 7.
    
    Despite paragraph 3, an individual will not be considered to have a material relationship
with Pengrowth solely because the individual or his or her immediate family member
 (a)
    
    has previously acted as an interim chief executive officer of Pengrowth, or(b)
    
    acts, or has previously acted, as a chair or vice-chair of the Board or of any
Board committee of Pengrowth on a part-time basis.
 8.
    
    Despite any determination made under paragraphs 1 through 7, an individual who
 (a)
    
    accepts, directly or indirectly, any consulting, advisory or other compensatory
fee from Pengrowth, other than as remuneration for acting in his or her capacity as a
member of the Board or any Board committee, or as a part-time chair or vice-chair of
the Board or any Board committee; or(b)
    
    is an affiliated entity of Pengrowth or any of its subsidiary entities,
is considered to have a material relationship with Pengrowth.
 9.
    
    For the purposes of paragraph 8, the indirect acceptance by an individual of any consulting,
advisory or other compensatory fee includes acceptance of a fee by
 (a)
    
    an individuals spouse, minor child or stepchild, or a child or stepchild who shares the individuals home; or(b)
    
    an entity in which such individual is a partner, member, an officer such as a
managing director occupying a comparable position or executive officer, or occupies a
similar position (except limited partners, non-managing members and those occupying
similar positions who, in each case, have no active role in providing services to the
entity) and which provides accounting, consulting, legal, investment banking or
financial advisory services to Pengrowth.
 10.
    
    For the purposes of paragraph 8, compensatory fees do not include the receipt of fixed
amounts of compensation under a retirement plan (including deferred compensation) for prior
service with Pengrowth if the compensation is not contingent in any way on continued service.
 Standard of Financial Literacy




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##### 



A-3




---



##### 



B-1 Schedule B
 Excerpts from Rule 10A-3 of the Securities and Exchange Act of 1934
 Standard of Independence
 b.
    
    Required standards.1.
    
    Independence.
 i.
    
    Each member of the audit committee must be a member of the board of directors
of the listed issuer, and must otherwise be independent; provided that, where a listed
issuer is one of two dual holding companies, those companies may designate one audit
committee for both companies so long as each member of the audit committee is a member
of the board of directors of at least one of such dual holding companies.ii.
    
    Independence requirements for non-investment company issuers.In order to be
considered to be independent for purposes of this paragraph (b)(1), a member of an
audit committee of a listed issuer that is not an investment company may not, other
than in his or her capacity as a member of the audit committee, the board of directors,
or any other board committee:
 A.
    
    Accept directly or indirectly any consulting, advisory, or
other compensatory fee from the issuer or any subsidiary thereof, provided
that, unless the rules of the national securities exchange or national
securities association provide otherwise, compensatory fees do not include the
receipt of fixed amounts of compensation under a retirement plan (including
deferred compensation) for prior service with the listed issuer (provided that
such compensation is not contingent in any way on continued service); orB.
    
    Be an affiliated person of the issuer or any subsidiary
thereof.
 e.
    
    Definitions. Unless the context otherwise requires, all terms used in this section have the
same meaning as in the Act. In addition, unless the context otherwise requires, the following
definitions apply for purposes of this section:
  i.
    
    The term affiliateof, or a person affiliatedwith, a specified person, means a
person that directly, or indirectly through one or more intermediaries, controls, or is
controlled by, or is under common control with, the person specified.
  A.
    
    A person will be deemed not to be in control of a specified
person for purposes of this section if the person:
 1.
    
    Is not the beneficial owner, directly or
indirectly, of more than 10% of any class of voting equity securities
of the specified person; and (2) Is not an executive officer of the
specified person.
 B.
    
    Paragraph (e)(1)(ii)(A) of this section only creates a safe
harbor position that a person does not control a specified person. The
existence of the safe harbor does not create a presumption in any way that a
person exceeding the ownership requirement




---



##### 



B-2 in paragraph (e)(1)(ii)(A)(1) of this section controls or is otherwise an
affiliate of a specified person.
 iii.
    
    The following will be deemed to be affiliates:
 A.
    
    An executive officer of an affiliate;B.
    
    A director who also is an employee of an affiliate;C.
    
    A general partner of an affiliate; andD.
    
    A managing member of an affiliate.
 iv.
    
    For purposes of paragraph (e)(1)(i) of this section, dual holding companies
will not be deemed to be affiliates of or persons affiliated with each other by virtue
of their dual holding company arrangements with each other, including where directors
of one dual holding company are also directors of the other dual holding company, or
where directors of one or both dual holding companies are also directors of the
businesses jointly controlled, directly or indirectly, by the dual holding companies
(and, in each case, receive only ordinary-course compensation for serving as a member
of the board of directors, audit committee or any other board committee of the dual
holding companies or any entity that is jointly controlled, directly or indirectly, by
the dual holding companies).
 4.
    
    The term control (including the terms controlling, controlled by and under common control
with) means the possession, direct or indirect, of the power to direct or cause the direction
of the management and policies of a person, whether through the ownership of voting
securities, by contract, or otherwise.8.
    
    The term indirect acceptance by a member of an audit committee of any consulting, advisory or
other compensatory fee includes acceptance of such a fee by a spouse, a minor child or
stepchild or a child or stepchild sharing a home with the member or by an entity in which such
member is a partner, member, an officer such as a managing director occupying a comparable
position or executive officer, or occupies a similar position (except limited partners,
non-managing members and those occupying similar positions who, in each case, have no active
role in providing services to the entity) and which provides accounting, consulting, legal,
investment banking or financial advisory services to the issuer or any subsidiary of the
issuer.




---



##### 



C-1 
 Schedule C
 Excerpts from Rule 303A.00 of the New York Stock Exchange
 303A.02 Independence Tests
  (a)
    
    No director qualifies as independent unless the board of directors
affirmatively determines that the director has no material relationship with the listed
company (either directly or as a partner, shareholder or officer of an organization
that has a relationship with the company). Companies must identify which directors are
independent and disclose the basis for that determination.(b)
    
    In addition, a director is not independent if:
 (i)
    
    The director is, or has been within the last three years, an
employee of the listed company, or an immediate family member is, or has been
within the last three years, an executive officer, of the listed company.(ii)
    
    The director has received, or has an immediate family member
who has received, during any twelve-month period within the last three years,
more than $100,000 in direct compensation from the listed company, other than
director and committee fees and pension or other forms of deferred compensation
for prior service (provided such compensation is not contingent in any way on
continued service).(iii)
    
    (A) The director or an immediate family member is a current
partner of a firm that is the companys internal or external auditor; (B) the
director is a current employee of such a firm; (C) the director has an
immediate family member who is a current employee of such a firm and who
participates in the firms audit, assurance or tax compliance (but not tax
planning) practice; or (D) the director or an immediate family member was
within the last three years (but is no longer) a partner or employee of such a
firm and personally worked on the listed companys audit within that time.(iv)
    
    The director or an immediate family member is, or has been
within the last three years, employed as an executive officer of another
company where any of the listed companys present executive officers at the
same time serves or served on that companys compensation committee.(v)
    
    The director is a current employee, or an immediate family
member is a current executive officer, of a company that has made payments to,
or received payments from, the listed company for property or services in an
amount which, in any of the last three fiscal years, exceeds the greater of $1
million, or 2% of such other companys consolidated gross revenues.
 General Commentary to Section 303A.02(b):




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##### 



C-2




---



##### 



EXHIBIT 1
 CONSENT OF GLJ PETROLEUM CONSULTANTS LTD.
  Date: September 15, 2008
Calgary, Alberta
    

/s/  GLJ
Petroleum Consultants Ltd.
GLJ Petroleum Consultants Ltd.




---



##### 



EXHIBIT
2
 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED
 PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
  1.
    
    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and2.
    
    The information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations
of the Company.
 Dated: September 15, 2008
    
    /s/  James S. KinnearJames S. KinnearChairman, President andChief Executive Officer




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##### 



EXHIBIT
3
 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE
 SARBANES-OXLEY ACT OF 2002
  1.
    
    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and2.
    
    The information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.
 Dated: September 15, 2008
    
    /s/  Christopher G. WebsterChristopher G. WebsterChief Financial Officer




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##### 



EXHIBIT
 4
 CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE
SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO
 SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
  1.
    
    I have reviewed this Amendment No. 1 to the annual report on Form 40-F of Pengrowth Energy Trust;2.
    
    Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;3.
    
    Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the issuer as of, and for, the periods presented in this report;4.
    
    The issuers other certifying officer(s) and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the issuer and have:
 (a)
    
    Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
issuer, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in
which this report is being prepared;(b)
    
    Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted
accounting principles;(c)
    
    Evaluated the effectiveness of the issuers disclosure controls and
procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and(d)
    
    Disclosed in this report any change in the issuers internal control
over financial reporting that occurred during the period covered by
the annual report that has materially affected, or is reasonably
likely to materially affect, the issuers internal control over
financial reporting; and
 5.
    
    The issuers other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the issuers auditors and the audit committee of the
issuers board of directors (or persons performing the equivalent
functions):
 (a)
    
    All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the issuers ability to record,
process, summarize and report financial information; and(b)
    
    Any fraud, whether or not material, that involves management or other
employees who have a significant role in the issuers internal control
over financial reporting.
 Dated: September 15, 2008
    
    /s/  James S. KinnearJames S. KinnearChairman, President andChief Executive Officer




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##### 



EXHIBIT 5
 CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE SECURITIES
EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE
 SARBANES-OXLEY ACT OF 2002
  1.
    
    I have reviewed this Amendment No. 1 to the annual report on Form 40-F of Pengrowth Energy Trust;2.
    
    Based on my knowledge, this report does not contain any untrue statement of a material fact or
omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report;3.
    
    Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the issuer as of, and for, the periods presented in this report;4.
    
    The issuers other certifying officer(s) and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e))
and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the issuer and have:
 (a)
    
    Designed such disclosure controls and
procedures, or caused such disclosure
controls and procedures to be designed under
our supervision, to ensure that material
information relating to the issuer, including
its consolidated subsidiaries, is made known
to us by others within those entities,
particularly during the period in which this
report is being prepared;(b)
    
    Designed such internal control over financial
reporting, or caused such internal control
over financial reporting to be designed under
our supervision, to provide reasonable
assurance regarding the reliability of
financial reporting and the preparation of
financial statements for external purposes in
accordance with generally accepted accounting
principles;(c)
    
    Evaluated the effectiveness of the issuers
disclosure controls and procedures and
presented in this report our conclusions
about the effectiveness of the disclosure
controls and procedures, as of the end of the
period covered by this report based on such
evaluation; and(d)
    
    Disclosed in this report any change in the
issuers internal control over financial
reporting that occurred during the period
covered by the annual report that has
materially affected, or is reasonably likely
to materially affect, the issuers internal
control over financial reporting; and
 5.
    
    The issuers other certifying officer(s) and I have
disclosed, based on our most recent evaluation of internal
control over financial reporting, to the issuers auditors
and the audit committee of the issuers board of directors
(or persons performing the equivalent functions):
 (a)
    
    All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the issuers ability to record,
process, summarize and report financial information; and(b)
    
    Any fraud, whether or not material, that involves management or other
employees who have a significant role in the issuers internal control
over financial reporting.
 Dated: September 15, 2008
    
    /s/  Christopher G. WebsterChristopher G. WebsterChief Financial Officer