U.S. SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, D.C. 20549
 FORM 40-F
 o
    
    REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934.
 þ
    
    ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934
 For
the fiscal year ended: December 31, 2008       Commission File Number: 1-31253
 PENGROWTH ENERGY TRUST
  Alberta, Canada
 1311
    
    None(Primary Standard Industrial 
Classification Code Number)
    
    (I.R.S. Employer
Identification Number)
 Suite 2100, 222 Third Avenue S.W.
Calgary, Alberta Canada T2P 0B4
(403) 233-0224
 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
    
    Edwin S. Maynard
Andrew J. FoleyPaul, Weiss, Rifkind, Wharton & Garrison LLP
1285 Avenue of the Americas
New York, New York 10019-6064 USA
(212) 373-3000
 Securities registered or to be registered pursuant to Section 12(b) of the Act.
 Title of each class
    
    Name of each exchange on which registeredTrust Units
    
    New York Stock Exchange
 Securities registered or to be registered pursuant to Section 12(g) of the Act.
 None
 (Title of Class)
 Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
 None
 (Title of Class)
  þ þ
    o þ
  þ o




---



##### 



DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT
  Appendix
    
    DocumentsA
    
    Pengrowth Energy Trust Annual Information Form for the year ended
December 31, 2008.B
    
    Managements Discussion and Analysis.C
    
    Consolidated Financial Statements of Pengrowth Energy Trust,
including Managements Report to Unitholders, the Auditors
Reports and note 24 thereof which includes a reconciliation of the
Consolidated Financial Statements to United States generally
accepted accounting principles.D
    
    Oil and Gas Producing Activities Prepared in Accordance with SFAS
No. 69  Disclosures about Oil and Gas Producing Activities.E
    
    Pengrowth Energy Trust Code of Business Conduct and Ethics dated
February 17, 2009.
 CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES
 Certifications
 Disclosure Controls and Procedures
 Managements Annual Report on Internal Control Over Financial Reporting
 Attestation Report of the Registered Public Accounting Firm
 Changes in Internal Control Over Financial Reporting




---



##### 



NOTICES PURSUANT TO REGULATION BTR
  IDENTIFICATION OF THE AUDIT COMMITTEE
  AUDIT COMMITTEE FINANCIAL EXPERT
  ADDITIONAL DISCLOSURE
  UNDERTAKING
  CONSENT TO SERVICE OF PROCESS




---



##### 



SIGNATURES
  Date:  March 24, 2009
    PENGROWTH ENERGY TRUST
by its Administrator
PENGROWTH CORPORATIONBy:
    /s/ James S. KinnearJames S. KinnearChairman, President and
Chief Executive Officer




---



##### 



APPENDIX
A
 PENGROWTH ENERGY TRUST ANNUAL INFORMATION FORM FOR THE YEAR
ENDED DECEMBER 31, 2008




---



##### 



PENGROWTH ENERGY TRUST
 ANNUAL INFORMATION FORM
 For the year ended December 31, 2008
 March
24, 2009




---



##### 



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




---



##### 



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




---



##### 



CONFLICTS OF INTEREST
    
    
    100LEGAL PROCEEDINGS
    
    
    102INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    
    
    102INTERESTS OF EXPERTS
    
    
    102AUDITORS, TRANSFER AGENT AND REGISTRAR
    
    
    102MATERIAL CONTRACTS
    
    
    102CODE OF ETHICS
    
    
    103OFF-BALANCE SHEET ARRANGEMENTS
    
    
    103DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
    
    
    103ADDITIONAL INFORMATION
    
    
    104Appendix A  Report on Reserves Data by Independent Qualified
Reserves Evaluator on Form 51-101F2Appendix B  Report of Management and Directors on Oil and Gas
Disclosure on Form 51-101F3Appendix C  Audit Committee Terms of Reference
  Unless otherwise indicated, all of the information provided in this Annual Information Form is as
at December 31, 2008.
 - iv -




---



##### 



GLOSSARY OF TERMS AND ABBREVIATIONS
  Corporate
 Board Board of Directors
 Computershare
 Corporation
 Debenture
 Debenture Indenture
 Manager
 Pengrowth we us and our
 Royalty Indenture
 Royalty Unitholder
 Royalty Units
 SIFT Legislation Certain Canadian Federal Income Tax Considerations
 Trust
 Trust Indenture
 Trust Units
 Unitholders
 Engineering
 Company Interest
 Contingent Resources




---



##### 



Developed Non-Producing Reserves
 Developed Producing Reserves
 Developed Reserves
 future net revenue
 GLJ
 GLJ Report
 gross
 net
 Possible Reserves
 Probable Reserves
 Proved Reserves
 Remaining Reserve Life
 Reserve Life Index
 - 2 -




---



##### 



reserves
 Royalty Interest
 Total Proved Plus Probable Reserves
 Undeveloped Reserves
 Working Interest
 Abbreviations
 API
 o API
 bbl Mbbl MMbbl Bbbl
 bblpd
 boe Mboe MMboe
 boepd
 bwpd
 CBM
 EDGAR
 GAAP Canadian GAAP
 $M $MM
 MMBtu
 Mcf MMcf
 - 3 -




---



##### 



Mcfe
 Mcfpd MMcfpd
 NGLs
 NYSE
 P+P
 SAGD
 SEC
 SEDAR
 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.
 - 4 -




---



##### 



CONVERSION
  To Convert From
    
    To
    
    Multiply byMcf
    
    cubic metre
    
    
    28.174bbl
    
    cubic metre
    
    
    0.159cubic metre
    
    bbl
    
    
    6.29metre
    
    feet
    
    
    3.281mile
    
    kilometre
    
    
    1.609kilometre
    
    mile
    
    
    0.621acre
    
    hectare
    
    
    0.405
  - 5 -




---



##### 



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
 - 6 -




---



##### 



Risk Factors Business Risks
  - 7 -




---



##### 



PENGROWTH ENERGY TRUST
 
 Introduction
 Pengrowth Management Limited  Management
Agreement
 
 The Trust
   
 The Corporation
   
 The Trusts Subsidiaries
  - 8 -




---



##### 



General
Development of Pengrowth Energy Trust  Historical Developments
 
 The Manager
 Pengrowth Management Limited -
Management Agreement
 Pengrowth Management Limited
 
 Intercorporate Relationships
  
 - 9 -




---



##### 



Business Strategy and Strengths
 2
  Acquisitions
 
    
    Acquisitions should yield economic returns above Pengrowths cost of capital and be accretive on a per Trust Unit basis
based upon current forecast parameters. In determining economic value and whether an acquisition is accretive, we examine
the profile of production, operating costs, capital costs, abandonment expenses, commodity price forecasts and other key
variables and compare that with the profile of our existing asset base to understand the impact over time in terms of cash
flow, production, reserves and distributions on a per Trust Unit basis.
    
    The projected future net cash flow from the properties should exceed the aggregate purchase price of the properties and
provide a reasonable rate of return.
    
    Properties to be acquired should be high quality, relatively long life and proven producing properties. Pengrowth gives
priority to properties with:
 o
    
    low anticipated capital expenditures relative to the cash generation potential of the properties;o

    
    relatively low operating costs or high netbacks;o

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

    
    favourable production history;
 - 10 -




---



##### 



o

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

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

    
    low environmental and site remediation risk.
 
    
    Generally each purchase of new properties must be based on an independent engineering report.
 Development
 
    
    Development investments should provide a high rate of return or be necessary to maintain existing production operations. Pengrowth
prioritizes its development investments based on:
 o

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

    
    rate of return;o

    
    timing of production;o

    
    potential for continued development; ando

    
    those investments necessary to maintain existing facilities and wells.
  
 SIFT Legislation Considerations
    - 11 -




---



##### 



GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST
 
 Recent Developments
 2009 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
    
    $
    126
    
    
    
    67
    %Plant and Facilities
    
    
    50
    
    
    
    26
    %Land and Seismic
    
    
    10
    
    
    
    5
    %
 - 12 -




---



##### 



Planned Capital Expenditures
    
    ($ millions)
    
    (% of Total)Other (e.g., CO2 Pilot)
    
    
    3
    
    
    
    2
    %Total Development Capital
    
    $
    189
    
    
    
    100
    %Lindbergh Oil Sands Project
    
    
    20Total Development Capital and Lindbergh
    
    $
    209Building, IT
    
    
    6Total Capital
    
    $
    215Average Daily Production Volume (boepd)
    
    
    
    
    
    

    76,000 - 78,000(1)Operating Costs (per boe)
    
    $
    14.45
    (2)General and Administrative Costs (per boe)
    
    $
    2.37
    (2)(3)
 Notes:(1)
    
    The 2009 estimate excludes potential additions through acquisitions or reductions due to
dispositions.(2)
    
    Assuming production targets for 2009 are achieved.(3)
    
    Includes management fees of approximately $0.21 per boe based on the remaining term of the
contract. Taxability of Distributions Paid to U.S. Residents
 The increase will become effective on January 1, 2010
 Accrete Acquisition
  Senior Unsecured Notes
  - 13 -




---



##### 



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 repayment of our lenders, note holders
and other creditors and only the remainder, if any, would be available for distribution to our
Unitholders.
 Credit Facility
   At-the-Market Equity Distribution Program
  
 Historical Developments
  - 14 -




---



##### 



Trust Units 
Redemption Right Trust Units  Conversion Rights
  - 15 -




---



##### 



Business Corporations Act
          - 16 -




---



##### 



Trends
  - 17 -




---



##### 



Managements Discussion and Analysis  Outlook
 
 PENGROWTH MANAGEMENT LIMITED
 
 Business
  - 18 -




---



##### 



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.
 For these purposes, Income means the aggregate of net production revenue of the
Corporation and any other income earned from permitted investments of the Trust
(excluding interest on cash or near-cash deposits or similar investments).
 
    
    a performance based fee based on total returns received by Unitholders which essentially
compensates the Manager for total annual returns which average in excess of eight percent per
annum over a three year period;
    
    a ceiling on total fees payable determined in reference to a percentage of the fees paid
under the previous management agreement: 80 percent each year in the first three year contract
term and 60 percent each year in the second three year contract term and subject to a further
ceiling essentially equivalent to $12 million annually during the second three year contract
term;
    
    requirement for the Manager to pay certain expenses of the Corporation and the Trust of
approximately $2 million per year;
    
    an annual minimum management fee of $3.6 million comprised of $1.6 million of management
fees and $2.0 million of expenses;
    
    key man provisions in respect of James S. Kinnear, the President of the Manager;
    
    an annual bonus pool based on 10 percent of the Managers base fee and performance fee for
employees of, and special consultants to, the Corporation; and
 - 19 -




---



##### 




    
    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.
  
 Bonus Pool
  
 Management Agreement Second Term
   - 20 -




---



##### 




    
    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.
  
 Expiry of the Management Agreement
   - 21 -




---



##### 



PENGROWTH  OPERATIONAL INFORMATION
  
 Principal Properties
   Summary of Company Interest
at December 31, 2008(1)
(Forecast Prices and Costs)(2)
 P+PValueReserve
    
    Before TaxP+P
    
    Remaining
    
    Life
    
    at 10%
    
    2008 Oil
    
    2008 Gas
    
    2008 NGL
    
    2008 TotalReserves(4)
    
    Reserve Life
    
    Index
    
    Discount
    
    Production
    
    Production
    
    Production
    
    ProductionField
    
    (Mboe)
    
    (years)
    
    (years)
    
    ($MM)
    
    (bblpd)
    
    (MMcfpd)
    
    (bblpd)
    
    (boepd)(4)Light Oil PropertiesJudy Creek
    
    
    39,073
    
    
    
    50
    
    
    
    11.0
    
    
    
    881.8
    
    
    
    6,801
    
    
    
    4.3
    
    
    
    2,247
    
    
    
    9,759Weyburn
    
    
    22,205
    
    
    
    50
    
    
    
    23.6
    
    
    
    392.0
    
    
    
    2,589
    
    
    
    0.0
    
    
    
    0
    
    
    
    2,589Swan Hills
    
    
    18,103
    
    
    
    50
    
    
    
    19.1
    
    
    
    256.9
    
    
    
    2,025
    
    
    
    1.7
    
    
    
    263
    
    
    
    2,570Carson Creek
    
    
    15,649
    
    
    
    39
    
    
    
    13.4
    
    
    
    264.7
    
    
    
    2,069
    
    
    
    3.4
    
    
    
    271
    
    
    
    2,910Fenn Big Valley
    
    
    6,413
    
    
    
    35
    
    
    
    9.0
    
    
    
    107.1
    
    
    
    863
    
    
    
    7.3
    
    
    
    66
    
    
    
    2,152Deer Mountain
    
    
    6,066
    
    
    
    47
    
    
    
    21.0
    
    
    
    96.8
    
    
    
    606
    
    
    
    0.1
    
    
    
    66
    
    
    
    691Other(3)
    
    
    32,813
    
    
    
    
    
    
    
    9.5
    
    
    
    659.1
    
    
    
    7,788
    
    
    
    6.5
    
    
    
    445
    
    
    
    9,321Sub-Total
    
    
    140,322
    
    
    
    
    
    
    
    12.7
    
    
    
    2,658.3
    
    
    
    22,740
    
    
    
    23.3
    
    
    
    3,357
    
    
    
    29,992Heavy Oil PropertiesBodo
    
    
    7,544
    
    
    
    35
    
    
    
    11.5
    
    
    
    119.6
    
    
    
    1,580
    
    
    
    2.0
    
    
    
    0
    
    
    
    1,917Jenner
    
    
    7,112
    
    
    
    20
    
    
    
    6.5
    
    
    
    179.4
    
    
    
    3,049
    
    
    
    0.4
    
    
    
    6
    
    
    
    3,121Tangleflags
    
    
    5,394
    
    
    
    28
    
    
    
    7.1
    
    
    
    78.8
    
    
    
    2,505
    
    
    
    0.4
    
    
    
    0
    
    
    
    2,571Other(3)
    
    
    4,628
    
    
    
    
    
    
    
    7.2
    
    
    
    67.7
    
    
    
    1,008
    
    
    
    4.2
    
    
    
    0
    
    
    
    1,716Sub-Total
    
    
    24,678
    
    
    
    
    
    
    
    7.8
    
    
    
    445.4
    
    
    
    8,142
    
    
    
    7.1
    
    
    
    6
    
    
    
    9,325Conventional Gas
PropertiesOlds
    
    
    24,766
    
    
    
    50
    
    
    
    17.3
    
    
    
    315.8
    
    
    
    0
    
    
    
    18.4
    
    
    
    685
    
    
    
    3,755Harmattan
    
    
    19,124
    
    
    
    44
    
    
    
    10.0
    
    
    
    298.2
    
    
    
    322
    
    
    
    16.1
    
    
    
    1,226
    
    
    
    4,226Dunvegan
    
    
    6,139
    
    
    
    36
    
    
    
    10.1
    
    
    
    89.6
    
    
    
    40
    
    
    
    7.7
    
    
    
    407
    
    
    
    1,727Quirk Creek
    
    
    5,878
    
    
    
    42
    
    
    
    10.7
    
    
    
    78.6
    
    
    
    0
    
    
    
    3.6
    
    
    
    223
    
    
    
    822Carson Creek
    
    
    5,231
    
    
    
    15
    
    
    
    6.5
    
    
    
    109.6
    
    
    
    0
    
    
    
    4.7
    
    
    
    689
    
    
    
    1,477McLeod River
    
    
    3,664
    
    
    
    42
    
    
    
    8.4
    
    
    
    69.0
    
    
    
    42
    
    
    
    5.3
    
    
    
    198
    
    
    
    1,129Kaybob
    
    
    3,519
    
    
    
    36
    
    
    
    13.9
    
    
    
    49.8
    
    
    
    0
    
    
    
    4.5
    
    
    
    38
    
    
    
    781Blackstone
    
    
    3,399
    
    
    
    24
    
    
    
    10.5
    
    
    
    40.0
    
    
    
    0
    
    
    
    5.6
    
    
    
    0
    
    
    
    941Other(3)
    
    
    17,214
    
    
    
    
    
    
    
    7.6
    
    
    
    300.1
    
    
    
    571
    
    
    
    28.1
    
    
    
    319
    
    
    
    5,577Sub-Total
    
    
    88,934
    
    
    
    
    
    
    
    10.4
    
    
    
    1,350.8
    
    
    
    975
    
    
    
    94.0
    
    
    
    3,786
    
    
    
    20,434
 - 22 -




---



##### 



P+PValueReserve
    
    Before TaxP+P
    
    Remaining
    
    Life
    
    at 10%
    
    2008 Oil
    
    2008 Gas
    
    2008 NGL
    
    2008 TotalReserves(4)
    
    Reserve Life
    
    Index
    
    Discount
    
    Production
    
    Production
    
    Production
    
    ProductionField
    
    (Mboe)
    
    (years)
    
    (years)
    
    ($MM)
    
    (bblpd)
    
    (MMcfpd)
    
    (bblpd)
    
    (boepd)(4)Shallow Gas PropertiesThree Hills/Twining
    
    
    12,364
    
    
    
    50
    
    
    
    9.9
    
    
    
    238.6
    
    
    
    405
    
    
    
    11.3
    
    
    
    359
    
    
    
    2,648Coal Bed Methane
    
    
    8,300
    
    
    
    37
    
    
    
    10.6
    
    
    
    135.0
    
    
    
    0
    
    
    
    11.0
    
    
    
    3
    
    
    
    1,839Monogram
    
    
    8,032
    
    
    
    36
    
    
    
    8.7
    
    
    
    163.4
    
    
    
    0
    
    
    
    14.1
    
    
    
    0
    
    
    
    2,350Jenner
    
    
    7,893
    
    
    
    43
    
    
    
    11.5
    
    
    
    122.6
    
    
    
    21
    
    
    
    12.1
    
    
    
    3
    
    
    
    2,039Lethbridge
    
    
    3,291
    
    
    
    49
    
    
    
    9.0
    
    
    
    56.7
    
    
    
    0
    
    
    
    6.8
    
    
    
    0
    
    
    
    1,142Other(3)
    
    
    14,091
    
    
    
    
    
    
    
    10.5
    
    
    
    222.0
    
    
    
    256
    
    
    
    26.2
    
    
    
    108
    
    
    
    4,738Sub-Total
    
    
    53,971
    
    
    
    
    
    
    
    10.1
    
    
    
    938.3
    
    
    
    683
    
    
    
    81.6
    
    
    
    473
    
    
    
    14,755Offshore Gas PropertiesSable Island
    
    
    9,213
    
    
    
    7
    
    
    
    3.7
    
    
    
    184.0
    
    
    
    0
    
    
    
    34.8
    
    
    
    1,693
    
    
    
    7,485Sub-Total
    
    
    9,213
    
    
    
    
    
    
    
    3.7
    
    
    
    184.0
    
    
    
    0
    
    
    
    34.8
    
    
    
    1,693
    
    
    
    7,485Oil Sands PropertiesLindbergh
    
    
    6,345
    
    
    
    13
    
    
    
    
    
    
    
    4.6
    
    
    
    0
    
    
    
    0.0
    
    
    
    0
    
    
    
    0Sub-Total
    
    
    6,345
    
    
    
    
    
    
    
    
    
    
    
    4.6
    
    
    
    0
    
    
    
    0.0
    
    
    
    0
    
    
    
    0Total
    
    
    323,463
    
    
    
    
    
    
    
    10.6
    
    
    
    5,581.5
    
    
    
    32,539
    
    
    
    240.8
    
    
    
    9,315
    
    
    
    81,991
 Notes:(1)
    
    The estimates of reserves and future net revenue for individual properties may not reflect
the same confidence level as estimates of reserves and future net revenue for all properties,
due to the effects of aggregation.(2)
    
    Forecast prices are shown under the heading   Pricing Assumptions.(3)
    
    Other includes Pengrowths Working Interests and Royalty Interests in approximately 100
other properties.(4)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil. 
 Light Oil Properties
 Judy Creek
  2008 Development Activity
  Carbon Dioxide (CO 2 ) Pilot
 2 2
 - 23 -




---



##### 



2 2 2 2
 2
 2009 Development Activity
  Weyburn Unit
 2 2
 2008 Development Activity
 2 2 2 2 2
 2009 Development Activity
 2
 Swan Hills
  2008 Development Activity
   - 24 -




---



##### 



2009 Development Activity
  Carson Creek
  2008 Development Activity
  2009 Development Activity
  Fenn Big Valley
  2008 Development Activity
  2009 Development Activity
  - 25 -




---



##### 



Deer Mountain Area
  2008 Development Activity
  2009 Development Activity
  
 Heavy Oil Properties
 Bodo
  2008 Development Activity
  2009 Development Activity
  Jenner
  - 26 -




---



##### 



° °
 2008 Development Activity
  2009 Development Activity
  Tangleflags
    2008 Development Activity
  2009 Development Activity
  
 Conventional Gas Properties
 Olds
 2
 - 27 -




---



##### 



2008 Development Activity
  2009 Development Activity
  Harmattan
  2008 Development Activity
  2009 Development Activity
  Dunvegan
  - 28 -




---



##### 



2008 Development Activity
  2009 Development Activity
  Quirk Creek
  2008 Development Activity
  2009 Development Activity
  Carson Creek
   2008 Development Activity
  - 29 -




---



##### 



2009 Development Activity
  McLeod River
  2008 Development Activity
  2009 Development Activity
  Kaybob
  2008 Development Activity
  2009 Development Activity
  Blackstone
  2008 Development Activity
  - 30 -




---



##### 



2009 Development Activity
  
 Shallow Gas Properties
 Twining/Three Hills Creek
  2008 Development Activity
  2009 Development Activity
  Coal Bed Methane (CBM)
  2008 Development Activity
  2009 Development Activity
  Monogram Gas Unit
  - 31 -




---



##### 



2008 Development Activity
  2009 Development Activity
  Jenner
  2008 Development Activity
  2009 Development Activity
  Lethbridge
  2008 Development Activity
  2009 Development Activity
  
 Offshore Gas Properties
 Sable Offshore Energy Project
  - 32 -




---



##### 



2008 Development Activity
  2009 Development Activity
  
 Oil Sands Properties
 Lindbergh
 °
 Lindbergh Oil Sands Contingent Resources
 2008 Development Activity
  2009 Development Activity
  - 33 -




---



##### 



Statement of Oil and Gas Reserves and Reserves Data
 Disclosure of Reserves Data
   Lindbergh
Oil Sands Reserves and Contingent Resources
 Pengrowths future net revenues associated with the reserves contained in this Annual Information
Form reflect the New Royalty Framework and the Transitional Royalties implemented by the Government
of Alberta on January 1, 2009. The Transitional Royalties may be applied to wells drilled after
November 18, 2008 and to production from those wells through December 31, 2013.
 The GLJ forecasts of future net revenue are stated
prior to any provision for income taxes, interest costs or general and administrative costs and
after the deduction of estimated future capital expenditures for wells to which reserves have been
assigned. It should not be assumed that the estimated future net revenue shown below is
representative of the fair market value of the properties. There is no assurance that such price
and cost assumptions will be attained and variances could be material. The recovery and estimates
of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no
guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas
reserves may be greater than or less than the estimates provided herein.
 The future net revenue and present value of future net revenue after income taxes were determined
by Pengrowth after taking into account the impact of the SIFT Legislation. Certain Canadian
Federal Income Tax Considerations  Taxation of the Trust  SIFT Legislation
 - 34 -




---



##### 




    
    SIFT tax starting January 2011 at 27.11 percent (and 25.61 percent in 2012 and thereafter).
The SIFT tax is based on the provincial allocation from the Corporations December 31, 2007
tax return;
 
    
    Annual general and administration expenses at the current level;
 
    
    Interest expense at the current level;
 
    
    Inclusion of tax pools and deductions at the trust level as well as at the operating entity
level (total tax pools of $3.1 billion);
 
    
    Royalties paid to the Trust after allowance for capital expenses contemplated by the GLJ
Report;
 
    
    Distributions by the Trust to the Unitholders in an amount equal to the cash received by
the Trust; and
 
    
    Any such other additional deductions and adjustments as is and would be consistent with the
manner in which Pengrowth files and would file future tax returns. See Canadian Income Tax
Considerations.
   - 35 -




---



##### 



Reserves Data (Forecast Prices and Costs)
 Summary of Oil and Gas Reserves
as of December 31, 2008
(Forecast Prices and Costs) (1)
 Light and Medium Oil
    
    Heavy Oil
    
    Natural Gas LiquidsCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)Proved ReservesProved Developed Producing
    
    
    72,564
    
    
    
    72,411
    
    
    
    57,262
    
    
    
    14,453
    
    
    
    14,443
    
    
    
    13,073
    
    
    
    22,009
    
    
    
    21,902
    
    
    
    15,806Proved Developed Non-
Producing
    
    
    821
    
    
    
    821
    
    
    
    611
    
    
    
    148
    
    
    
    148
    
    
    
    136
    
    
    
    415
    
    
    
    414
    
    
    
    304Proved Undeveloped
    
    
    17,030
    
    
    
    17,029
    
    
    
    12,541
    
    
    
    1,676
    
    
    
    1,676
    
    
    
    1,370
    
    
    
    1,120
    
    
    
    1,120
    
    
    
    766Total Proved Reserves
    
    
    90,415
    
    
    
    90,261
    
    
    
    70,414
    
    
    
    16,277
    
    
    
    16,268
    
    
    
    14,579
    
    
    
    23,543
    
    
    
    23,436
    
    
    
    16,876Probable Reserves
    
    
    30,874
    
    
    
    30,846
    
    
    
    23,545
    
    
    
    11,451
    
    
    
    11,448
    
    
    
    10,110
    
    
    
    8,898
    
    
    
    8,873
    
    
    
    6,353Total Proved Plus Probable
Reserves
    
    
    121,289
    
    
    
    121,107
    
    
    
    93,959
    
    
    
    27,728
    
    
    
    27,716
    
    
    
    24,689
    
    
    
    32,442
    
    
    
    32,309
    
    
    
    23,228
 Natural Gas
    
    Coal Bed Methane
    
    Total Oil Equivalent Basis(2)Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestRESERVES CATEGORY
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (Mboe)
    
    (Mboe)
    
    (Mboe)Proved ReservesProved Developed Producing
    
    
    527,799
    
    
    
    523,765
    
    
    
    428,531
    
    
    
    21,524
    
    
    
    20,490
    
    
    
    20,080
    
    
    
    200,580
    
    
    
    199,466
    
    
    
    160,910Proved Developed Non-
Producing
    
    
    19,544
    
    
    
    19,337
    
    
    
    14,528
    
    
    
    2,177
    
    
    
    2,157
    
    
    
    2,025
    
    
    
    5,004
    
    
    
    4,965
    
    
    
    3,810Proved Undeveloped
    
    
    48,440
    
    
    
    48,310
    
    
    
    39,368
    
    
    
    10,447
    
    
    
    10,372
    
    
    
    9,397
    
    
    
    29,640
    
    
    
    29,605
    
    
    
    22,804Total Proved Reserves
    
    
    595,783
    
    
    
    591,412
    
    
    
    482,427
    
    
    
    34,148
    
    
    
    33,019
    
    
    
    31,503
    
    
    
    235,224
    
    
    
    234,036
    
    
    
    187,524Probable Reserves
    
    
    206,815
    
    
    
    205,163
    
    
    
    163,393
    
    
    
    15,279
    
    
    
    14,960
    
    
    
    13,768
    
    
    
    88,239
    
    
    
    87,854
    
    
    
    69,534Total Proved Plus Probable
Reserves
    
    
    802,598
    
    
    
    796,576
    
    
    
    645,821
    
    
    
    49,427
    
    
    
    47,979
    
    
    
    45,270
    
    
    
    323,463
    
    
    
    321,891
    
    
    
    257,058
 Notes:(1)
    
    Forecast prices are shown under the heading   Pricing Assumptions.(2)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil. - 36 -




---



##### 



Summary of Net Present Value
of Future Net Revenue
as of December 31, 2008
Before and After Income Taxes
(Forecast Prices and Costs) (1)
 Unit ValueBefore Income Taxes
    
    Before Income TaxDiscounted at (%/Year)
    
    Discounted at 10%/Year(2)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    $/boe
    
    $/McfeProved ReservesProved Developed Producing
    
    
    6,947
    
    
    
    5,046
    
    
    
    3,982
    
    
    
    3,308
    
    
    
    2,843
    
    
    
    24.75
    
    
    
    4.12Proved Developed Non-Producing
    
    
    162
    
    
    
    103
    
    
    
    75
    
    
    
    57
    
    
    
    46
    
    
    
    19.56
    
    
    
    3.26Proved Undeveloped
    
    
    1,097
    
    
    
    611
    
    
    
    368
    
    
    
    229
    
    
    
    142
    
    
    
    16.14
    
    
    
    2.69Total Proved Reserves
    
    
    8,206
    
    
    
    5,761
    
    
    
    4,425
    
    
    
    3,594
    
    
    
    3,030
    
    
    
    23.60
    
    
    
    3.93Probable Reserves
    
    
    3,703
    
    
    
    1,899
    
    
    
    1,157
    
    
    
    779
    
    
    
    558
    
    
    
    16.64
    
    
    
    2.77Total Proved Plus Probable Reserves
    
    
    11,909
    
    
    
    7,660
    
    
    
    5,582
    
    
    
    4,373
    
    
    
    3,589
    
    
    
    21.71
    
    
    
    3.62
 After Income TaxesDiscounted at (%/Year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    5,894
    
    
    
    4,225
    
    
    
    3,462
    
    
    
    2,938
    
    
    
    2,561Proved Developed Non-Producing
    
    
    99
    
    
    
    66
    
    
    
    49
    
    
    
    38
    
    
    
    31Proved Undeveloped
    
    
    430
    
    
    
    398
    
    
    
    221
    
    
    
    125
    
    
    
    66Total Proved Reserves
    
    
    6,423
    
    
    
    4,689
    
    
    
    3,732
    
    
    
    3,101
    
    
    
    2,658Probable Reserves
    
    
    2,214
    
    
    
    1,098
    
    
    
    692
    
    
    
    479
    
    
    
    351Total Proved Plus Probable Reserves
    
    
    8,637
    
    
    
    5,787
    
    
    
    4,424
    
    
    
    3,580
    
    
    
    3,009
 Notes:(1)
    
    Forecast prices are shown under the heading   Pricing Assumptions.(2)
    
    Net present value of future net revenue per reserve unit values are based on Pengrowths net
reserves. - 37 -




---



##### 



Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2008
(Forecast Prices and Costs) (1)
 Future NetCapital
    
    
    
    
    
    Future Net
    
    
    
    
    
    RevenueOperating
    
    Development
    
    Abandonment
    
    Revenue Before
    
    
    
    
    
    After IncomeRevenue
    
    Royalties(2)
    
    Costs
    
    Costs
    
    Costs(3)
    
    Income Taxes
    
    Income Tax
    
    TaxesReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    17,515
    
    
    
    3,630
    
    
    
    4,901
    
    
    
    579
    
    
    
    200
    
    
    
    8,206
    
    
    
    (1,783
    )
    
    
    6,423Total Proved Plus
Probable Reserves
    
    
    25,082
    
    
    
    5,269
    
    
    
    6,670
    
    
    
    1,009
    
    
    
    225
    
    
    
    11,909
    
    
    
    (3,272
    )
    
    
    8,637
 
 Notes:(1)
    
    Forecast prices are shown under the heading   Pricing Assumptions.(2)
    
    Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova
Scotia. This includes the impact of the New Royalty Framework implemented by the Government
of Alberta on January 1, 2009, and the optional Transitional Royalty until December 31, 2013
for qualifying wells drilled in Alberta after November 18, 2008.(3)
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See
Pengrowth  Operational Information  Additional Information Concerning Abandonment &
Reclamation Costs. Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2008
(Forecast Prices and Costs) (1)
 Future Net RevenueBefore Income Taxes(discounted at 10%/yr)
    
    Unit Value(4)Reserves Category
    
    Production Group
    
    ($MM)
    
    ($/boe)
    
    ($/Mcfe)Total Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products)(2)
    
    
    2,181
    
    
    
    25.90
    
    
    
    4.32Heavy Oil (including solution gas and other by-products)((1)
    
    
    358
    
    
    
    21.96
    
    
    
    3.66Natural Gas (including by-products but excluding solution gas from oil wells)(3)
    
    
    1,777
    
    
    
    21.74
    
    
    
    3.62Non-conventional Oil & Gas Activities
    
    
    108
    
    
    
    20.57
    
    
    
    3.43Total
    
    
    4,425
    
    
    
    23.60
    
    
    
    3.93Total Proved PlusProbable Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products)(2)
    
    
    2,708
    
    
    
    24.36
    
    
    
    4.06Heavy Oil (including solution gas and other by-products)(1)
    
    
    443
    
    
    
    20.83
    
    
    
    3.47Natural Gas (including by-products but excluding solution gas from oil wells)(3)
    
    
    2,289
    
    
    
    20.63
    
    
    
    3.44Non-conventional Oil & Gas Activities
    
    
    141
    
    
    
    10.59
    
    
    
    1.76Total
    
    
    5,582
    
    
    
    21.71
    
    
    
    3.62
 
 Notes:(1)
    
    Forecast prices are shown under the heading   Pricing Assumptions.(2)
    
    NGLs associated with the production of solution gas are included as a by-product.(3)
    
    NGLs associated with the production of natural gas are included as a by-product.(4)
    
    Net present value of future net revenue per reserve unit values are based on Pengrowths net
reserves. - 38 -




---



##### 



Reserves Data (Constant Prices and Costs)
 Summary of Oil And Gas Reserves
as of December 31, 2008
(Constant Prices and Costs) (1)
 Light and Medium Oil
    
    Heavy Oil
    
    Natural Gas LiquidsCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)Proved ReservesProved Developed
Producing
    
    
    64,697
    
    
    
    64,569
    
    
    
    59,544
    
    
    
    12,386
    
    
    
    12,380
    
    
    
    11,668
    
    
    
    21,414
    
    
    
    21,311
    
    
    
    15,539Proved Developed
Non-Producing
    
    
    882
    
    
    
    882
    
    
    
    740
    
    
    
    111
    
    
    
    111
    
    
    
    108
    
    
    
    416
    
    
    
    416
    
    
    
    306Proved Undeveloped
    
    
    18,269
    
    
    
    18,268
    
    
    
    16,541
    
    
    
    1,522
    
    
    
    1,522
    
    
    
    1,395
    
    
    
    1,200
    
    
    
    1,200
    
    
    
    810Total Proved Reserves
    
    
    83,847
    
    
    
    83,719
    
    
    
    76,825
    
    
    
    14,019
    
    
    
    14,013
    
    
    
    13,171
    
    
    
    23,030
    
    
    
    22,927
    
    
    
    16,655Probable Reserves
    
    
    30,427
    
    
    
    30,405
    
    
    
    27,763
    
    
    
    4,373
    
    
    
    4,372
    
    
    
    4,032
    
    
    
    8,841
    
    
    
    8,817
    
    
    
    6,364Total Proved Plus
Probable Reserves
    
    
    114,274
    
    
    
    114,124
    
    
    
    104,588
    
    
    
    18,392
    
    
    
    18,385
    
    
    
    17,203
    
    
    
    31,871
    
    
    
    31,743
    
    
    
    23,019
 Natural Gas
    
    Coal Bed Methane
    
    Total Oil Equivalent Basis(2)Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (Mboe)
    
    (Mboe)
    
    (Mboe)Proved ReservesProved Developed
Producing
    
    
    517,028
    
    
    
    512,917
    
    
    
    437,243
    
    
    
    21,526
    
    
    
    20,492
    
    
    
    20,175
    
    
    
    188,256
    
    
    
    187,162
    
    
    
    162,987Proved Developed
Non-Producing
    
    
    19,291
    
    
    
    19,072
    
    
    
    14,922
    
    
    
    2,177
    
    
    
    2,157
    
    
    
    2,034
    
    
    
    4,987
    
    
    
    4,946
    
    
    
    3,980Proved Undeveloped
    
    
    48,614
    
    
    
    48,485
    
    
    
    41,044
    
    
    
    10,445
    
    
    
    10,371
    
    
    
    9,511
    
    
    
    30,834
    
    
    
    30,799
    
    
    
    27,172Total Proved Reserves
    
    
    584,933
    
    
    
    580,473
    
    
    
    493,210
    
    
    
    34,149
    
    
    
    33,020
    
    
    
    31,721
    
    
    
    224,077
    
    
    
    222,908
    
    
    
    194,139Probable Reserves
    
    
    203,168
    
    
    
    201,735
    
    
    
    169,631
    
    
    
    15,274
    
    
    
    14,954
    
    
    
    13,999
    
    
    
    80,048
    
    
    
    79,708
    
    
    
    68,764Total Proved Plus
Probable Reserves
    
    
    788,101
    
    
    
    782,208
    
    
    
    662,841
    
    
    
    49,423
    
    
    
    47,974
    
    
    
    45,720
    
    
    
    304,125
    
    
    
    302,616
    
    
    
    262,902
 
 Notes:(1)
    
    Constant prices are shown under the heading   Pricing Assumptions.(2)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil. - 39 -




---



##### 



Summary of Net Present Value
of Future Net Revenue
as of December 31, 2008
Before and After Income Tax
(Constant Prices and Costs) (1)
 Before Income Taxes
    
    
    
    
    
    
    
    
    
    
    Unit ValueDiscounted At (%/Year)
    
    
    
    
    
    
    
    
    
    
    Before Income Tax0%
    
    
    5%
    
    
    10%
    
    
    15%
    
    
    20%
    
    
    Discounted At 10%/Year(2)Reserves Category
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    $/boe
    
    
    $/McfeProved ReservesProved Developed Producing
    
    
    3,001
    
    
    
    2,362
    
    
    
    1,967
    
    
    
    1,697
    
    
    
    1,502
    
    
    
    12.07
    
    
    
    2.01Proved Developed Non-Producing
    
    
    77
    
    
    
    51
    
    
    
    37
    
    
    
    29
    
    
    
    23
    
    
    
    9.30
    
    
    
    1.55Proved Undeveloped
    
    
    356
    
    
    
    163
    
    
    
    62
    
    
    
    4
    
    
    
    (32
    )
    
    
    2.28
    
    
    
    0.38Total Proved Reserves
    
    
    3,434
    
    
    
    2,576
    
    
    
    2,066
    
    
    
    1,730
    
    
    
    1,492
    
    
    
    10.64
    
    
    
    1.77Probable Reserves
    
    
    1,386
    
    
    
    787
    
    
    
    509
    
    
    
    356
    
    
    
    263
    
    
    
    7.40
    
    
    
    1.23Total Proved Plus Probable
Reserves
    
    
    4,820
    
    
    
    3,363
    
    
    
    2,575
    
    
    
    2,086
    
    
    
    1,755
    
    
    
    9.79
    
    
    
    1.63
 After Income TaxesDiscounted At (%/Year)0%
    
    
    5%
    
    
    10%
    
    
    15%
    
    
    20%Reserves Category
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    2,951
    
    
    
    2,344
    
    
    
    1,951
    
    
    
    1,688
    
    
    
    1,489Proved Developed Non-Producing
    
    
    49
    
    
    
    33
    
    
    
    24
    
    
    
    19
    
    
    
    14Proved Undeveloped
    
    
    280
    
    
    
    141
    
    
    
    41
    
    
    
    (17
    )
    
    
    (50
    )Total Proved Reserves
    
    
    3,280
    
    
    
    2,518
    
    
    
    2,016
    
    
    
    1,685
    
    
    
    1,453Probable Reserves
    
    
    1,109
    
    
    
    729
    
    
    
    461
    
    
    
    318
    
    
    
    231Total Proved Plus Probable
Reserves
    
    
    4,389
    
    
    
    3,247
    
    
    
    2,477
    
    
    
    2,003
    
    
    
    1,684
 
 Notes:(1)
    
    Constant prices are shown under the heading   Pricing Assumptions.(2)
    
    Net present value of future net revenue per reserve unit values are based on Pengrowths net
reserves - 40 -




---



##### 



Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2008
(Constant Prices and Costs) (1)
 Future NetRevenue
    
    
    
    
    
    Future netCapital
    
    
    
    
    
    Before
    
    
    
    
    
    RevenueOperating
    
    Development
    
    Abandonment
    
    Income
    
    Income
    
    After IncomeRevenue
    
    Royalties(2)
    
    Costs
    
    Costs
    
    Costs(3)
    
    Taxes
    
    Tax
    
    TaxesReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    8,839
    
    
    
    1,111
    
    
    
    3,616
    
    
    
    524
    
    
    
    153
    
    
    
    3,434
    
    
    
    (154
    )
    
    
    3,280Total Proved Plus
Probable Reserves
    
    
    11,998
    
    
    
    1,530
    
    
    
    4,676
    
    
    
    813
    
    
    
    160
    
    
    
    4,820
    
    
    
    (431
    )
    
    
    4,389
 Notes:(1)
    
    Constant prices are shown under the heading   Pricing Assumptions.(2)
    
    Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova
Scotia. This includes the impact of the New Royalty Framework implemented by the Government
of Alberta on January 1, 2009, and the optional Transitional Royalty until December 31, 2013
for qualifying wells drilled in Alberta after November 18, 2008.(3)
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See
Pengrowth  Operational Information  Additional Information Concerning Abandonment &
Reclamation Costs. Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2008
(Constant Prices and Costs) (1)
 Future NetRevenue BeforeIncome Taxes(discounted at 10%/yr)
    
    Unit Value(4)Reserves Category
    
    Production Group
    
    ($MM)
    
    ($/Boe)
    
    ($/Mcfe)Total Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other
by-products)(2)
    
    
    779
    
    
    
    8.59
    
    
    
    1.43Heavy Oil (including solution gas and other by-products)(1)
    
    
    81
    
    
    
    5.44
    
    
    
    0.91Natural Gas (including by-products but excluding solution gas from
oil wells)(3)
    
    
    1,136
    
    
    
    13.75
    
    
    
    2.29Non-conventional Oil & Gas Activities
    
    
    70
    
    
    
    11.56
    
    
    
    1.93Total
    
    
    2,066
    
    
    
    10.64
    
    
    
    1.77Total Proved Plus
     Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other
by-products)(2)
    
    
    960
    
    
    
    7.87
    
    
    
    1.31Heavy Oil (including solution gas and other by-products)(1)
    
    
    97
    
    
    
    5.01
    
    
    
    0.84Natural Gas (including by-products but excluding solution gas from
oil wells)(3)
    
    
    1,432
    
    
    
    12.74
    
    
    
    2.12Non-conventional Oil & Gas Activities
    
    
    85
    
    
    
    9.78
    
    
    
    1.63Total
    
    
    2,575
    
    
    
    9.79
    
    
    
    1.63
 Notes:(1)
    
    Constant prices are shown under the heading   Pricing Assumptions.(2)
    
    NGLs associated with the production of solution gas are included as a by-product.(3)
    
    NGLs associated with the production of natural gas are included as a by-product.(4)
    
    Net present value of future net revenue per reserve unit values are based on Pengrowths net
reserves. - 41 -




---



##### 



Pricing Assumptions
 Forecast Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)WTI
    
    Edmonton
    
    Cromer
    
    HardistyCushing
    
    Par Price
    
    Medium
    
    Heavy 120
    
    AECO Gas
    
    
    
    
    
    
    
    
    
    Pentanes
    
    Inflation
    
    ExchangeOklahoma
    
    400API
    
    29.30 API
    
    API
    
    Price
    
    Propane
    
    Butane
    
    Plus
    
    Rates(2)
    
    Rate(3)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/MMBtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    (%/Year)
    
    ($US/Cdn)2008(4)
    
    
    99.48
    
    
    
    103.44
    
    
    
    93.74
    
    
    
    75.54
    
    
    
    8.16
    
    
    
    57.82
    
    
    
    76.91
    
    
    
    104.46
    
    
    
    
    
    
    
    2009
    
    
    57.50
    
    
    
    68.61
    
    
    
    59.00
    
    
    
    43.10
    
    
    
    7.58
    
    
    
    43.22
    
    
    
    52.14
    
    
    
    69.98
    
    
    
    2.0
    
    
    
    0.832010
    
    
    68.00
    
    
    
    78.94
    
    
    
    68.68
    
    
    
    49.76
    
    
    
    7.94
    
    
    
    49.73
    
    
    
    61.57
    
    
    
    80.52
    
    
    
    2.0
    
    
    
    0.852011
    
    
    74.00
    
    
    
    83.54
    
    
    
    73.52
    
    
    
    54.35
    
    
    
    8.34
    
    
    
    52.63
    
    
    
    65.16
    
    
    
    85.21
    
    
    
    2.0
    
    
    
    0.882012
    
    
    85.00
    
    
    
    90.92
    
    
    
    80.01
    
    
    
    59.23
    
    
    
    8.70
    
    
    
    57.28
    
    
    
    70.92
    
    
    
    92.74
    
    
    
    2.0
    
    
    
    0.932013
    
    
    92.01
    
    
    
    95.91
    
    
    
    84.40
    
    
    
    62.54
    
    
    
    8.95
    
    
    
    60.42
    
    
    
    74.81
    
    
    
    97.82
    
    
    
    2.0
    
    
    
    0.952014
    
    
    93.85
    
    
    
    97.84
    
    
    
    86.10
    
    
    
    63.82
    
    
    
    9.14
    
    
    
    61.64
    
    
    
    76.32
    
    
    
    99.80
    
    
    
    2.0
    
    
    
    0.952015
    
    
    95.73
    
    
    
    99.82
    
    
    
    87.84
    
    
    
    65.13
    
    
    
    9.34
    
    
    
    62.89
    
    
    
    77.86
    
    
    
    101.81
    
    
    
    2.0
    
    
    
    0.952016
    
    
    97.64
    
    
    
    101.83
    
    
    
    89.61
    
    
    
    66.46
    
    
    
    9.54
    
    
    
    64.15
    
    
    
    79.43
    
    
    
    103.87
    
    
    
    2.0
    
    
    
    0.952017
    
    
    99.59
    
    
    
    103.89
    
    
    
    91.42
    
    
    
    67.83
    
    
    
    9.75
    
    
    
    65.45
    
    
    
    81.03
    
    
    
    105.97
    
    
    
    2.0
    
    
    
    0.952018
    
    
    101.59
    
    
    
    105.99
    
    
    
    93.27
    
    
    
    69.22
    
    
    
    9.95
    
    
    
    66.77
    
    
    
    82.67
    
    
    
    108.10
    
    
    
    2.0
    
    
    
    0.95Thereafter
    
    +2%/yr
    
    +2%/yr
    
    +2%/yr
    
    +2%/yr
    
    +2%/yr
    
    +2%/yr
    
    +2%/yr
    
    +2%/yr
    
    
    2.0
    
    
    
    0.95
 Notes:(1)
    
    FOB Edmonton.(2)
    
    Inflation rates for forecasting prices and costs.(3)
    
    The exchange rates used to generate the benchmark reference prices in this table.(4)
    
    Actual weighted average historical prices for 2008. Constant Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)WTI
    
    Edmonton
    
    Cromer
    
    HardistyCushing
    
    Par Price
    
    Medium
    
    Heavy 12°
    
    AECO Gas
    
    
    
    
    
    
    
    
    
    Pentanes
    
    Inflation
    
    ExchangeOklahoma
    
    400 API
    
    29.30 API
    
    API
    
    Price
    
    Propane
    
    Butane
    
    Plus
    
    Rate
    
    Rate(2)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/MMBtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    (%/Year)
    
    ($US/Cdn)December 31, 2008
    
    
    44.60
    
    
    
    44.27
    
    
    
    37.98
    
    
    
    30.24
    
    
    
    6.22
    
    
    
    27.89
    
    
    
    33.65
    
    
    
    55.93
    
    
    
    0.0
    %
    
    
    0.817
 Notes:(1)
    
    FOB Edmonton.(2)
    
    The exchange rate used to generate the benchmark reference prices in this table. - 42 -




---



##### 



Reserves Reconciliation
  Reserves Reconciliation
By Principal 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(Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)December 31, 2007
    
    
    92,817
    
    
    
    31,180
    
    
    
    123,997
    
    
    
    16,898
    
    
    
    4,883
    
    
    
    21,781
    
    
    
    21,677
    
    
    
    7,185
    
    
    
    28,862Extensions
    
    
    619
    
    
    
    595
    
    
    
    1,214
    
    
    
    199
    
    
    
    49
    
    
    
    247
    
    
    
    796
    
    
    
    793
    
    
    
    1,589Infill Drilling
    
    
    1,263
    
    
    
    330
    
    
    
    1,592
    
    
    
    260
    
    
    
    306
    
    
    
    566
    
    
    
    103
    
    
    
    182
    
    
    
    285Improved Recovery
    
    
    1,314
    
    
    
    695
    
    
    
    2,009
    
    
    
    0
    
    
    
    6,389
    
    
    
    6,389
    
    
    
    93
    
    
    
    8
    
    
    
    101Technical Revisions
    
    
    1,965
    
    
    
    (2,349
    )
    
    
    (384
    )
    
    
    1,884
    
    
    
    (179
    )
    
    
    1,705
    
    
    
    1,885
    
    
    
    (541
    )
    
    
    1,344Discoveries
    
    
    17
    
    
    
    3
    
    
    
    20
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0Acquisitions
    
    
    1,182
    
    
    
    394
    
    
    
    1,576
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    2,282
    
    
    
    1,251
    
    
    
    3,533Dispositions
    
    
    (11
    )
    
    
    (3
    )
    
    
    (14
    )
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    (10
    )
    
    
    (5
    )
    
    
    (15
    )Economic Factors
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0Production
    
    
    (8,905
    )
    
    
    0
    
    
    
    (8,905
    )
    
    
    (2,973
    )
    
    
    0
    
    
    
    (2,973
    )
    
    
    (3,390
    )
    
    
    0
    
    
    
    (3,390
    )December 31, 2008
    
    
    90,261
    
    
    
    30,846
    
    
    
    121,107
    
    
    
    16,268
    
    
    
    11,448
    
    
    
    27,716
    
    
    
    23,436
    
    
    
    8,873
    
    
    
    32,309
 Natural Gas
    
    Coal Bed Methane
    
    Total Oil Equivalent Basis(1)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, 2007
    
    
    614,363
    
    
    
    193,874
    
    
    
    808,237
    
    
    
    37,002
    
    
    
    17,115
    
    
    
    54,117
    
    
    
    239,953
    
    
    
    78,413
    
    
    
    318,366Extensions
    
    
    11,009
    
    
    
    13,457
    
    
    
    24,466
    
    
    
    1,298
    
    
    
    2,284
    
    
    
    3,582
    
    
    
    3,665
    
    
    
    4,061
    
    
    
    7,726Infill Drilling
    
    
    8,885
    
    
    
    1,187
    
    
    
    10,072
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    3,106
    
    
    
    1,015
    
    
    
    4,122Improved Recovery
    
    
    339
    
    
    
    (104
    )
    
    
    236
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    1,464
    
    
    
    7,075
    
    
    
    8,539Technical Revisions
    
    
    21,415
    
    
    
    (13,230
    )
    
    
    8,185
    
    
    
    (1,603
    )
    
    
    (4,440
    )
    
    
    (6,042
    )
    
    
    9,036
    
    
    
    (6,014
    )
    
    
    3,022Discoveries
    
    
    622
    
    
    
    295
    
    
    
    917
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    120
    
    
    
    52
    
    
    
    173Acquisitions
    
    
    19,181
    
    
    
    10,082
    
    
    
    29,263
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    6,661
    
    
    
    3,326
    
    
    
    9,987Dispositions
    
    
    (1,185
    )
    
    
    (398
    )
    
    
    (1,583
    )
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    (219
    )
    
    
    (74
    )
    
    
    (292
    )Economic Factors
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0Production
    
    
    (83,216
    )
    
    
    0
    
    
    
    (83,216
    )
    
    
    (3,678
    )
    
    
    0
    
    
    
    (3,678
    )
    
    
    (29,751
    )
    
    
    0
    
    
    
    (29,751
    )December 31, 2008
    
    
    591,413
    
    
    
    205,163
    
    
    
    796,576
    
    
    
    33,019
    
    
    
    14,960
    
    
    
    47,979
    
    
    
    234,036
    
    
    
    87,854
    
    
    
    321,891
 
 Note:(1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil. - 43 -




---



##### 



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, 2007
    
    
    202,898
    
    
    
    241,169
    
    
    
    319,921Extensions
    
    
    3,805
    
    
    
    3,689
    
    
    
    7,762Infill Drilling
    
    
    3,766
    
    
    
    3,109
    
    
    
    4,125Improved Recovery
    
    
    873
    
    
    
    1,464
    
    
    
    8,539Technical Revisions
    
    
    13,346
    
    
    
    9,244
    
    
    
    3,264Discoveries
    
    
    0
    
    
    
    120
    
    
    
    173Acquisitions
    
    
    6,016
    
    
    
    6,661
    
    
    
    9,987Dispositions
    
    
    (114
    )
    
    
    (224
    )
    
    
    (299
    )Economic Factors
    
    
    0
    
    
    
    0
    
    
    
    0Production
    
    
    (30,009
    )
    
    
    (30,009
    )
    
    
    (30,009
    )December 31, 2008
    
    
    200,580
    
    
    
    235,224
    
    
    
    323,463
 
 Note:(1)
    
    Natural gas has been converted to barrels of oil equivalent on
the basis of six Mcf of natural gas being equal to one barrel of oil.  
    
    Reserve additions from drilling activity, improved recovery and technical revisions
replaced 2008 production by 59 percent and 80 percent for Total Proved and Proved Plus
Probable Reserves, respectively. Based on all changes, including acquisitions and
dispositions, reserve replacement was 80 percent and 112 percent for Total Proved and
Proved Plus Probable Reserves, respectively.
    
    New reserves of 20.6 MMboe added for development activity accounted for
approximately 61 percent of the Total Proved Plus Probable Reserves additions in 2008.
Most significant were the improved recovery addition for the proposed thermal project
at Lindbergh, drilling extensions at Carson Creek and infill drilling and improved
recover adds at Weyburn and Deer Mountain. Reserve increases in the Proved Producing
category also resulted from reclassification of Proved and Probable Undeveloped
Reserves primarily for infill drilling and drilling extensions at Monogram, Fenn Big
Valley (CBM), Weyburn and Swan Hills.
    
    The net increase of 9.7 MMboe to Proved Plus Probable Reserves from acquisitions and
dispositions was almost entirely from the acquisition of additional interests in
Harmattan, a focus area for Pengrowth. Only some minor sales were made in 2008,
disposing of small, isolated properties when opportunities arose.
    
    Various performance related revisions were made to previous estimates resulting in a
net positive change. The largest revisions to Proved Plus Probable Reserves occurred
at Judy Creek (+1,483 Mboe), Quirk Creek (+1,137 Mboe), Carson Creek (+892 Mboe) and
Kidney (-641 Mboe).
 
 Additional Information Relating to Reserves Data
 Undeveloped Reserves
   - 44 -




---



##### 



Company Gross Reserves First Attributed by Year (1)
 Proved
Undeveloped Reserves
 Light & Medium Oil
    
    Heavy Oil
    
    Natural Gas
    
    Coal Bed Methane
    
    Natural Gas Liquids
    
    Total Oil Equivalent(Mbbl)
    
    (Mbbl)
    
    (MMcf)
    
    (MMcf)
    
    (Mbbl)
    
    (Mboe)(2)First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total atAttributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-endPrior
    
    
    18,755
    
    
    
    18,755
    
    
    
    1,699
    
    
    
    1,699
    
    
    
    29,005
    
    
    
    29,005
    
    
    
    0
    
    
    
    0
    
    
    
    1,088
    
    
    
    1,088
    
    
    
    26,376
    
    
    
    26,3762006
    
    
    1,766
    
    
    
    17,352
    
    
    
    295
    
    
    
    1,891
    
    
    
    16,088
    
    
    
    44,198
    
    
    
    3,955
    
    
    
    3,955
    
    
    
    421
    
    
    
    1,439
    
    
    
    5,822
    
    
    
    28,7082007
    
    
    1,932
    
    
    
    18,985
    
    
    
    342
    
    
    
    2,194
    
    
    
    20,905
    
    
    
    50,224
    
    
    
    11,356
    
    
    
    13,911
    
    
    
    398
    
    
    
    1,361
    
    
    
    8,049
    
    
    
    33,2292008
    
    
    1,000
    
    
    
    17,029
    
    
    
    382
    
    
    
    1,676
    
    
    
    3,513
    
    
    
    48,311
    
    
    
    1,858
    
    
    
    10,372
    
    
    
    125
    
    
    
    1,120
    
    
    
    2,402
    
    
    
    29,606Probable
Undeveloped ReservesLight & Medium Oil
    
    Heavy Oil
    
    Natural Gas
    
    Coal Bed Methane
    
    Natural Gas Liquids
    
    Total Oil Equivalent(Mbbl)
    
    (Mbbl)
    
    (MMcf)
    
    (MMcf)
    
    (Mbbl)
    
    (Mboe)(2)First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total at
    
    First
    
    Total atAttributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-end
    
    Attributed
    
    year-endPrior
    
    
    8,104
    
    
    
    8,104
    
    
    
    1,506
    
    
    
    1,506
    
    
    
    16,805
    
    
    
    16,805
    
    
    
    0
    
    
    
    0
    
    
    
    1,062
    
    
    
    1,062
    
    
    
    13,473
    
    
    
    13,4732006
    
    
    2,577
    
    
    
    11,350
    
    
    
    507
    
    
    
    1,586
    
    
    
    19,510
    
    
    
    56,662
    
    
    
    4,306
    
    
    
    4,306
    
    
    
    531
    
    
    
    2,151
    
    
    
    7,585
    
    
    
    25,2482007
    
    
    3,065
    
    
    
    13,497
    
    
    
    726
    
    
    
    2,269
    
    
    
    25,386
    
    
    
    64,986
    
    
    
    8,170
    
    
    
    10,155
    
    
    
    670
    
    
    
    2,716
    
    
    
    10,054
    
    
    
    31,0062008
    
    
    1,850
    
    
    
    12,372
    
    
    
    6,997
    
    
    
    7,857
    
    
    
    17,686
    
    
    
    68,822
    
    
    
    4,514
    
    
    
    7,948
    
    
    
    782
    
    
    
    3,478
    
    
    
    13,329
    
    
    
    36,502
 
 Notes:(1)
    
    First Attributed refers to reserves first attributed at year-end of the corresponding
fiscal year.(2)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil. Proved Undeveloped Reserves
  2 2 2 2
  - 45 -




---



##### 



Probable Undeveloped Reserves
  
 Future Development Costs
  TotalDiscounted2009
    
    2010
    
    2011
    
    2012
    
    2013
    
    Remainder
    
    Undiscounted
    
    at 10%Reserve Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    157
    
    
    
    146
    
    
    
    61
    
    
    
    30
    
    
    
    19
    
    
    
    111
    
    
    
    524
    
    
    
    402(Constant Prices and Costs)Proved Reserves
    
    
    157
    
    
    
    149
    
    
    
    63
    
    
    
    32
    
    
    
    21
    
    
    
    157
    
    
    
    579
    
    
    
    422(Forecast Prices and Costs)Proved & Probable Reserves
    
    
    220
    
    
    
    283
    
    
    
    204
    
    
    
    46
    
    
    
    36
    
    
    
    220
    
    
    
    1,009
    
    
    
    748(Forecast Prices and Costs)
  
 Finding, Development and Acquisition Costs
 Finding and Development Costs
   - 46 -




---



##### 



2
    Acquisitions and Divestitures
   
 Future Development Capital
  - 47 -




---



##### 



2008 Finding, Development and Acquisition Costs
Company Interest Reserves
(Forecast Prices and Costs)
 Proved plusProved
    
    ProbableFD&A Costs Excluding Changes in Future Development CapitalExploration and Development Capital Expenditures ($M)
    
    $
    388,300
    
    
    $
    388,300Exploration and Development Reserve Additions including Revisions (Mboe)
    
    
    17,627
    
    
    
    23,863Finding and Development Cost ($/boe)
    
    $
    22.03
    
    
    $
    16.27Net Acquisition Capital ($M)
    
    $
    130,795
    
    
    $
    130,795Net Acquisition Reserve Additions (Mboe)
    
    
    6,437
    
    
    
    9,688Net Acquisition Cost ($/boe)
    
    $
    20.32
    
    
    $
    13.50Total Capital Expenditures including Net Acquisitions ($M)
    
    $
    519,095
    
    
    $
    519,095Reserve Additions including Net Acquisitions (Mboe)
    
    
    24,064
    
    
    
    33,551Finding Development and Acquisition Cost ($/boe)
    
    $
    21.57
    
    
    $
    15.47FD&A Costs Including Changes in Future Development CapitalExploration and Development Capital Expenditures ($M)
    
    $
    388,300
    
    
    $
    388,300Exploration and Development Change in FDC ($M)
    
    $
    12,000
    
    
    $
    180,000Exploration and Development Capital including Change in FDC ($M)
    
    $
    400,300
    
    
    $
    568,300Exploration and Development Reserve Additions including Revisions (Mboe)
    
    
    17,627
    
    
    
    23,863Finding and Development Cost ($/boe)
    
    $
    22.71
    
    
    $
    23.82Net Acquisition Capital ($M)
    
    $
    130,795
    
    
    $
    130,795Net Acquisition FDC ($M)
    
    $
    1,000
    
    
    $
    10,000Net Acquisition Capital including FDC ($M)
    
    $
    131,795
    
    
    $
    140,795Net Acquisition Reserve Additions (Mboe)
    
    
    6,437
    
    
    
    9,688Net Acquisition Cost ($/boe)
    
    $
    20.47
    
    
    $
    14.53Total Capital Expenditures including Net Acquisitions ($M)
    
    $
    519,095
    
    
    $
    519,095Total Change in FDC ($M)
    
    $
    13,000
    
    
    $
    190,000Total Capital including Change in FDC ($M)
    
    $
    532,095
    
    
    $
    709,095Reserve Additions including Net Acquisitions (Mboe)
    
    
    24,064
    
    
    
    33,551Finding Development and Acquisition Cost including change in FDC ($/boe)
    
    $
    22.11
    
    
    $
    21.14
 
 Notes:(1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of
six Mcf of natural gas being equal to one barrel of oil.(2)
    
    The Proved plus Probable values for Exploration and Development Reserve
Additions including Revisions and for Reserve Additions including Net
Acquisitions includes 6,345 Mboe for the proposed Lindbergh oil sands SAGD pilot
project. The 2008 costs associated with the Lindbergh project were $20 million
and the change in future development costs, in addition to the 2008 costs, is
$123 million. If the Lindbergh SAGD pilot project reserves and the associated
2008 and future development costs were excluded, Pengrowths 2008 finding,
development and acquisition costs, including the change in FDC, would be $20.81
per boe on a Proved plus Probable basis. These Reserves and costs are only
associated with the pilot area; please see   Lindbergh Oil Sands Reserves and
Contingent Resources for additional information.  
 Other Oil and Gas Information
 Oil and Gas Wells
  - 48 -




---



##### 



Producing
    
    Non-ProducingGross
    
    Net
    
    Gross
    
    NetCrude Oil WellsAlberta
    
    
    2,449
    
    
    
    1,559
    
    
    
    468
    
    
    
    282British Columbia
    
    
    154
    
    
    
    108
    
    
    
    46
    
    
    
    43Saskatchewan
    
    
    1,181
    
    
    
    295
    
    
    
    176
    
    
    
    81Nova Scotia
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0Natural Gas WellsAlberta
    
    
    5,881
    
    
    
    2,963
    
    
    
    527
    
    
    
    287British Columbia
    
    
    118
    
    
    
    76
    
    
    
    22
    
    
    
    15Saskatchewan
    
    
    52
    
    
    
    49
    
    
    
    87
    
    
    
    47Nova Scotia
    
    
    19
    
    
    
    1
    
    
    
    0
    
    
    
    0Other(1)Alberta
    
    
    252
    
    
    
    222
    
    
    
    158
    
    
    
    109British Columbia
    
    
    0
    
    
    
    0
    
    
    
    46
    
    
    
    43Saskatchewan
    
    
    22
    
    
    
    11
    
    
    
    22
    
    
    
    19Total
    
    
    10,128
    
    
    
    5,286
    
    
    
    1,552
    
    
    
    926
 Note:(1)
    
    Pengrowth cannot classify these wells as either oil or gas. Properties with No Attributed Reserves
  Unproved Properties
as at December 31, 2008
 Maximum Net Acres Expected toLocation
    
    Gross Acres
    
    Net Acres
    
    Expire During 2009Alberta
    
    
    974,083
    
    
    
    656,192
    
    
    
    92,591British Columbia
    
    
    279,222
    
    
    
    153,748
    
    
    
    15,948Ontario
    
    
    4,776
    
    
    
    
    
    
    
    Saskatchewan
    
    
    64,145
    
    
    
    53,522
    
    
    
    1,920Nova Scotia
    
    
    200,650
    
    
    
    15,957
    
    
    
    Total
    
    
    1,522,876
    
    
    
    879,419
    
    
    
    110,459
  Lindbergh Oil Sands Reserves and Contingent Resources
 °
   - 49 -




---



##### 



Pilot Project Probable and Probable
plus Possible Reserves and Net Present Value of Future Net Revenue
as of December 31, 2008
(Forecast Prices and Costs)
 Probable plusProbable Reserves
    
    Possible Reserves(1)Reserves (Mbbl)
    
    
    6,345
    
    
    
    35,695Before tax net present value of
future net revenue0 % discount rate ($MM)
    
    $
    85.7
    
    
    $
    1,071.25% discount rate ($MM)
    
    $
    35.5
    
    
    $
    298.610% discount rate ($MM)
    
    $
    4.6
    
    
    $
    96.615% discount rate ($MM)
    
    $
    (14.7
    )
    
    $
    24.620% discount rate ($MM)
    
    $
    (26.6
    )
    
    $
    (7.5
    )
 
 Note:(1)
    
    GLJ has estimated our undiscounted capital to be $327 million and the 10 percent discounted
capital amount to be $129 million to develop the Proved plus Probable Reserves.  December 31, 2008Contingent Resources(1)(MMbbl)Low estimate(2)
    
    
    144.2Best estimate(3)
    
    
    194.2High Estimate(4)
    
    
    264.1
 
 Notes:(1)
    
    Contingent Resources are those quantities of petroleum estimated, as of a given date, to be
potentially recoverable from known accumulations using established technology or technology
under development, but which are not currently considered to be commercially recoverable due
to one or more contingencies. The contingencies may include factors such as economics, legal,
environmental, political, regulatory or lack of markets. Contingent Resources are further
classified in accordance with the level of certainty associated with the estimates.(2)
    
    A low estimate is a conservative estimate of the quantity of oil that will be recovered from
the accumulation, which under probabilistic methodology reflects a 90 percent confidence
level.(3)
    
    A best estimate is a best estimate of the quantity of oil that will be recovered from the
accumulation, which under probabilistic methodology reflects a 50 percent confidence level.(4)
    
    A high estimate is an optimistic estimate of the quantity of oil that will be recovered from
the accumulation, which under probabilistic methodology reflects a 10 percent confidence
level. - 50 -




---



##### 



Forward Contracts
  
 Additional Information Concerning Abandonment & Reclamation Costs
    Asset Retirement Obligations
 2009
    
    2010
    
    2011
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment, Reclamation,
Remediation & Dismantling
    
    
    14,176
    
    
    
    14,828
    
    
    
    17,168
    
    
    
    2,236,964
    
    
    
    2,283,136Discounted at ten percent
    
    
    13,516
    
    
    
    12,853
    
    
    
    13,528
    
    
    
    215,725
    
    
    
    256,622
 - Other Oil and Gas
Information  Oil and Gas Wells
 
 Costs Incurred
  - 51 -




---



##### 



AmountNature of Cost
    
    ($M)Acquisition Costs(1)Proved
    
    
    126,022Unproved
    
    
    Exploration Costs
    
    
    22,012Development Costs
    
    
    366,300Total
    
    
    514,334
 
 Note:(1)
    
    Based on the values assigned to property, plant and equipment in the
purchase price allocations for the Accrete acquisition and for several minor
property acquisitions 
 Exploration and Development Activities
  Development
    
    Exploration
    
    TotalWells
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetGas
    
    
    371
    
    
    
    142.4
    
    
    
    8
    
    
    
    4.8
    
    
    
    379
    
    
    
    147.2Oil
    
    
    90
    
    
    
    47.3
    
    
    
    3
    
    
    
    1.3
    
    
    
    93
    
    
    
    48.6Service
    
    
    16
    
    
    
    6.2
    
    
    
    
    
    
    
    
    
    
    
    16
    
    
    
    6.2Dry
    
    
    14
    
    
    
    12.1
    
    
    
    5
    
    
    
    3.1
    
    
    
    19
    
    
    
    15.2Total
    
    
    491
    
    
    
    208.0
    
    
    
    16
    
    
    
    9.2
    
    
    
    507
    
    
    
    217.2
 
 Production Estimates
  2009 Estimated ProductionConstant Prices and Costs
    
    Forecast Prices and CostsTotal Proved Plus
    
    
    
    
    
    Total Proved PlusTotal Proved
    
    Probable
    
    Total Proved
    
    ProbableLight and Medium Crude Oil
(bblpd)
    
    
    23,615
    
    
    
    24,500
    
    
    
    23,615
    
    
    
    24,502Heavy Oil (bblpd)
    
    
    6,971
    
    
    
    7,274
    
    
    
    6,971
    
    
    
    7,279Natural Gas (Mcfpd)
    
    
    233,518
    
    
    
    245,958
    
    
    
    233,547
    
    
    
    246,008Natural Gas Liquids (bblpd)
    
    
    10,052
    
    
    
    10,609
    
    
    
    10,051
    
    
    
    10,609Total (boepd)
    
    
    79,558
    
    
    
    83,376
    
    
    
    79,562
    
    
    
    83,391
 - 52 -




---



##### 



Production History (Netback)
  YearQuarter Ended
    
    EndedMarch 31,
    
    June 30,
    
    September
    
    December
    
    December2008
    
    2008
    
    30, 2008
    
    31, 2008
    
    31, 2008Light Crude OilAverage Daily Oil Production(1) (bblpd)
    
    
    25,103
    
    
    
    25,052
    
    
    
    23,286
    
    
    
    24,236
    
    
    
    24,416Sales Price (after realized commodity price risk
management) ($/bbl)
    
    
    79.38
    
    
    
    83.88
    
    
    
    82.00
    
    
    
    65.87
    
    
    
    77.78Processing and other income ($/bbl)
    
    
    0.67
    
    
    
    1.10
    
    
    
    1.46
    
    
    
    0.04
    
    
    
    0.81Royalties ($/bbl)
    
    
    (15.44
    )
    
    
    (17.52
    )
    
    
    (20.10
    )
    
    
    (14.02
    )
    
    
    (16.73
    )Amortization of injectants ($/bbl)
    
    
    (3.40
    )
    
    
    (2.50
    )
    
    
    (3.05
    )
    
    
    (2.64
    )
    
    
    (2.90
    )Production Costs(2)($/bbl)
    
    
    (16.03
    )
    
    
    (16.89
    )
    
    
    (15.05
    )
    
    
    (15.05
    )
    
    
    (15.77
    )Operating Netback ($/bbl)
    
    
    45.18
    
    
    
    48.07
    
    
    
    45.26
    
    
    
    34.20
    
    
    
    43.19Heavy OilAverage Daily Oil Production(1) (bblpd)
    
    
    7,740
    
    
    
    8,242
    
    
    
    8,287
    
    
    
    8,217
    
    
    
    8,122Sales Price ($/bbl)
    
    
    62.74
    
    
    
    100.34
    
    
    
    96.93
    
    
    
    42.20
    
    
    
    75.77Processing and other income ($/bbl)
    
    
    0.27
    
    
    
    0.70
    
    
    
    0.02
    
    
    
    0.29
    
    
    
    0.32Royalties ($/bbl)
    
    
    (9.18
    )
    
    
    (15.07
    )
    
    
    (15.87
    )
    
    
    (1.95
    )
    
    
    (10.54
    )Production Costs(2)($/bbl)
    
    
    (12.34
    )
    
    
    (11.60
    )
    
    
    (13.17
    )
    
    
    (12.77
    )
    
    
    (12.47
    )Operating Netback ($/bbl)
    
    
    41.49
    
    
    
    74.37
    
    
    
    67.91
    
    
    
    27.77
    
    
    
    53.08NGLsAverage Daily NGL Production(1) (bblpd)
    
    
    9,666
    
    
    
    8,596
    
    
    
    8,361
    
    
    
    10,634
    
    
    
    9,315Sales Price ($/bbl)
    
    
    66.96
    
    
    
    92.25
    
    
    
    87.06
    
    
    
    43.87
    
    
    
    70.67Royalties ($/bbl)
    
    
    (23.45
    )
    
    
    (38.77
    )
    
    
    (32.22
    )
    
    
    (12.27
    )
    
    
    (25.74
    )Production Costs(2)($/bbl)
    
    
    (12.28
    )
    
    
    (16.36
    )
    
    
    (14.62
    )
    
    
    (12.93
    )
    
    
    (13.93
    )Operating Netback ($/bbl)
    
    
    31.23
    
    
    
    37.12
    
    
    
    40.22
    
    
    
    18.67
    
    
    
    31.00Natural GasAverage Daily Gas Production(1) (Mcfpd)
    
    
    241,208
    
    
    
    234,028
    
    
    
    246,287
    
    
    
    241,709
    
    
    
    240,825Sales Price after realized commodity price risk
management) ($/Mcf)
    
    
    7.72
    
    
    
    9.40
    
    
    
    8.29
    
    
    
    7.40
    
    
    
    8.19Processing and other income ($/Mcf)
    
    
    0.28
    
    
    
    0.59
    
    
    
    0.72
    
    
    
    0.36
    
    
    
    0.49Royalties ($/Mcf)
    
    
    (1.64
    )
    
    
    (2.06
    )
    
    
    (2.19
    )
    
    
    (1.62
    )
    
    
    (1.88
    )Production Costs(2)($/Mcf)
    
    
    (2.13
    )
    
    
    (2.49
    )
    
    
    (2.42
    )
    
    
    (2.29
    )
    
    
    (2.33
    )Operating Netback ($/Mcf)
    
    
    4.23
    
    
    
    5.44
    
    
    
    4.40
    
    
    
    3.85
    
    
    
    4.47Barrels of Oil Equivalent Basis(3)Average Daily Production(1) (boepd)
    
    
    82,711
    
    
    
    80,895
    
    
    
    80,981
    
    
    
    83,373
    
    
    
    81,991Sales Price after realized commodity price risk
management) ($/boe)
    
    
    60.30
    
    
    
    73.21
    
    
    
    67.71
    
    
    
    50.34
    
    
    
    62.76Processing and other income ($/boe)
    
    
    1.06
    
    
    
    2.10
    
    
    
    2.61
    
    
    
    1.09
    
    
    
    1.71Royalties ($/boe)
    
    
    (13.05
    )
    
    
    (17.05
    )
    
    
    (17.39
    )
    
    
    (10.51
    )
    
    
    (14.46
    )Amortization of injectants ($/boe)
    
    
    (1.03
    )
    
    
    (0.77
    )
    
    
    (0.88
    )
    
    
    (0.77
    )
    
    
    (0.86
    )Production Costs(2)($/boe)
    
    
    (13.66
    )
    
    
    (15.34
    )
    
    
    (14.57
    )
    
    
    (13.92
    )
    
    
    (14.37
    )Operating Netback ($/boe)
    
    
    33.62
    
    
    
    42.15
    
    
    
    37.48
    
    
    
    26.23
    
    
    
    34.78
 
 Notes:(1)
    
    Before the deduction of royalties.(2)
    
    Includes transportation costs. Net of processing and other income.(3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one boe. - 53 -




---



##### 



Replacement of Properties
  Before Tax Net Asset Value (NAV) at December 31, 2008
 Pricing Assumptions
 Undiscounted
    
    
    5% Discount
    
    
    10% Discount
    
    
    15% Discount
    
    
    20% DiscountAmount
    
    
    Rate
    
    
    Rate
    
    
    Rate
    
    
    Rate(amounts in $MM except for NAV per Trust Unit)Undeveloped Lands(1)
    
    
    210Working Capital Deficit(2)
    
    
    (68
    )Reclamation Funds
    
    
    27Long Term Debt
    
    
    (1,697
    )Fair Value of Risk Management Contracts(3)
    
    
    146Other Liabilities(4)
    
    
    (85
    )Asset Retirement Obligations(5)
    
    
    (196
    )Total Other Assets and Liabilities
    
    
    (1,663
    )
    
    
    (1,663
    )
    
    
    (1,663
    )
    
    
    (1,663
    )
    
    
    (1,663
    )Value of Total Proved Plus Probable Reserves(6)
    
    
    11,909
    
    
    
    7,660
    
    
    
    5,582
    
    
    
    4,373
    
    
    
    3,589Total Net Asset Value
    
    
    10,246
    
    
    
    5,997
    
    
    
    3,919
    
    
    
    2,710
    
    
    
    1,926NAV per Trust Unit
    
    $
    40.01
    
    
    $
    23.42
    
    
    $
    15.30
    
    
    $
    10.58
    
    
    $
    7.52(256.1 million Trust Units outstanding as
at December 31, 2008)
 
 Notes:(1)
    
    Pengrowths internal estimate, calculated using the average land sale prices paid in 2008 in
Alberta, Saskatchewan and British Columbia.(2)
    
    Excludes distributions payable, current portion of risk management contracts and future
income taxes.(3)
    
    Represents the total fair value of risk management contracts at December 31, 2008.(4)
    
    Other liabilities include convertible debt and non-current contract liabilities.(5)
    
    The asset retirement obligation is based on Pengrowths estimate of future site restoration
and abandonment liabilities, discounted at 10 percent, less that portion of the asset
retirement obligations costs that are included in the value of Total Proved Plus Probable
Reserves.(6)
    
    Future net revenue prior to provisions for income tax, interest costs or general and
administrative costs. 
 - 54 -




---



##### 



TRUST UNITS
 
 The Trust Indenture
   Canadian Deposit Insurance Corporation Act
 
 The Trustee
    - 55 -




---



##### 



Stock Exchange Listings
  
 Ownership Restrictions
  
 Redemption Right
 in
specie
 
 Conversion Rights
  
 Voting at Meetings of Unitholders
   - 56 -




---



##### 



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, class A trust units and special units, in the aggregate;
or (ii) if the Trust Units, the class A trust units and the special units have become
ineligible for investment by RRSPs, RRIFs, RESPs and DPSPs;
    
    the termination must be approved by extraordinary resolution of the Unitholders; and
    
    a quorum representing five percent of the issued and outstanding Trust Units, class
A trust units and special units, in the aggregate, must be present or represented by
proxy at the meeting at which the vote is taken.
  
 Unitholder Limited Liability
  - 57 -




---



##### 



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.
   - 58 -




---



##### 



The Trustee
   
 EXCHANGEABLE SHARES
    - 59 -




---



##### 



DISTRIBUTIONS
 
 General
  
 Historical Distributions
 Risk Factors
  2008
    
    2007
    
    2006
    
    2005
    
    2004
    
    2003First Quarter
    
    $
    0.675
    
    
    $
    0.75
    
    
    $
    0.75
    
    
    $
    0.69
    
    
    $
    0.63
    
    
    $
    0.75Second Quarter
    
    
    0.675
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.64
    
    
    
    0.67Third Quarter
    
    
    0.675
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.67
    
    
    
    0.63
 - 60 -




---



##### 



2008
    
    2007
    
    2006
    
    2005
    
    2004
    
    2003Fourth Quarter
    
    
    0.565
    
    
    
    0.675
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.63Total
    
    $
    2.59
    
    
    $
    2.93
    
    
    $
    3.00
    
    
    $
    2.82
    
    
    $
    2.63
    
    
    $
    2.68
  2008
    
    2007
    
    2006
    
    2005
    
    2004
    
    2003Taxable Income(1)(per Trust Unit)
    
    $
    2.70
    
    
    $
    2.78
    
    
    $
    2.40
    
    
    $
    2.22
    
    
    $
    1.43
    
    
    $
    1.47(percent of distributions classified as taxable income)
    
    
    (100
    %)
    
    
    (95
    %)
    
    
    (80
    %)
    
    
    (80
    %)
    
    
    (55
    %)
    
    
    (55
    %)
 
 Note:(1)
    
    For Canadian residents, amounts treated as a return of capital generally are not required to
be included in a Unitholders income but such amounts will reduce the adjusted cost base to
the Unitholder of the Trust Units.  Cash distributions are not guaranteed. Risk Factors
 Certain
Canadian Federal Income Tax Considerations United States Federal Income Tax Considerations
 
 Restrictions on Distributions
  - 61 -




---



##### 



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;
 - 62 -




---



##### 



   depreciation, depletion and amortization expense; and   other non-cash amounts.Material Acquisition:
    
    An acquisition or series of acquisitions which increases the consolidated tangible
assets of Pengrowth by more than 5 percent.Subordinated Debt:
    
    Debt which, by its terms, is subordinated to the obligations to the lenders under
the Credit Facility.Total Capitalization:
    
    The aggregate of Consolidated Total Debt and the Unitholders equity (calculated in
accordance with GAAP as shown on the Trusts consolidated balance sheet)
 Senior Unsecured Notes
   
    
    the ratio of Consolidated EBITDA (as defined below) to interest expense for the four
immediately preceding fiscal quarters shall be not less than 4:1;
    
    with respect to the 2003 U.S. Senior Notes and the U.K. Senior Notes only, the
Consolidated Total Debt (as defined below) is limited to 60 percent of the Consolidated
Total Established Reserves (as defined below) determined and calculated not later than
the last day of the first fiscal quarter of the next succeeding fiscal year of the
Trust;
    
    with respect to the 2007 U.S. Senior Notes and the 2008 Senior Notes, the
Consolidated Total Debt (as defined below) to Total Capitalization (as defined below)
shall not exceed 55 percent at the end of each fiscal quarter; and
    
    the ratio of Consolidated Total Debt to Consolidated EBITDA for each period of four
consecutive fiscal quarters shall not exceed 3.5:1.
  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.
 - 63 -




---



##### 



Consolidated Total Debt:
    
    Has substantially the same meaning as Consolidated Senior
Debt in the definitions relating to the Credit Facility.Consolidated Total 
Established Reserves:
    
    The sum of: (i) 100 percent of the present value of
Pengrowths Proved Reserves; and (ii) 50 percent of the
present value of Pengrowths Probable Reserves.Total Capitalization:
    
    Consolidated Total Debt plus Unitholder equity in the Trust.
 Convertible Debentures
 Certain Canadian Federal Income Tax Considerations  Taxation of Unitholders who are Non-Residents of Canada
   
    
    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;
 
 - 64 -




---



##### 




    
    the Trust is required to deliver to the trustee under the Debenture Indenture,
within 120 days of the end of each calendar year, an officers certificate as to
compliance with the terms and conditions of the Debenture Indenture; and
    
    the Trust is prohibited from issuing additional debentures, which are convertible at
the option of the holder into Trust Units of equal ranking to the Debentures if the
principal amount of all issued and outstanding convertible debentures of the Trust
would exceed 25 percent of the Trusts total market capitalization after the issuance
of such additional debentures.
 
 CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
 
 Taxation of the Trust
 SIFT Legislation
    - 65 -




---



##### 



No assurance can be provided
that the SIFT Legislation will not apply to the Trust prior to 2011.
   
 Taxation of Unitholders Resident in Canada
   - 66 -




---



##### 



Taxation of Unitholders who are Non-Residents of Canada
     - 67 -




---



##### 



This Annual Information Form may not describe the United States tax consequences of the purchase,
holding or disposition of the Trust Units fully. Non-Resident Unitholders should obtain
independent tax advice as necessary.
 The SIFT Legislation will have a material and adverse impact on the Trust and its Unitholders.
Unitholders are urged to consult their own tax advisors having regard to their own particular
circumstances including the impact of the SIFT Legislation on the Trust and Unitholders. See  Risk
Factors  The SIFT Legislation has and will continue to materially and adversely affect the Trust,
the Unitholders and the value of the Trust Units .
 
 UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
 U.S. Internal Revenue
Code of 1986
  - 68 -




---



##### 



Classification of Pengrowth Energy Trust as a Partnership
   United States Federal Income Tax Considerations  Tax Consequences of Trust Unit
Ownership
  - 69 -




---



##### 



Possible Classification as a Corporation; PFIC Rules
   
 Consequences of Possible PFIC Classification
      - 70 -




---



##### 



Tax Consequences of Trust Unit Ownership
 Flow-through of Taxable Income
    Treatment of Distributions
  United States
Federal Income Considerations  Disposition of Trust Units
 Basis of Trust Units
  United
States Federal Income Tax Considerations  Disposition of Trust Units Recognition of Gain or
Loss
 Limitations on Deductibility of Losses
   - 71 -




---



##### 



Limitations on Interest Deductions
  Foreign Tax Credits
  Functional Currency
  
 Tax Treatment of Trust Operations
 Accounting Method and Taxable Year
  Depletion
  - 72 -




---



##### 



Depreciation
  Valuation of Our Properties
  Section 754 Election
   - 73 -




---



##### 



Disposition of Trust Units
 Recognition of Gain or Loss
    Allocations between Transferors and Transferees
  Notification Requirements
  - 74 -




---



##### 



Constructive Termination
  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
  United States Federal Income Tax Considerations 
Disposition of Trust Units  Recognition of Gain or Loss
 - 75 -




---



##### 



Uniformity of Trust Units
   
 Tax-Exempt Organizations
    
 Administrative Matters
 Trust Information Returns
  
 Reportable Transactions
  - 76 -




---



##### 



Foreign Partnership Reporting
  
 INDUSTRY CONDITIONS
 
 Government Regulation
  
 Pricing and Marketing  Oil
  
 Pricing and Marketing  Natural Gas
   - 77 -




---



##### 



Pricing and Marketing  Natural Gas Liquids
  
 Royalties
   Alberta
   2 3
   - 78 -




---



##### 



British Columbia
     Saskatchewan
  3 3
 3 3
 - 79 -




---



##### 



3
    Nova Scotia
   
 Environmental Regulation
  
 Climate Change
 Federal
 Regulatory Framework for Air
Emissions Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions
 - 80 -




---



##### 



Canadian Environmental Protection Act, 1999
  Alberta
 Climate Change and Emissions Management Act Specified Gas Reporting Regulation Specified Gas Emitters Regulation
 British Columbia
 Greenhouse Gas Reduction Targets
Act
 - 81 -




---



##### 



Saskatchewan
   
 RISK FACTORS
 If any of the following risks occur, our production, revenues and financial condition could be
materially harmed, with a resulting decrease in distributions on, and the market price of, our
Trust Units. As a result, the trading price of our Trust Units could decline, and you could lose
all or part of your investment. Additional risks are described under the heading Business Risks
in our Managements Discussion and Analysis for the year ended December 31, 2008.
 The SIFT Legislation has and will continue to materially and adversely affect Pengrowth, the
Unitholders and the value of the Trust Units.
  - 82 -




---



##### 



Low oil and natural gas prices could have a material adverse effect on results of operations and
financial condition, which, in turn, could negatively affect the amount of distributions to our
Unitholders.
  
    
    global energy policy, including the ability of OPEC to set and maintain production levels
for oil;
 
    
    geo-political conditions;
 
    
    worldwide economic conditions;
 
    
    weather conditions including weather-related disruptions to the North American natural gas
supply;
 
    
    the supply and price of foreign oil and natural gas;
 
    
    the level of consumer demand;
 
    
    the price and availability of alternative fuels;
 
    
    the proximity to, and capacity of, transportation facilities;
 
    
    the effect of worldwide energy conservation measures; and
 
    
    government regulation.
  Distributions may be reduced during periods of lower operating cash flow due to low commodity
prices, and in which Pengrowth makes capital expenditures using cash flow, which could also
negatively affect the market price of the Trust Units.
   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.
 - 83 -




---



##### 




    
    historical production from the area compared with production rates from similar producing
areas;
 
    
    the assumed effect of government regulation;
 
    
    assumptions about future commodity prices, exchange rates, production and development
costs, capital expenditures, abandonment costs, environmental liabilities, and applicable
royalty regimes;
 
    
    initial production rates;
 
    
    production decline rates;
 
    
    ultimate recovery of reserves;
 
    
    marketability of production; and
 
    
    other government levies that may be imposed over the producing life of reserves.
   Continued uncertainty in the credit markets may restrict the availability or increase the cost of
borrowing required for future development and acquisitions.
  In the normal course of our business, we have entered into contractual arrangements with third
parties which subject Pengrowth to the risk that such parties may default on their obligations.
 - 84 -




---



##### 



If Pengrowth 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 potential environmental claims and
liability which will be funded out of our cash flow and will reduce cash flow otherwise payable to
our Unitholders.
  We may be unable to successfully compete with other industry participants, which could negatively
affect the market price of the Trust Units and distributions to our Unitholders.
  Incorrect assessments of value at the time of acquisitions could adversely affect the value of our
Trust Units and distributions to our Unitholders.
  - 85 -




---



##### 



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.
  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 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.
   - 86 -




---



##### 



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.
   Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of
the Corporation and Esprit. If the oil and natural gas reserves associated with the resource
properties of the Corporation and Esprit are not supplemented through additional development or the
acquisition of oil and natural gas properties, the ability of Pengrowth to continue to generate
cash flow for distribution to Unitholders may be adversely affected.
  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.
  - 87 -




---



##### 



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.
  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.
   - 88 -




---



##### 




    
    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.
 Securities Act of 1933
 
    
    will enforce judgments of United States courts obtained in actions against Pengrowth or
such persons predicated upon the civil liability provisions of the United States federal
securities laws or the securities or blue sky laws of any state within the United States; or
 
    
    will enforce, in original actions, liabilities against Pengrowth or such persons predicated
upon the United States federal securities laws or any such state securities or blue sky laws.
 Your rights as a Unitholder differ from the rights associated with other types of investments and
we cannot assure you that the distributions you receive over the life of your investment will meet
or exceed your initial capital investment.
  - 89 -




---



##### 



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.
    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
 - 90 -




---



##### 



amended (the Code) provides that publicly-traded partnerships such as the Trust will, as a
general rule, be taxed as corporations. We will not be treated as a corporation for U.S.
federal income tax purposes only if 90 percent or more of its gross income consists of
qualifying income. Although we expect to satisfy the 90 percent requirement at all times,
if we fail to satisfy this requirement, we will be treated as a foreign corporation. Such
conversion will be taxable unless a certain filing is made.
 
    
    We have the right to elect under applicable United States Treasury Regulations to be
treated as a corporation for United States federal income tax purposes, if such election were
determined to be beneficial. As circumstances, including, without limitation, applicable tax
laws and tax treaties, change, we will continue to evaluate if such an election would be
beneficial to Pengrowth and its Unitholders including, without limitation, as a result of any
potential tax efficiency in the payment of distributions to United States holders. If we
elect to be treated as a corporation for United States federal income tax purposes, we would
be treated as if we transferred all of our assets (subject to liabilities) to a newly formed
corporation in return for stock in that corporation, and then distributed that stock to our
owners in liquidation of their interests in us. Such deemed transfer and liquidation would
likely be taxable to United States holders.
 
    
    If we were treated as a foreign corporation, we could be a passive foreign investment
company or PFIC. If we were considered a PFIC, United States holders of Trust Units could
be subject to substantially increased United States tax liability, including an interest
charge upon the sale or other disposition of the United States holders Trust Units, or upon
the receipt of excess distributions from the Trust. Certain elections may be available to a
United States holder if we were classified as a PFIC to alleviate these adverse tax
consequences.
 
    
    We treat the Royalty between the Trust and the Corporation as a Royalty Interest for all
legal purposes, including United States federal income tax purposes. The Royalty Indenture in
some respects differs from more conventional net profits interests as to which the courts
and the IRS have ruled regarding the federal income tax treatment as a royalty, and as a
result the propriety of such treatment is not free from doubt. It is possible that the IRS
could contend, for example, that we should be considered to have a Working Interest in the
properties of the Corporation. If the IRS were successful in making such a contention, the
United States federal income tax consequences to United States holders could be different,
perhaps materially worse, than indicated in the discussion herein, which generally assumes
that the Royalty Indenture will be respected as a royalty.
 
    
    Gain or loss will be recognized on a sale of Trust Units equal to the difference between
the amount realized and the United States holders tax basis for the Trust Units sold. Gain
or loss recognized by a United States holder on the sale or exchange of Trust Units will
generally be taxable as capital gain or loss, and will be long-term capital gain or loss if
such United States holders holding period of the Trust Units exceeds one year. A portion of
any amount realized on a sale or exchange of Trust Units (which portion could be substantial)
will be separately computed and taxed as ordinary income under Section 751 of the Code to the
extent attributable to the recapture of depletion or depreciation deductions. Ordinary income
attributable to depletion deductions and depreciation recapture could exceed net taxable gain
realized upon the sale of the Trust Units and may be recognized even if there is a net taxable
loss realized on the sale of the Trust Units. Thus, a United States holder may recognize both
ordinary income and a capital loss upon a taxable disposition of Trust Units.
 
    
    Because we cannot match transferors and transferees of Trust Units, we must maintain
uniformity of the economic and tax characteristics of the Trust Units to a purchaser of these
Trust Units. In the absence of such uniformity, the Trust may be unable to comply completely
with a number of federal income tax requirements. A lack of uniformity, however, can result
from a literal application of some Treasury regulations. If any non-uniformity was required
by the IRS, it could have a negative impact on the value of the Trust Units.
 - 91 -




---



##### 




    
    The Trust may not be an appropriate investment for certain types of entities. For example,
there is a risk that some of the Trusts income could be unrelated business taxable income
with respect to tax-exempt organizations. Prospective purchasers of Trust Units that are
tax-exempt organizations are encouraged to consult their tax advisors regarding investments in
Trust Units.
 
    
    The present U.S. federal income tax treatment of publicly traded partnerships, including
us, or an investment in our Trust Units may be modified by administrative, legislative or
judicial interpretation at any time. For example, in response to certain recent developments,
members of Congress are considering substantive changes to the existing U.S. tax laws that
would affect certain publicly traded partnerships. Any modification to the U.S. federal
income tax laws and interpretations thereof may or may not be applied retroactively. Although
the currently proposed legislation would not appear to affect our tax treatment, we are unable
to predict whether any of these changes, or other proposals, will ultimately be enacted. Any
such changes could negatively impact the value of an investment in our Trust Units.
 
    
    We prorate our items of income, gain, loss and deduction between transferors and
transferees of our Trust Units each month based upon the ownership of our Trust Units on the
first day of each month, instead of on the basis of the date a particular Trust Unit is
transferred. The use of the proration method may not be permitted under existing Treasury
Regulations, and, accordingly, our counsel is unable to opine as to the validity of this
method. If the IRS were to challenge this method or new Treasury Regulations were issued, we
may be required to change the allocation of items of income, gain, loss and deduction among
our Unitholders.
 
    
    On September 21, 2007, Canada and the United States signed the Protocol to the Canada-U.S.
Convention. The Protocol entered into force on December 15, 2008. The Protocol contains new
Article IV(7)(b), a treaty benefit denial rule, which would increase the Canadian withholding
tax on Pengrowths distributions (which for the purposes of this paragraph includes deemed
dividends pursuant to the SIFT Legislation) to Non-Resident Unitholders who are residents of
the U.S. for the purposes of the Canada-U.S. Convention. Article IV(7)(b) of the Protocol
will not come into force until January 1, 2010. Article IV(7)(b) of the Protocol generally
denies benefits under the Canada-U.S. Convention in circumstances where (i) a Unitholder who
is a resident of the U.S. for the purposes of the Canada-U.S. Convention receives an amount,
such as a distribution, from an entity that is a resident of Canada, such as Pengrowth,
(ii) Pengrowth is treated as a fiscally transparent entity for U.S. federal income tax
purposes, which is the case inasmuch as Pengrowth is treated as a partnership for U.S. federal
income tax purposes, and (iii) the tax treatment of the amount (or distribution) received by
the U.S. Resident Unitholder would, for U.S. federal income tax purposes, be different if
Pengrowth were not treated as fiscally transparent for U.S. federal income tax purposes. The
effect of Article IV(7)(b) of the Protocol is that the Canadian withholding tax rate on
distributions of income would be 25 percent instead of 15 percent or such lower rate otherwise
available under the Canada-U.S. Convention. Returns of capital would still be subject to a
15 percent Canadian withholding tax and such rate is not modified by the Protocol. The
Protocol also contains measures which, generally speaking, are designed to limit the benefits
under the Canada-U.S. Convention to treaty shopping transactions or arrangements.
 Distributions to our Unitholders may be reduced during periods in which Pengrowth makes capital
expenditures using cash flow.
  - 92 -




---



##### 



Changes in government regulations that affect the crude oil and natural gas industry could
adversely affect Pengrowth and reduce our distributions to our 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.
  Terrorist attacks and the threat of terrorist attacks may have an adverse impact on the
Corporation.
  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;
 - 93 -




---



##### 




    
    recovery by the operator of expenses incurred in the operation of the properties; or
 
    
    the establishment by the operator of reserves for these expenses.
  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.
  - 94 -




---



##### 



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)
    
    
    
    
    
    (U.S. $ per Trust Unit)2008January
    
    
    18.15
    
    
    
    14.16
    
    
    
    17.67
    
    
    
    11,122,230
    
    
    
    18.22
    
    
    
    13.67
    
    
    
    17.48
    
    
    
    5,637,800February
    
    
    18.85
    
    
    
    17.10
    
    
    
    18.35
    
    
    
    8,055,594
    
    
    
    19.22
    
    
    
    16.93
    
    
    
    18.66
    
    
    
    3,611,700March
    
    
    19.82
    
    
    
    18.07
    
    
    
    19.67
    
    
    
    11,576,037
    
    
    
    19.47
    
    
    
    17.61
    
    
    
    19.10
    
    
    
    5,043,500April
    
    
    21.02
    
    
    
    19.17
    
    
    
    19.75
    
    
    
    9,122,242
    
    
    
    20.79
    
    
    
    18.86
    
    
    
    19.71
    
    
    
    6,104,400May
    
    
    21.56
    
    
    
    19.47
    
    
    
    20.34
    
    
    
    9,432,421
    
    
    
    21.90
    
    
    
    19.04
    
    
    
    20.53
    
    
    
    7,693,300June
    
    
    21.16
    
    
    
    19.90
    
    
    
    20.50
    
    
    
    9,449,203
    
    
    
    20.89
    
    
    
    19.60
    
    
    
    20.11
    
    
    
    5,626,900July
    
    
    20.55
    
    
    
    17.40
    
    
    
    17.70
    
    
    
    11,964,173
    
    
    
    20.20
    
    
    
    17.04
    
    
    
    17.31
    
    
    
    10,624,448August
    
    
    18.89
    
    
    
    17.10
    
    
    
    18.85
    
    
    
    9,860,089
    
    
    
    18.09
    
    
    
    16.20
    
    
    
    17.75
    
    
    
    7,137,570September
    
    
    18.50
    
    
    
    14.73
    
    
    
    15.99
    
    
    
    9,961,463
    
    
    
    17.32
    
    
    
    14.16
    
    
    
    14.94
    
    
    
    9,052,581October
    
    
    15.98
    
    
    
    8.55
    
    
    
    13.01
    
    
    
    18,451,866
    
    
    
    15.00
    
    
    
    7.50
    
    
    
    11.21
    
    
    
    22,021,164November
    
    
    13.53
    
    
    
    9.75
    
    
    
    11.24
    
    
    
    7,901,229
    
    
    
    11.65
    
    
    
    7.56
    
    
    
    8.97
    
    
    
    9,406,631December
    
    
    10.95
    
    
    
    8.82
    
    
    
    9.35
    
    
    
    8,681,986
    
    
    
    8.62
    
    
    
    6.84
    
    
    
    7.62
    
    
    
    10,348,796
  Toronto Stock ExchangeDebenture Price RangeHigh
    
    Low
    
    Close
    
    Volume(Canadian $ per Debenture)2008January
    
    
    100.50
    
    
    
    98.50
    
    
    
    100.00
    
    
    
    841,000February
    
    
    102.25
    
    
    
    99.51
    
    
    
    100.00
    
    
    
    677,000March
    
    
    102.00
    
    
    
    100.00
    
    
    
    100.50
    
    
    
    671,000April
    
    
    102.00
    
    
    
    100.01
    
    
    
    102.00
    
    
    
    485,000May
    
    
    101.25
    
    
    
    101.25
    
    
    
    101.25
    
    
    
    349,000June
    
    
    102.00
    
    
    
    100.55
    
    
    
    100.55
    
    
    
    358,000July
    
    
    101.50
    
    
    
    100.55
    
    
    
    100.56
    
    
    
    524,000August
    
    
    102.00
    
    
    
    100.01
    
    
    
    101.00
    
    
    
    451,000September
    
    
    101.50
    
    
    
    99.00
    
    
    
    101.00
    
    
    
    814,000October
    
    
    100.01
    
    
    
    91.60
    
    
    
    91.60
    
    
    
    1,277,000November
    
    
    98.70
    
    
    
    90.50
    
    
    
    91.00
    
    
    
    621,000December
    
    
    97.23
    
    
    
    85.00
    
    
    
    91.00
    
    
    
    372,000
 - 95 -




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##### 



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 (since 2004)
    
    Vice President, Engineering
Pengrowth Management LimitedRobert M. Nicolay
Alberta, Canada
    
    Vice President, Business Development
(since 2007)
    
    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
  - 96 -




---



##### 



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
    
    
    7,495,095Alberta, 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
    
    
    4,273Alberta, Canada
    
    
    
    Petro Andina Resources Inc.(energy company)Michael 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)
    
    Corporate Director
    
    
    13,370Alberta, CanadaNicholas C.H. Villiers
    
    Director (since 2007)
    
    Business Consultant
    
    
    London, EnglandJohn B. Zaozirny(3)(4)
    
    Vice Chairman and Lead Independent
    
    Vice Chair
    
    
    35,100Alberta, Canada
    
    Director (Director since 1988)
    
    Canaccord Capital CorporationGordon M. Anderson
    
    Vice President (since 2001)
    
    Vice President, Financial Services
    
    
    29,167Alberta, 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
    
    
    20,483Alberta, Canada
    
    (since March 1, 2006)
    
    Controller PengrowthController (since 2005)
    
    CorporationJames E.A. Causgrove
    
    Vice President, Production and
    
    Vice President, Production
    
    
    41,789Alberta, Canada
    
    Operations (since 2005)
    
    and OperationsPengrowth CorporationWilliam G. Christensen
    
    Vice President, Strategic Planning and
    
    Vice President, Strategic
    
    
    26,927Alberta, Canada
    
    Reservoir Exploitation (since 2005)
    
    Planning and ReservoirExploitationPengrowth CorporationJames M. Donihee
    
    Vice-President and Chief of Staff
    
    Vice-President and Chief of
    
    
    12,510Alberta, Canada
    
    (since 2007)
    
    StaffPengrowth CorporationCharles V. Selby
    
    Vice President and Corporate Secretary
    
    President
    
    
    161,071Alberta, Canada
    
    (since 2005)
    
    Selby ProfessionalCorporate Secretary (since 1993)
    
    Corporation (corporatefinance and legal advisingcompany)Larry B. Strong
    
    Vice President, Geosciences (since 2005)
    
    Vice President, Geosciences
    
    
    23,763Alberta, Canada
    
    
    
    Pengrowth Corporation
 - 97 -




---



##### 



Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)Christopher G. Webster
    
    Chief Financial Officer (since 2005)
    
    Chief Financial Officer
    
    
    66,144Alberta, Canada
    
    Treasurer (2000 - 2005)
    
    Pengrowth Corporation
 Notes:
 
 (1)
    
    As at December 31, 2008 and excluding Trust Units issuable upon the exercise of outstanding
options, rights or deferred entitlement units.(2)
    
    Member of Reserves, Operations and Environmental, Health and Safety Committee.(3)
    
    Member of Corporate Governance Committee.(4)
    
    Member of Compensation Committee.(5)
    
    Member of Audit Committee.    
 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(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.
 - 98 -




---



##### 



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
 Name
    
    Independent
    
    Financially 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, and until October 31,
2008 was a member of the board
of Fording Inc. and served as a
Trustee for Fording Canadian
Coal Trust. He was formerly
President of Rio Algom Limited
and prior to that Chief
Financial Officer of Rio Algom
and Falconbridge Limited. Mr.
Parrett is a chartered
accountant and holds a Bachelor
of Arts in Economics from York
University.A. Terence Poole
    
    Yes
    
    Yes
    
    Mr. Poole brings extensive
senior financial management,
accounting, capital and debt
market experience to Pengrowth.
He retired from Nova Chemicals
Corporation in 2006 where he had
held various senior management
positions including Executive
Vice-President, Corporate
Strategy and Development. Mr.
Poole currently serves on the
board of directors for Methanex
Corporation. Mr. Poole received
a Bachelor of Commerce degree
from Dalhousie University and
holds a Chartered Accountant
designation.
 - 99 -




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##### 



Principal Accountant Fees and Services
  2008
    
    2007Audit Fees
    
    
    1,037
    
    
    
    1,393Audit Related Fees
    
    
    
    
    
    
    Tax Fees
    
    
    98
    
    
    
    163All Other Fees
    
    
    
    
    
    
    Total
    
    
    1,135
    
    
    
    1,556
 Audit Fees
  Audit-Related Fees
  Tax Fees
  
 Pre-approval Policies and Procedures
  de minimis
 
 CONFLICTS OF INTEREST
  - 100 -




---



##### 




    
    the issuance of additional Trust Units;
 
    
    material acquisitions and dispositions of properties;
 
    
    material capital expenditures;
 
    
    borrowing; and
 
    
    the payment of distributable cash.
 Protection of Minority Security Holders in Special Transactions.
  - 101 -




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##### 



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 Note Purchase Agreement dated August 21, 2008 concerning the 2008 Senior Notes;
 - 102 -




---



##### 



7.
    
    the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes;8.
    
    the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes;9.
    
    the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes;10.
    
    the Debenture Indenture;11.
    
    the first supplemental trust indenture relating to the Debentures dated October 2, 2006; 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
   - 103 -




---



##### 



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
 Website:
    
    www.pengrowth.comE-mail:
    
    investorrelations@pengrowth.com
 - 104 -




---



##### 



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, 2008. The reserves data are
estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2008, estimated using forecast prices and costs.2.
    
    The reserves data are the responsibility of the Companys management. Our responsibility is
to express an opinion on the reserves data based on our evaluation.We carried out our evaluation in accordance with standards set out in the Canadian Oil and
Gas Evaluation Handbook (the COGE Handbook) prepared jointly by the Society of Petroleum
Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy &
Petroleum (Petroleum Society).3.
    
    Those standards require that we plan and perform an evaluation to obtain reasonable assurance
as to whether the reserves data are free of material misstatement. An evaluation also
includes assessing whether the reserves data are in accordance with principles and definitions
presented in the COGE Handbook.4.
    
    The following table sets forth the estimated future net revenue (before deduction of income
taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs
and calculated using a discount rate of 10 percent, included in the reserves data of the
Company evaluated by us for the year ended December 31, 2008, and identifies the respective
portions thereof that we have audited, evaluated and reviewed and reported on to the Companys board of directors:
 Description and
    
    
    
    
    
    Net Present Value of Future Net RevenuePreparation Date
    
    Location of Reserves
    
    (before income taxes, 10 percent discount rate -Independent Qualified
    
    of Evaluation
    
    (Country or Foreign
    
    $MM)Reserves Evaluator
    
    Report
    
    Geographic Area)
    
    Audited
    
    Evaluated
    
    Reviewed
    
    TotalGLJ Petroleum
Consultants
    
    January 15, 2009
    
    Canada
    
    
    
    
    
    $
    5,582
    
    
    
    
    
    
    $
    5,582
 5.
    
    In our opinion, the reserves data respectively evaluated by us have, in all material
respects, been determined and are in accordance with the COGE Handbook. We express no opinion
on the reserves data that we reviewed but did not audit or evaluate.6.
    
    We have no responsibility to update our reports referred to in paragraph 4 for events and
circumstances occurring after their respective preparation dates.




---



##### 



7.
    
    Because the reserves data are based on judgments regarding future events, actual results will
vary and the variations may be material. However, any variations should be consistent with
the fact that reserves are categorized according to the probability of their recovery.
   (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
RESERVES DATA AND OTHER INFORMATION
    (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) Wayne FooWayne FooDirectorPengrowth Corporation(signed) D. Michael G. StewartD. Michael G. StewartDirectorPengrowth Corporation
  - 2 -




---



##### 



APPENDIX C
 Audit Committee Terms of Reference
  C-1




---



##### 



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




---



##### 



- 2 - 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 annually in the Trusts annual information circular and at least every three years
in accordance with the regulations of the United States Securities and Exchange Commission.
 2.
    
    Prior to filing or public distribution, review, discuss with management and the internal and
external auditors and recommend to the Board for approval, Pengrowths audited annual
financial statements, annual earnings press releases, annual information form, all statements
including the related managements discussion and analysis required in prospectuses and other
offering memoranda, financial statements required by regulatory authorities, all prospectuses
and all documents which may be incorporated by reference into a prospectus, including without
limitation, the annual information circular. Approve, on behalf of the Board, Pengrowths
interim financial statements and related managements discussion and analysis and interim
earnings




---



##### 



- 3 - 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 NI
52-110. If proxies are solicited for the election of directors of the Corporation, the Audit
Committee shall be responsible for ensuring that Pengrowths information circular includes a
cross-reference to the sections in Pengrowths annual information form that contain the
information required by Form 52-110F1.
 External Auditors
 1.
    
    The Audit Committee shall advise the external auditors of their accountability to the Audit
Committee and the Board as representatives of the unitholders of the Trust to whom the
external auditors are ultimately responsible. The external auditors shall report directly to
the Audit Committee. The Audit Committee is directly responsible for overseeing the work of
the external auditors, shall review at least annually the independence and performance of the
external auditors and shall annually recommend to the Board the appointment of the external
auditors or approve any discharge of auditors when circumstances warrant. The Audit Committee
shall, on an annual basis, obtain and review a report by the external auditor describing: (i)
the external auditors internal quality-control procedures; (ii) any material issues raised by
the most recent internal quality-control review, or peer review, of the external auditors, or
by any inquiry or investigation by governmental or professional authorities, within the
preceding five years, respecting one or more independent audits carried out by the external
auditors, and any steps taken to deal with any such issues; and (iii) all relationships
between the independent auditor and Pengrowth.
 2.
    
    Approve the fees and other compensation to be paid to the external auditors.
 3.
    
    Pre-approve all services to be provided to Pengrowth or its subsidiary entities by
Pengrowths external auditors and all related terms of engagement.
 Other Audit Committee Responsibilities
 1.
    
    Establish procedures for: (i) the receipt, retention and treatment of complaints received by
Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii)
the confidential and anonymous submission by employees of Pengrowth of concerns regarding
questionable accounting or auditing matters.
 2.
    
    Review and approve Pengrowths hiring policies regarding partners, employees and former
partners and employees of the present and former external auditors of Pengrowth.
 Discretionary Duties




---



##### 



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




---



##### 



- 5 - 6.
    
    Ensure that the external auditors are participants in good standing with the Canadian Public
Accountability Board (CPAB) and participate in the oversight programs established by the
CPAB from time to time and that the external auditors have complied with any restrictions or
sanctions imposed by the CPAB as of the date of the applicable auditors report relating to
Pengrowths annual audited financial statements.
 7.
    
    Monitor compliance with the lead auditor rotation requirements of Regulation S-X.
 Other Audit Committee Responsibilities
 1.
    
    On at least an annual basis, review with Pengrowths legal counsel any legal matters that
could have a significant impact on the organizations financial statements, Pengrowths
compliance with applicable laws and regulations, and inquiries received from regulators or
governmental agencies.
 2.
    
    Annually prepare a report to unitholders as required by the United States Securities and
Exchange Commission; the report should be included in Pengrowths annual information circular.
 3.
    
    Ensure due compliance with each obligation to certify, on an annual and interim basis,
internal control over financial reporting and disclosure controls and procedures in accordance
with applicable securities laws and regulations.
 4.
    
    Review all exceptions to established policies, procedures and internal controls of Pengrowth,
which have been approved by any two officers of the Corporation.
 5.
    
    Perform any other activities consistent with this Charter, the Trust Indenture, the
Corporations by-laws, and other governing law as the Audit Committee or the Board deems
necessary or appropriate.
 6.
    
    Maintain minutes of meetings and periodically report to the Board on significant results of
the foregoing activities.
 Communication, Authority to Engage Advisors and Expenses




---



##### 



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




---



##### 



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




---



##### 



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); or
 B.
    
    Be an affiliated person of the issuer or any subsidiary
thereof.
 e.
    
    Definitions. Unless the context otherwise requires, all terms used in this section have the
same meaning as in the Act. In addition, unless the context otherwise requires, the following
definitions apply for purposes of this section:
 1.
 i.
    
    The 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.
 ii.
 A.
    
    A person will be deemed not to be in control of a specified
person for purposes of this section if the person:
 1.
    
    Is not the beneficial owner, directly or
indirectly, of more than 10% of any class of voting equity securities
of the specified person; and
 2.
    
    Is not an executive officer of the specified
person.
 B.
    
    Paragraph (e)(1)(ii)(A) of this section only creates a safe
harbor position that a person does not control a specified person. The
existence of the safe harbor does not create a presumption in any way that a
person exceeding the ownership




---



##### 



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




---



##### 



C-1 Schedule C
 Excerpts from Rule 303A.00 of the New York Stock Exchange
 303A.02 Independence Tests
  (a)
    
    No director qualifies as independent unless the board of directors
affirmatively determines that the director has no material relationship with the listed
company (either directly or as a partner, shareholder or officer of an organization
that has a relationship with the company). Companies must identify which directors are
independent and disclose the basis for that determination.
 (b)
    
    In addition, a director is not independent if:
 (i)
    
    The director is, or has been within the last three years, an
employee of the listed company, or an immediate family member is, or has been
within the last three years, an executive officer, of the listed company.
 (ii)
    
    The director has received, or has an immediate family member
who has received, during any twelve-month period within the last three years,
more than $120,000 in direct compensation from the listed company, other than
director and committee fees and pension or other forms of deferred compensation
for prior service (provided such compensation is not contingent in any way on
continued service).
 (iii)
    
    (A) The director is a current partner or employee of a firm
that is the companys internal or external auditor; (B) the director has an
immediate family member who is a current partner of such a firm; (C) the
director has an immediate family member who is a current employee of such a
firm and personally works on the listed companys audit; or (D) the director or
an immediate family member was within the last three years a partner or
employee of such a firm and personally worked on the listed companys audit
within that time.
 (iv)
    
    The director or an immediate family member is, or has been
within the last three years, employed as an executive officer of another
company where any of the listed companys present executive officers at the
same time serves or served on that companys compensation committee.
 (v)
    
    The director is a current employee, or an immediate family
member is a current executive officer, of a company that has made payments to,
or received payments from, the listed company for property or services in an
amount which, in any of the last three fiscal years, exceeds the greater of $1
million, or 2% of such other companys consolidated gross revenues.
 General Commentary to Section 303A.02(b):




---



##### 



C-2  The term officer shall mean an issuers president, principal financial officer, principal
accounting officer (or, if there is no such accounting officer, the controller), any
vice-president of the issuer in charge of a principal business unit, division or function
(such as sales, administration or finance), any other officer who performs a policy-making
function, or any other person who performs similar policy-making functions for the issuer.
Officers of the issuers parent(s) or subsidiaries shall be deemed officers of the issuer if
they perform such policy-making functions for the issuer. In addition, when the issuer is a
limited partnership, officers or employees of the general partner(s) who perform
policy-making functions for the limited partnership are deemed officers of the limited
partnership. When the issuer is a trust, officers or employees of the trustee(s) who
perform policy-making functions for the trust are deemed officers of the trust.




---



##### 



APPENDIX B
 MANAGEMENTS DISCUSSION AND ANALYSIS




---



##### 








---



##### 



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




---



##### 



Three Months ended December 31
    
    
    
    Twelve Months ended December 312008
    
    
    
    2007
    
    
    % Change
    
    
    
    2008
    
    
    
    2007
    
    
    % ChangeAVERAGE DAILY
PRODUCTIONCrude oil (barrels)
    
    
    
    24,236
    
    
    
    
    25,892
    
    
    
    (6
    )
    
    
    
    24,416
    
    
    
    
    26,327
    
    
    
    (7
    )Heavy oil (barrels)
    
    
    
    8,217
    
    
    
    
    7,434
    
    
    
    11
    
    
    
    
    8,122
    
    
    
    
    7,168
    
    
    
    13Natural gas (mcf)
    
    
    
    241,709
    
    
    
    
    250,117
    
    
    
    (3
    )
    
    
    
    240,825
    
    
    
    
    266,980
    
    
    
    (10
    )Natural gas liquids (barrels)
    
    
    
    10,634
    
    
    
    
    9,319
    
    
    
    14
    
    
    
    
    9,315
    
    
    
    
    9,409
    
    
    
    (1
    )Total production (boe)
    
    
    
    83,373
    
    
    
    
    84,331
    
    
    
    (1
    )
    
    
    
    81,991
    
    
    
    
    87,401
    
    
    
    (6
    )TOTAL PRODUCTION (mboe)
    
    
    
    7,670
    
    
    
    
    7,758
    
    
    
    (1
    )
    
    
    
    30,009
    
    
    
    
    31,901
    
    
    
    (6
    )PRODUCTION PROFILECrude oil
    
    
    
    29
    %
    
    
    
    31
    %
    
    
    
    
    
    
    
    30
    %
    
    
    
    30
    %Heavy oil
    
    
    
    10
    %
    
    
    
    9
    %
    
    
    
    
    
    
    
    10
    %
    
    
    
    8
    %Natural gas
    
    
    
    48
    %
    
    
    
    49
    %
    
    
    
    
    
    
    
    49
    %
    
    
    
    51
    %Natural gas liquids
    
    
    
    13
    %
    
    
    
    11
    %
    
    
    
    
    
    
    
    11
    %
    
    
    
    11
    %AVERAGE REALIZED PRICES(after commodity
risk management)Crude oil (per barrel)
    
    
    $
    65.87
    
    
    
    $
    73.69
    
    
    
    (11
    )
    
    
    $
    77.78
    
    
    
    $
    71.88
    
    
    
    8Heavy oil (per barrel)
    
    
    $
    42.20
    
    
    
    $
    45.47
    
    
    
    (7
    )
    
    
    $
    75.77
    
    
    
    $
    44.53
    
    
    
    70Natural gas (per mcf)
    
    
    $
    7.40
    
    
    
    $
    6.90
    
    
    
    7
    
    
    
    $
    8.19
    
    
    
    $
    7.29
    
    
    
    12Natural gas liquids (per barrel)
    
    
    $
    43.87
    
    
    
    $
    67.64
    
    
    
    (35
    )
    
    
    $
    70.67
    
    
    
    $
    58.86
    
    
    
    20Average realized price per boe
    
    
    $
    50.34
    
    
    
    $
    54.58
    
    
    
    (8
    )
    
    
    $
    62.76
    
    
    
    $
    53.90
    
    
    
    16PROVED PLUS
PROBABLE RESERVESCrude oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    121,289
    
    
    
    
    124,188
    
    
    
    (2
    )Heavy oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    27,728
    
    
    
    
    21,792
    
    
    
    27Natural gas (bcf)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    852
    
    
    
    
    870
    
    
    
    (2
    )Natural gas liquids (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    32,442
    
    
    
    
    28,994
    
    
    
    12Total oil equivalent (mboe)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    323,463
    
    
    
    
    319,921
    
    
    
    1SUMMARY OF TRUST
UNIT TRADINGNYSE  PGH ($U.S.)High
    
    
    $
    15.00
    
    
    
    $
    19.21
    
    
    
    
    
    
    
    $
    21.90
    
    
    
    $
    19.85Low
    
    
    $
    6.84
    
    
    
    $
    17.30
    
    
    
    
    
    
    
    $
    6.84
    
    
    
    $
    15.82Close
    
    
    $
    7.62
    
    
    
    $
    17.77
    
    
    
    
    
    
    
    $
    7.62
    
    
    
    $
    17.77TSX  PGF.UN ($Cdn)High
    
    
    $
    15.98
    
    
    
    $
    18.68
    
    
    
    
    
    
    
    $
    21.56
    
    
    
    $
    21.04Low
    
    
    $
    8.55
    
    
    
    $
    17.00
    
    
    
    
    
    
    
    $
    8.55
    
    
    
    $
    16.92Close
    
    
    $
    9.35
    
    
    
    $
    17.62
    
    
    
    
    
    
    
    $
    9.35
    
    
    
    $
    17.62




---



##### 








---



##### 








---



##### 



Three months ended
    
    
    Twelve months endedDec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Production (boe/d)
    
    
    
    83,373
    
    
    
    
    80,981
    
    
    
    84,331
    
    
    
    
    81,991
    
    
    
    
    87,401Netback ($/boe)
    
    
    
    26.23
    
    
    
    
    37.48
    
    
    
    29.56
    
    
    
    
    34.78
    
    
    
    
    30.40Cash flows from 
operating activities ($000s)
    
    
    
    154,807
    
    
    
    
    273,597
    
    
    
    196,325
    
    
    
    
    912,516
    
    
    
    
    800,344Net income (loss) ($000s)
    
    
    
    148,688
    
    
    
    
    422,395
    
    
    
    (3,665
    )
    
    
    
    395,850
    
    
    
    
    359,652Included in net income:Unrealized gain (loss) on commodity
risk management ($000s)
    
    
    
    292,249
    
    
    
    
    476,005
    
    
    
    (136,606
    )
    
    
    
    249,899
    
    
    
    
    (122,307
    )Unrealized foreign exchange
gain (loss) on foreign denominated
debt ($000s)
    
    
    
    (127,207
    )
    
    
    
    (24,999
    )
    
    
    5,665
    
    
    
    
    (172,626
    )
    
    
    
    73,940
 
 (1)
    
    Restated to conform to presentation adapted in current period.




---



##### 




    
    Oil and gas sales increased 11 percent, to $1.9 billion in 2008 reflective of higher average
realized prices reached through the first three quarters of 2008. In the fourth quarter, oil and
gas sales were $392.2 million, a decrease of 24 percent from the third quarter and an eight
percent decrease from the fourth quarter of 2007.
    
    Cash flow from operating activities increased 14 percent to $912.5 million in 2008 reflective of
higher realized prices compared to 2007. Fourth quarter cash flow from operating activities was
$154.8 million representing a 43 percent decrease from the third quarter and a 21 percent
decrease from the fourth quarter of 2007.
    
    Daily production for 2008 averaged 81,991 boe per day, consistent with 2008 guidance. The six
percent decrease in the current year compared to 2007 full year average production of 87,401 boe
per day, is primarily due to lower volumes as a result of divested properties and operational
shutdowns offset by successful development activity and additional volumes from the acquired
properties from Accrete Energy Inc. (Accrete) completed at the end of the third quarter.
Fourth quarter production averaged 83,373 boe per day, relatively unchanged from the same
quarter in 2007; additional volumes from the Accrete properties were partially offset by an
unscheduled maintenance shutdown.
    
    Pengrowths 2008 development capital spending, excluding acquisitions totaled $388.3 million
($283.1 million in 2007), including the Lindbergh project, resulting in reserve replacement of
80 percent for Total Proved plus Probable Reserves excluding acquisitions, and 112 percent
including acquisitions.
    
    Distributions declared to unitholders in 2008 were $651.0 million, or $2.59 per trust unit.
Distributions declared to unitholders totalled 71 percent of cash flow from operating
activities and 93 percent for the fourth quarter of 2008. Due to higher capital spending in
2008, and the desire to curtail debt, an increased percentage of cash flow from operations
was withheld to fund the capital program.
    
    Net income increased ten percent to $395.8 million in 2008 compared to $359.7 million in 2007.
The increase was due to higher realized prices through the first three quarters of 2008, partly
offset by higher royalties, operating expenses and general and administrative costs. In addition
to these items, net income was effected by certain non-cash items including a $249.9 million
unrealized gain on commodity risk management contracts, and a $71.9 million future tax
reduction, partly offset by a $172.6 million unrealized foreign exchange loss on foreign
denominated debt.
    
    During 2008, Pengrowths average realized price was $62.76 per boe (after commodity risk
management) compared to an average price of $53.90 per boe in 2007. Prices for liquids and
natural gas were higher year over year reflective of the unprecedented benchmark prices
through the third quarter of 2008.
    
    During the fourth quarter of 2008, Pengrowths average realized price was $50.34 per boe (after
commodity risk management) compared to an average realization of $67.71 per boe in the third
quarter of 2008 and $54.58 in the fourth quarter of 2007. Compared to the other periods, prices
for liquids were lower in the fourth quarter of 2008 while natural gas enjoyed a modest
increase.
    
    During 2008, Pengrowth closed a U.S. $265 million and a Cdn $15 million private placement of
senior unsecured notes with interest rates of 6.98 percent and 6.61 percent respectively, due in
2018.
    
    Operating netbacks (after commodity risk management) increased 14 percent in 2008 to $34.78 from
2007, driven by higher realized prices partially offset by higher royalties and operating costs.
Fourth quarter 2008 operating netbacks were $26.23 per boe, a decrease of 30 percent from the
third quarter and a 11 percent decrease from the fourth quarter of 2007.




---



##### 




    
    Pengrowths finding and development costs for 2008 equaled $16.27 per boe on a proved plus
probable basis. Including acquisitions, finding and development costs were $15.47 per boe on a
proved plus probable basis. During the year, Pengrowth participated in 507 gross (217 net)
wells with a 96 percent success rate.
    
    During the fourth quarter of 2008, Pengrowth completed the divestiture of certain non-core,
non-producing lands in the Dawson area in British Columbia. Proceeds of the disposition were
approximately $27 million, with $21 million received in 2008.
    
    On September 30, 2008, Pengrowth acquired properties in the Harmattan area from Accrete Energy
Inc. (Accrete). All of Accretes oil and gas properties except those in the Harmattan area
were transferred to Argosy Energy Inc., an unrelated company.
    
    During the third quarter of 2008, Pengrowth completed the acquisition of additional working
interest in the Harmattan area from Fairmount Energy Inc. for $12.0 million. Also in the third
quarter of 2008, Pengrowth purchased additional working interests in both the Carson Creek and
Garrington areas.
    
    During the second quarter of 2008, Pengrowth completed property acquisitions of approximately
$16.9 million, which included exercising a right of first refusal in Three Hills and
purchasing additional working interest at Swan Hills.
   PRODUCTION
   DAILY PRODUCTION
 Three months ended
    
    
    
    Twelve months endedDec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Light crude oil (bbls)
    
    
    
    24,236
    
    
    
    
    23,286
    
    
    
    25,892
    
    
    
    
    24,416
    
    
    
    
    26,327Heavy oil (bbls)
    
    
    
    8,217
    
    
    
    
    8,287
    
    
    
    7,434
    
    
    
    
    8,122
    
    
    
    
    7,168Natural gas (mcfs)
    
    
    
    241,709
    
    
    
    
    246,287
    
    
    
    250,117
    
    
    
    
    240,825
    
    
    
    
    266,980Natural gas liquids (bbls)
    
    
    
    10,634
    
    
    
    
    8,361
    
    
    
    9,319
    
    
    
    
    9,315
    
    
    
    
    9,409Total boe per day
    
    
    
    83,373
    
    
    
    
    80,981
    
    
    
    84,331
    
    
    
    
    81,991
    
    
    
    
    87,401




---



##### 



PRICING AND COMMODITY RISK MANAGEMENT




---



##### 



AVERAGE REALIZED PRICES
 Three months ended
    
    
    
    Twelve months ended(Cdn$)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Light crude oil (per bbl)
    
    
    
    60.76
    
    
    
    
    118.81
    
    
    
    82.31
    
    
    
    
    98.20
    
    
    
    
    72.93after realized commodity
risk management
    
    
    
    65.87
    
    
    
    
    82.00
    
    
    
    73.69
    
    
    
    
    77.78
    
    
    
    
    71.88Heavy oil (per bbl)
    
    
    
    42.20
    
    
    
    
    96.93
    
    
    
    45.47
    
    
    
    
    75.77
    
    
    
    
    44.53Natural gas (per mcf)
    
    
    
    6.97
    
    
    
    
    8.82
    
    
    
    6.20
    
    
    
    
    8.32
    
    
    
    
    6.71after realized commodity
risk management
    
    
    
    7.40
    
    
    
    
    8.29
    
    
    
    6.90
    
    
    
    
    8.19
    
    
    
    
    7.29Natural gas liquids (per bbl)
    
    
    
    43.87
    
    
    
    
    87.06
    
    
    
    67.64
    
    
    
    
    70.67
    
    
    
    
    58.86Total per boe
    
    
    
    47.60
    
    
    
    
    79.91
    
    
    
    55.16
    
    
    
    
    69.24
    
    
    
    
    52.46after realized commodity
risk management
    
    
    
    50.34
    
    
    
    
    67.71
    
    
    
    54.58
    
    
    
    
    62.76
    
    
    
    
    53.90BENCHMARK PRICESWTI oil (U.S.$  per bbl)
    
    
    
    58.73
    
    
    
    
    117.98
    
    
    
    90.71
    
    
    
    
    99.65
    
    
    
    
    72.12AECO spot gas (Cdn$  per gj)
    
    
    
    6.43
    
    
    
    
    8.76
    
    
    
    5.69
    
    
    
    
    7.70
    
    
    
    
    6.27NYMEX gas (U.S.$  per mmbtu)
    
    
    
    6.94
    
    
    
    
    10.24
    
    
    
    6.97
    
    
    
    
    9.04
    
    
    
    
    6.86Currency (U.S.$/Cdn$)
    
    
    
    0.83
    
    
    
    
    0.96
    
    
    
    1.02
    
    
    
    
    0.94
    
    
    
    
    0.93
 REALIZED COMMODITY RISK MANAGEMENT GAINS (LOSSES)
 Three months ended
    
    
    Twelve months endedDec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Light crude oil ($ millions)
    
    
    
    11.4
    
    
    
    
    (78.8
    )
    
    
    (20.5
    )
    
    
    
    (182.5
    )
    
    
    
    (10.1
    )Light crude oil ($  per bbl)
    
    
    
    5.11
    
    
    
    
    (36.81
    )
    
    
    (8.62
    )
    
    
    
    (20.42
    )
    
    
    
    (1.05
    )Natural gas ($ millions)
    
    
    
    9.6
    
    
    
    
    (12.1
    )
    
    
    16.0
    
    
    
    
    (11.8
    )
    
    
    
    56.1Natural gas ($  per mcf)
    
    
    
    0.43
    
    
    
    
    (0.53
    )
    
    
    0.70
    
    
    
    
    (0.13
    )
    
    
    
    0.58Combined ($ millions)
    
    
    
    21.0
    
    
    
    
    (90.9
    )
    
    
    (4.5
    )
    
    
    
    (194.3
    )
    
    
    
    46.0Combined ($  per boe)
    
    
    
    2.74
    
    
    
    
    (12.20
    )
    
    
    (0.58
    )
    
    
    
    (6.48
    )
    
    
    
    1.44
  OIL AND GAS SALES  CONTRIBUTION ANALYSIS
  ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec 31,
    
    
    % of
    
    
    
    Sept 30,
    
    
    % of
    
    
    Dec 31,
    
    
    % of
    
    
    
    Dec 31,
    
    
    % of
    
    
    
    Dec 31,
    
    
    % ofSales Revenue
    
    
    2008
    
    
    total
    
    
    
    2008
    
    
    total
    
    
    2007
    
    
    total
    
    
    
    2008
    
    
    total
    
    
    
    2007
    
    
    totalLight crude oil
    
    
    
    146.9
    
    
    
    37
    
    
    
    
    175.6
    
    
    
    34
    
    
    
    175.6
    
    
    
    41
    
    
    
    
    695.1
    
    
    
    36
    
    
    
    
    690.8
    
    
    
    40Natural gas
    
    
    
    164.5
    
    
    
    42
    
    
    
    
    187.9
    
    
    
    36
    
    
    
    158.8
    
    
    
    37
    
    
    
    
    722.1
    
    
    
    38
    
    
    
    
    710.1
    
    
    
    41Natural gas liquids
    
    
    
    42.9
    
    
    
    11
    
    
    
    
    66.9
    
    
    
    13
    
    
    
    57.9
    
    
    
    14
    
    
    
    
    240.9
    
    
    
    12
    
    
    
    
    202.1
    
    
    
    12Heavy oil
    
    
    
    31.9
    
    
    
    8
    
    
    
    
    73.9
    
    
    
    14
    
    
    
    31.1
    
    
    
    8
    
    
    
    
    225.3
    
    
    
    12
    
    
    
    
    116.5
    
    
    
    7Brokered sales/sulphur
    
    
    
    5.9
    
    
    
    2
    
    
    
    
    14.4
    
    
    
    3
    
    
    
    1.8
    
    
    
    
    
    
    
    
    35.6
    
    
    
    2
    
    
    
    
    2.5
    
    
    
    Total oil and gas sales
    
    
    
    392.1
    
    
    
    
    
    
    
    
    518.7
    
    
    
    
    
    
    
    425.2
    
    
    
    
    
    
    
    
    1,919.0
    
    
    
    
    
    
    
    
    1,722.0




---



##### 



OIL AND GAS SALES  PRICE AND VOLUME ANALYSIS
  ($ millions)
    
    
    Light oil
    
    
    Natural gas
    
    
    NGLs
    
    
    Heavy oil
    
    
    Other
    
    
    TotalPeriod ended Dec 31, 2007
    
    
    
    690.8
    
    
    
    710.1
    
    
    
    202.1
    
    
    
    116.5
    
    
    
    2.5
    
    
    
    1,722.0Effect of change in product prices
    
    
    
    225.9
    
    
    
    142.1
    
    
    
    40.3
    
    
    
    92.9
    
    
    
    
    
    
    
    501.2Effect of change in sales volumes
    
    
    
    (49.1
    )
    
    
    (62.4
    )
    
    
    (1.5
    )
    
    
    15.9
    
    
    
    
    
    
    
    (97.1
    )Effect of change in realized commodity
risk management activities
    
    
    
    (172.4
    )
    
    
    (67.9
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (240.3
    )Other
    
    
    
    (0.1
    )
    
    
    0.2
    
    
    
    
    
    
    
    
    
    
    
    33.1
    (1)
    
    
    32.2Period ended Dec 31, 2008
    
    
    
    695.1
    
    
    
    722.1
    
    
    
    240.9
    
    
    
    225.3
    
    
    
    35.6
    
    
    
    1,919.0
 
 (1)
    
    Primary sulphur sales. PROCESSING AND OTHER INCOME
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Processing & other income
    
    
    
    2.3
    
    
    
    
    5.2
    (1)
    
    
    4.1
    
    
    
    
    15.5
    
    
    
    
    20.6$  per boe
    
    
    
    0.31
    
    
    
    
    0.70
    
    
    
    0.53
    
    
    
    
    0.52
    
    
    
    
    0.64
 
 (1)
    
    Prior quarter restated to conform to presentation adopted in the current period.   ROYALTY EXPENSE
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Royalty expense
    
    
    
    80.7
    
    
    
    
    129.5
    
    
    
    85.4
    
    
    
    
    434.0
    
    
    
    
    319.3$  per boe
    
    
    
    10.51
    
    
    
    
    17.39
    
    
    
    11.01
    
    
    
    
    14.46
    
    
    
    
    10.01Royalties as a percent of sales
    
    
    
    20.6
    %
    
    
    
    25.0
    %
    
    
    20.0
    %
    
    
    
    22.6
    %
    
    
    
    18.5
    %Royalties as a percent of
sales excluding realized risk
management contracts
    
    
    
    21.7
    %
    
    
    
    21.2
    %
    
    
    19.9
    %
    
    
    
    20.5
    %
    
    
    
    19.1
    %




---



##### 



OPERATING EXPENSES
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Operating expenses
    
    
    
    104.1
    
    
    
    
    105.2
    
    
    
    103.8
    
    
    
    
    418.5
    
    
    
    
    406.5$  per boe
    
    
    
    13.57
    
    
    
    
    14.13
    
    
    
    13.38
    
    
    
    
    13.95
    
    
    
    
    12.74
   NET OPERATING EXPENSES
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Net operating expenses
    
    
    
    101.8
    
    
    
    
    100.0
    
    
    
    99.7
    
    
    
    
    403.0
    
    
    
    
    385.9$  per boe
    
    
    
    13.27
    
    
    
    
    13.43
    
    
    
    12.85
    
    
    
    
    13.43
    
    
    
    
    12.10
  TRANSPORTATION COSTS
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Light oil transportation
    
    
    
    0.4
    
    
    
    
    0.7
    
    
    
    1.2
    
    
    
    
    3.4
    
    
    
    
    3.5$  per bbl
    
    
    
    0.19
    
    
    
    
    0.33
    
    
    
    0.49
    
    
    
    
    0.38
    
    
    
    
    0.37Natural gas transportation
    
    
    
    2.3
    
    
    
    
    2.6
    
    
    
    2.1
    
    
    
    
    9.1
    
    
    
    
    9.1$  per mcf
    
    
    
    0.10
    
    
    
    
    0.11
    
    
    
    0.09
    
    
    
    
    0.10
    
    
    
    
    0.09
  AMORTIZATION OF INJECTANTS FOR MISCIBLE FLOODS
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Purchased and capitalized
    
    
    
    5.4
    
    
    
    
    4.8
    
    
    
    8.1
    
    
    
    
    21.0
    
    
    
    
    26.1Amortization
    
    
    
    5.9
    
    
    
    
    6.5
    
    
    
    7.5
    
    
    
    
    25.9
    
    
    
    
    34.1




---



##### 



OPERATING
NETBACKS
    Three months ended
    
    
    
    Twelve months endedCombined Netbacks ($ per boe)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Sales price (after commodity
risk management)
    
    
    
    50.34
    
    
    
    
    67.71
    
    
    
    54.58
    
    
    
    
    62.76
    
    
    
    
    53.90Other production income
    
    
    
    0.78
    
    
    
    
    1.91
    
    
    
    0.23
    
    
    
    
    1.19
    
    
    
    
    0.0851.12
    
    
    
    
    69.62
    
    
    
    54.81
    
    
    
    
    63.95
    
    
    
    
    53.98Processing and other income(1)
    
    
    
    0.31
    
    
    
    
    0.70
    
    
    
    0.53
    
    
    
    
    0.52
    
    
    
    
    0.64Royalties
    
    
    
    (10.51
    )
    
    
    
    (17.39
    )
    
    
    (11.01
    )
    
    
    
    (14.46
    )
    
    
    
    (10.01
    )Operating expenses
    
    
    
    (13.57
    )
    
    
    
    (14.13
    )
    
    
    (13.38
    )
    
    
    
    (13.95
    )
    
    
    
    (12.74
    )Transportation costs
    
    
    
    (0.35
    )
    
    
    
    (0.44
    )
    
    
    (0.42
    )
    
    
    
    (0.42
    )
    
    
    
    (0.40
    )Amortization of injectants
    
    
    
    (0.77
    )
    
    
    
    (0.88
    )
    
    
    (0.97
    )
    
    
    
    (0.86
    )
    
    
    
    (1.07
    )Operating netback
    
    
    
    26.23
    
    
    
    
    37.48
    
    
    
    29.56
    
    
    
    
    34.78
    
    
    
    
    30.40
 Three months ended
    
    
    
    Twelve months endedLight Crude Netbacks ($ per bbl)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Sales price (after commodity
risk management)
    
    
    
    65.87
    
    
    
    
    82.00
    
    
    
    73.69
    
    
    
    
    77.78
    
    
    
    
    71.88Other production income
    
    
    
    (0.02
    )
    
    
    
    (0.01
    )
    
    
    0.36
    
    
    
    
    0.19
    
    
    
    
    0.1565.85
    
    
    
    
    81.99
    
    
    
    74.05
    
    
    
    
    77.97
    
    
    
    
    72.03Processing and other income(1)
    
    
    
    0.06
    
    
    
    
    1.47
    
    
    
    0.33
    
    
    
    
    0.62
    
    
    
    
    0.44Royalties
    
    
    
    (14.02
    )
    
    
    
    (20.10
    )
    
    
    (13.86
    )
    
    
    
    (16.73
    )
    
    
    
    (11.57
    )Operating expenses(1)
    
    
    
    (14.86
    )
    
    
    
    (14.72
    )
    
    
    (14.98
    )
    
    
    
    (15.39
    )
    
    
    
    (13.73
    )Transportation costs
    
    
    
    (0.19
    )
    
    
    
    (0.33
    )
    
    
    (0.49
    )
    
    
    
    (0.38
    )
    
    
    
    (0.37
    )Amortization of injectants
    
    
    
    (2.64
    )
    
    
    
    (3.05
    )
    
    
    (3.14
    )
    
    
    
    (2.90
    )
    
    
    
    (3.54
    )Operating netback
    
    
    
    34.20
    
    
    
    
    45.26
    
    
    
    41.91
    
    
    
    
    43.19
    
    
    
    
    43.26




---



##### 



Three months ended
    
    
    
    Twelve months endedHeavy Oil Netbacks ($ per bbl)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Sales price
    
    
    
    42.20
    
    
    
    
    96.93
    
    
    
    45.47
    
    
    
    
    75.77
    
    
    
    
    44.53Processing and other income
    
    
    
    0.29
    
    
    
    
    0.02
    
    
    
    0.19
    
    
    
    
    0.32
    
    
    
    
    0.27Royalties(2)
    
    
    
    (1.95
    )
    
    
    
    (15.87
    )
    
    
    (5.91
    )
    
    
    
    (10.54
    )
    
    
    
    (5.86
    )Operating expenses(1)
    
    
    
    (12.77
    )
    
    
    
    (13.17
    )
    
    
    (11.92
    )
    
    
    
    (12.47
    )
    
    
    
    (12.60
    )Operating netback
    
    
    
    27.77
    
    
    
    
    67.91
    
    
    
    27.83
    
    
    
    
    53.08
    
    
    
    
    26.34
 Three months ended
    
    
    
    Twelve months endedNatural Gas Netbacks ($ per mcf)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Sales price (after commodity
risk management)
    
    
    
    7.40
    
    
    
    
    8.29
    
    
    
    6.90
    
    
    
    
    8.19
    
    
    
    
    7.29Other production income
    
    
    
    0.27
    
    
    
    
    0.63
    
    
    
    0.04
    
    
    
    
    0.39
    
    
    
    
    0.017.67
    
    
    
    
    8.92
    
    
    
    6.94
    
    
    
    
    8.58
    
    
    
    
    7.30Processing and other income(1)
    
    
    
    0.09
    
    
    
    
    0.09
    
    
    
    0.14
    
    
    
    
    0.10
    
    
    
    
    0.16Royalties
    
    
    
    (1.62
    )
    
    
    
    (2.19
    )
    
    
    (1.22
    )
    
    
    
    (1.88
    )
    
    
    
    (1.33
    )Operating expenses(1)
    
    
    
    (2.19
    )
    
    
    
    (2.31
    )
    
    
    (2.06
    )
    
    
    
    (2.23
    )
    
    
    
    (2.04
    )Transportation costs
    
    
    
    (0.10
    )
    
    
    
    (0.11
    )
    
    
    (0.09
    )
    
    
    
    (0.10
    )
    
    
    
    (0.09
    )Operating netback
    
    
    
    3.85
    
    
    
    
    4.40
    
    
    
    3.71
    
    
    
    
    4.47
    
    
    
    
    4.00
 Three months ended
    
    
    
    Twelve months endedNGL Netbacks ($ per bbl)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Sales price
    
    
    
    43.87
    
    
    
    
    87.06
    
    
    
    67.64
    
    
    
    
    70.67
    
    
    
    
    58.86Royalties
    
    
    
    (12.27
    )
    
    
    
    (32.22
    )
    
    
    (23.61
    )
    
    
    
    (25.74
    )
    
    
    
    (18.49
    )Operating expenses(1)
    
    
    
    (12.93
    )
    
    
    
    (14.62
    )
    
    
    (14.67
    )
    
    
    
    (13.93
    )
    
    
    
    (12.57
    )Operating netback
    
    
    
    18.67
    
    
    
    
    40.22
    
    
    
    29.36
    
    
    
    
    31.00
    
    
    
    
    27.80
 
 (1)
    
    Prior Period restated to conform to presentation in the current period.(2)
    
    Heavy Oil Royalties in the fourth quarter of 2008 includes accounting adjustments related to
overpayment of royalties in the third quarter. INTEREST EXPENSE
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Interest Expense
    
    
    
    22.6
    
    
    
    
    19.0
    (1)
    
    
    19.7
    
    
    
    
    76.3
    
    
    
    
    84.3
 
 (1)
    
    Prior quarter restated to conform to presentation adopted in the current period.




---



##### 



GENERAL AND ADMINISTRATIVE EXPENSES
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Cash G&A expense
    
    
    
    13.7
    
    
    
    
    11.3
    
    
    
    12.4
    
    
    
    
    48.9
    
    
    
    
    50.5$  per boe
    
    
    
    1.79
    
    
    
    
    1.52
    
    
    
    1.60
    
    
    
    
    1.63
    
    
    
    
    1.58Non-cash G&A expense
    
    
    
    3.5
    
    
    
    
    1.9
    
    
    
    1.8
    
    
    
    
    10.0
    
    
    
    
    5.4$  per boe
    
    
    
    0.45
    
    
    
    
    0.26
    
    
    
    0.22
    
    
    
    
    0.33
    
    
    
    
    0.17Total G&A
    
    
    
    17.2
    
    
    
    
    13.2
    
    
    
    14.2
    
    
    
    
    58.9
    
    
    
    
    55.9$  per boe
    
    
    
    2.24
    
    
    
    
    1.78
    
    
    
    1.82
    
    
    
    
    1.96
    
    
    
    
    1.75
    MANAGEMENT FEES
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Management Fee
    
    
    
    (2.0
    )
    
    
    
    3.0
    
    
    
    (2.2
    )
    
    
    
    7.0
    
    
    
    
    6.8$  per boe
    
    
    
    (0.26
    )
    
    
    
    0.40
    
    
    
    (0.28
    )
    
    
    
    0.23
    
    
    
    
    0.21




---



##### 



RELATED PARTY TRANSACTIONS
   TAXES
  Bill C-52 Budget Implementation Act 2007




---



##### 



Future Income Taxes
  FOREIGN CURRENCY GAINS & LOSSES
    DEPLETION, DEPRECIATION AND ACCRETION
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Depletion and depreciation
    
    
    
    157.6
    
    
    
    
    151.5
    
    
    
    156.0
    
    
    
    
    609.3
    
    
    
    
    639.1$  per boe
    
    
    
    20.55
    
    
    
    
    20.34
    
    
    
    20.11
    
    
    
    
    20.31
    
    
    
    
    20.03Accretion
    
    
    
    7.3
    
    
    
    
    7.1
    
    
    
    6.5
    
    
    
    
    28.1
    
    
    
    
    25.7$  per boe
    
    
    
    0.95
    
    
    
    
    0.95
    
    
    
    0.84
    
    
    
    
    0.93
    
    
    
    
    0.81
   CEILING TEST
   PENGROWTH 2008




---



##### 



ASSET RETIREMENT OBLIGATIONS
  REMEDIATION TRUST FUNDS AND REMEDIATION AND ABANDONMENT EXPENSE
     CLIMATE CHANGE PROGRAMS
  OTHER EXPENSES
  PENGROWTH 2008




---



##### 



GOODWILL
  CAPITAL EXPENDITURES
 Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2008
    
    
    
    Sept 30, 2008
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2008
    
    
    
    Dec 31, 2007Seismic acquisitions(1)(2)
    
    
    
    0.5
    
    
    
    
    2.0
    
    
    
    (0.5
    )
    
    
    
    7.6
    
    
    
    
    6.1Drilling, completions and
facilities(1)
    
    
    
    82.6
    
    
    
    
    64.2
    
    
    
    71.2
    
    
    
    
    276.5
    
    
    
    
    226.7Maintenance capital(1)
    
    
    
    26.2
    
    
    
    
    13.0
    
    
    
    15.4
    
    
    
    
    57.5
    
    
    
    
    37.1Land purchases
    
    
    
    0.1
    
    
    
    
    17.9
    
    
    
    2.7
    
    
    
    
    26.7
    
    
    
    
    13.2Development capital
    
    
    
    109.4
    
    
    
    
    97.1
    
    
    
    88.8
    
    
    
    
    368.3
    
    
    
    
    283.1Lindbergh Project
    
    
    
    10.4
    
    
    
    
    3.0
    
    
    
    
    
    
    
    
    20.0
    
    
    
    
    Other capital
    
    
    
    3.8
    
    
    
    
    (0.6
    )
    
    
    6.9
    
    
    
    
    13.6
    
    
    
    
    26.6Total capital expenditures
    
    
    
    123.6
    
    
    
    
    99.5
    
    
    
    95.7
    
    
    
    
    401.9
    
    
    
    
    309.7Business acquisitions(3)
    
    
    
    0.2
    
    
    
    
    90.2
    
    
    
    (0.6
    )
    
    
    
    90.4
    
    
    
    
    923.1Property acquisitions
    
    
    
    0.2
    
    
    
    
    18.1
    
    
    
    9.0
    
    
    
    
    35.9
    
    
    
    
    9.0Proceeds on property dispositions
    
    
    
    (20.4
    )
    
    
    
    0.1
    
    
    
    (23.7
    )
    
    
    
    (17.4
    )
    
    
    
    (458.8
    )Net capital expenditures
and acquisitions
    
    
    
    103.6
    
    
    
    
    207.9
    
    
    
    80.4
    
    
    
    
    510.8
    
    
    
    
    783.0
 (1)
    
    Prior year restated to conform to presentation adopted in current year.(2)
    
    Seismic acquisitions are net of seismic sales revenue.(3)
    
    Accrete acquisition valued at consideration paid (see Note 4 of consolidated financial statements).   RESERVES
   PENGROWTH 2008




---



##### 



ACQUISITIONS AND DISPOSITIONS
      WORKING CAPITAL
   PENGROWTH 2008




---



##### 



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




---



##### 



PENGROWTH 2008




---



##### 



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




---



##### 



TAXABILITY OF DISTRIBUTIONS
   PENGROWTH 2008




---



##### 







COMMITMENTS AND CONTRACTUAL OBLIGATIONS
 ($ thousands)
    
    
    2009
    
    
    2010
    
    
    2011
    
    
    2012
    
    
    2013
    
    
    thereafter
    
    
    TotalLong term debt(1)
    
    
    
    
    
    
    
    182,180
    
    
    
    372,000
    
    
    
    
    
    
    
    60,900
    
    
    
    925,459
    
    
    
    1,540,539Interest payments on
long term debt(2)
    
    
    
    72,313
    
    
    
    66,308
    
    
    
    63,306
    
    
    
    63,306
    
    
    
    61,085
    
    
    
    230,955
    
    
    
    557,273Convertible debentures(3)
    
    
    
    
    
    
    
    74,700
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    74,700Interest payments on
convertible debentures(4)
    
    
    
    4,810
    
    
    
    4,810
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,620Other(5)
    
    
    
    10,797
    
    
    
    10,427
    
    
    
    9,560
    
    
    
    7,646
    
    
    
    8,107
    
    
    
    31,735
    
    
    
    78,27287,920
    
    
    
    338,425
    
    
    
    444,866
    
    
    
    70,952
    
    
    
    130,092
    
    
    
    1,188,149
    
    
    
    2,260,404Purchase obligationsPipeline transportation
    
    
    
    40,468
    
    
    
    22,006
    
    
    
    19,326
    
    
    
    16,405
    
    
    
    16,046
    
    
    
    26,462
    
    
    
    140,713CO2 purchases(6)
    
    
    
    2,919
    
    
    
    2,943
    
    
    
    2,601
    
    
    
    2,352
    
    
    
    2,365
    
    
    
    5,475
    
    
    
    18,65543,387
    
    
    
    24,949
    
    
    
    21,927
    
    
    
    18,757
    
    
    
    18,411
    
    
    
    31,937
    
    
    
    159,368Remediation trust
fund payments
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    11,250
    
    
    
    12,500131,557
    
    
    
    363,624
    
    
    
    467,043
    
    
    
    89,959
    
    
    
    148,753
    
    
    
    1,231,336
    
    
    
    2,432,272
 
 (1)
    
    The debt repayment includes the principal owing at maturity on foreign denominated fixed rate
debt. (see Note 4 of the financial statements)(2)
    
    Interest payments relate to the interest
payable on the fixed rate debt. Foreign denominated debt is translated using the year-end exchange rate.(3)
    
    Includes repayment of convertible debentures on maturity (see Note 14 of the financial
statements), and assumes no conversion of convertible debentures to trust units.(4)
    
    Includes annual interest on convertible debentures outstanding at year-end and assumes no conversion of
convertible debentures prior to maturity.(5)
    
    Includes office rent and vehicle leases.(6)
    
    For the Weyburn CO2 project, prices are denominated in U.S. dollars and have
been translated at the year-end exchange rate. For the Judy Creek
CO2
Pilot Project, Prices are denominated in Canadian dollars. SUMMARY OF TRUST UNIT TRADING DATA
 Volume
    
    
    ValueHigh
    
    
    Low
    
    
    Close
    
    
    (000s)
    
    
    ($ millions)TSX  PGF.UN ($ Cdn)2008 1st quarter
    
    
    
    19.82
    
    
    
    14.16
    
    
    
    19.67
    
    
    
    30,755
    
    
    
    557.92nd quarter
    
    
    
    21.56
    
    
    
    19.17
    
    
    
    20.50
    
    
    
    28,004
    
    
    
    569.73rd quarter
    
    
    
    20.55
    
    
    
    14.73
    
    
    
    15.99
    
    
    
    31,735
    
    
    
    565.44th quarter
    
    
    
    15.98
    
    
    
    8.55
    
    
    
    9.35
    
    
    
    35,035
    
    
    
    402.7Year
    
    
    
    21.56
    
    
    
    8.55
    
    
    
    9.35
    
    
    
    125,529
    
    
    
    2,095.72007 1st quarter
    
    
    
    20.85
    
    
    
    18.62
    
    
    
    19.45
    
    
    
    37,742
    
    
    
    744.82nd quarter
    
    
    
    21.04
    
    
    
    18.82
    
    
    
    20.27
    
    
    
    28,348
    
    
    
    561.53rd quarter
    
    
    
    20.70
    
    
    
    16.92
    
    
    
    18.64
    
    
    
    27,970
    
    
    
    524.54th quarter
    
    
    
    18.68
    
    
    
    17.00
    
    
    
    17.62
    
    
    
    23,559
    
    
    
    423.1Year
    
    
    
    21.04
    
    
    
    16.92
    
    
    
    17.62
    
    
    
    117,619
    
    
    
    2,253.9NYSE  PGH ($ U.S.)2008 1st quarter
    
    
    
    19.47
    
    
    
    13.67
    
    
    
    19.10
    
    
    
    14,293
    
    
    
    257.52nd quarter
    
    
    
    21.90
    
    
    
    18.86
    
    
    
    20.11
    
    
    
    19,425
    
    
    
    392.73rd quarter
    
    
    
    20.20
    
    
    
    14.16
    
    
    
    14.94
    
    
    
    26,815
    
    
    
    457.74th quarter
    
    
    
    15.00
    
    
    
    6.84
    
    
    
    7.62
    
    
    
    41,776
    
    
    
    401.2Year
    
    
    
    21.90
    
    
    
    6.84
    
    
    
    7.62
    
    
    
    102,309
    
    
    
    1,509.12007 1st quarter
    
    
    
    17.96
    
    
    
    15.82
    
    
    
    16.87
    
    
    
    26,633
    
    
    
    449.12nd quarter
    
    
    
    19.84
    
    
    
    16.45
    
    
    
    19.09
    
    
    
    23,668
    
    
    
    428.63rd quarter
    
    
    
    19.85
    
    
    
    16.25
    
    
    
    18.84
    
    
    
    19,284
    
    
    
    346.94th quarter
    
    
    
    19.21
    
    
    
    17.30
    
    
    
    17.77
    
    
    
    13,980
    
    
    
    256.4Year
    
    
    
    19.85
    
    
    
    15.82
    
    
    
    17.77
    
    
    
    83,565
    
    
    
    1,481.0
 PENGROWTH 2008







---



##### 



SUMMARY OF QUARTERLY RESULTS
  2008
    
    
    Q1
    
    
    Q2
    
    
    Q3
    
    
    Q4Oil and gas sales ($000s)
    
    
    
    457,606
    
    
    
    550,623
    
    
    
    518,662
    
    
    
    392,158Net income/(loss) ($000s)
    
    
    
    (56,583
    )
    
    
    (118,650
    )
    
    
    422,395
    
    
    
    148,688Net income/(loss) per trust unit ($)
    
    
    
    (0.23
    )
    
    
    (0.48
    )
    
    
    1.69
    
    
    
    0.58Net income/(loss) per trust unit  diluted ($)
    
    
    
    (0.23
    )
    
    
    (0.48
    )
    
    
    1.69
    
    
    
    0.58Cash flow from operating activities ($000s)
    
    
    
    216,238
    
    
    
    267,874
    
    
    
    273,597
    
    
    
    154,807Distributions declared ($000s)
    
    
    
    167,234
    
    
    
    168,159
    
    
    
    170,959
    
    
    
    144,663Distributions declared per trust unit ($)
    
    
    
    0.675
    
    
    
    0.675
    
    
    
    0.675
    
    
    
    0.565Daily production (boe)
    
    
    
    82,711
    
    
    
    80,895
    
    
    
    80,981
    
    
    
    83,373Total production (mboe)
    
    
    
    7,527
    
    
    
    7,361
    
    
    
    7,450
    
    
    
    7,670Average realized price ($  per boe)
    
    
    
    60.30
    
    
    
    73.21
    
    
    
    67.71
    
    
    
    50.34Operating netback ($  per boe)(1)
    
    
    
    33.62
    
    
    
    42.15
    
    
    
    37.48
    
    
    
    26.23
 2007
    
    Q1
    
    
    Q2
    
    
    Q3
    
    
    Q4Oil and gas sales ($000s)
    
    
    432,108
    
    
    
    443,977
    
    
    
    420,704
    
    
    
    425,249Net income/(loss) ($000s)
    
    
    (69,834
    )
    
    
    271,659
    
    
    
    161,492
    
    
    
    (3,665
    )Net income/(loss) per trust unit ($)
    
    
    (0.29
    )
    
    
    1.11
    
    
    
    0.66
    
    
    
    (0.01
    )Net
income/(loss) per trust unit  diluted ($)
    
    
    (0.29
    )
    
    
    1.10
    
    
    
    0.66
    
    
    
    (0.01
    )Cash flow
from operating activities ($000s)
    
    
    136,429
    
    
    
    249,960
    
    
    
    217,630
    
    
    
    196,325Distributions declared ($000s)
    
    
    183,534
    
    
    
    184,327
    
    
    
    172,109
    
    
    
    166,631Distributions declared per trust unit ($)
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.70
    
    
    
    0.675Daily production (boe)
    
    
    90,068
    
    
    
    89,633
    
    
    
    85,654
    
    
    
    84,331Total production (mboe)
    
    
    8,106
    
    
    
    8,157
    
    
    
    7,880
    
    
    
    7,758Average realized price ($  per boe)
    
    
    53.30
    
    
    
    54.39
    
    
    
    53.34
    
    
    
    54.58Operating netback ($  per boe)
    
    
    29.87
    
    
    
    29.56
    
    
    
    32.66
    
    
    
    29.56
 
 (1)
    
    Restated to conform to presentation adopted in the current period.  PENGROWTH 2008




---



##### 



SELECTED ANNUAL INFORMATION
  Twelve months ended December 31($ thousands)
    
    
    2008
    
    
    
    2007
    
    
    2006Oil and gas sales
    
    
    
    1,919,049
    
    
    
    
    1,722,038
    
    
    
    1,214,093Net income
    
    
    
    395,850
    
    
    
    
    359,652
    
    
    
    262,303Net income per trust unit ($)
    
    
    
    1.58
    
    
    
    
    1.47
    
    
    
    1.49Net income per trust unit  diluted ($)
    
    
    
    1.58
    
    
    
    
    1.46
    
    
    
    1.49Distributions declared per trust unit ($)
    
    
    
    2.59
    
    
    
    
    2.875
    
    
    
    3.00Total assets
    
    
    
    5,317,341
    
    
    
    
    5,234,251
    
    
    
    4,690,129Long term debt(1)
    
    
    
    1,599,418
    
    
    
    
    1,278,266
    
    
    
    679,327Trust unitholders equity
    
    
    
    2,663,805
    
    
    
    
    2,756,220
    
    
    
    3,049,677Number of trust units outstanding at year end (thousands)
    
    
    
    256,076
    
    
    
    
    246,846
    
    
    
    244,017
 
 (1)
    
    Includes long term debt and convertible debentures. BUSINESS RISKS
  
    
    Continued uncertainty in the credit markets may restrict the availability or increase the cost of
borrowing required for future development and acquisitions. This uncertainty may also impair
Pengrowths normal business counterparties to meet their obligations to Pengrowth. Additional
credit risk could exist where little or none previously existed.
    
    The prices of Pengrowths products (crude oil, natural gas, and NGLs) fluctuate due to many factors
including local and global market supply and demand, weather patterns, pipeline transportation and
political and economic stability.
    
    The marketability of our production depends in part upon the availability, proximity and capacity
of gathering systems, pipelines and processing facilities. Operational or economic factors may
result in the inability to deliver our products to market.
    
    Geological and operational risks affect the quantity and quality of reserves and the costs of
recovering those reserves. Our actual results will vary from our reserve estimates and those
variations could be material.
    
    Government royalties, income taxes, commodity taxes and other taxes, levies and fees have a
significant economic impact on Pengrowths financial results. Changes to federal and provincial
legislation governing such royalties, taxes and fees, including implementation of the SIFT
Legislation, could have a material impact on Pengrowths financial results and the value of
Pengrowth trust units.
    
    Pengrowth could lose its grandfathered status under the SIFT Legislation and become subject to the
SIFT tax prior to January 1, 2011 if it exceeds the normal growth guidelines.
    
    Oil and gas operations carry the risk of damaging the local environment in the event of equipment
or operational failure. The cost to remediate any environmental damage could be significant.
    
    Environmental laws and regulatory initiatives impact Pengrowth financially and operationally. We
may incur substantial capital and operating expenses to comply with increasingly complex laws and
regulations covering the protection of the environment and human health and safety. In particular,
we may be required to incur significant costs to comply with future regulations to reduce
greenhouse gas and other emissions.
    
    Pengrowths oil and gas reserves will be depleted over time and our level of cash flow from
operations and the value of our trust units could be reduced if reserves and production are not
replaced. The ability to replace production depends on the amount of capital invested and success
in developing existing reserves, acquiring new reserves and financing this development and
acquisition activity within the context of the capital markets.
 PENGROWTH 2008




---



##### 




    
    Increased competition for properties will drive the cost of acquisitions up and expected returns
from the properties down.
    
    Timing of oil and gas operations is dependent on gaining timely access to lands. Consultations,
that are mandated by governing authorities, with all stakeholders (including surface owners, First
Nations and all interested parties) are becoming increasingly time consuming and complex, and are
having a direct impact on cycle times.
    
    A significant portion of Pengrowths properties are operated by third parties. If these operators
fail to perform their duties properly, or become insolvent, we may experience interruptions in
production and revenues from these properties or incur additional liabilities and expenses as a
result of the default of these third party operators.
    
    During periods of increased activity within the oil and gas sector, the cost of goods and services
may increase and it may be more difficult to hire and retain professional staff.
    
    Changing interest rates influence borrowing costs and the availability of capital.
    
    Failing a financial covenant may result in one or more of Pengrowths loans being in default. In
certain circumstances, being in default of one loan will result in other loans to also be in
default.
    
    Investors interest in the oil and gas sector may change over time which would affect the
availability of capital and the value of Pengrowth trust units.
    
    Inflation may result in escalating costs, which could impact unitholder distributions and the value
of Pengrowth trust units.
    
    Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and capital
costs. Pengrowth is also exposed to foreign currency fluctuations on the U.S. dollar denominated
notes for both interest and principal payments.
    
    The value of Pengrowth trust units is impacted directly by the related tax treatment of the trust
units and the trust unit distributions, and indirectly by the tax treatment of alternative equity
investments. Changes in Canadian or U.S. tax legislation could adversely affect the value of our
trust units. As 2011 approaches, the expectation of taxability of distributions may negatively
impact the value of trust units.
    
    Attacks by individuals against facilities and the threat of such attacks may have an adverse impact
on Pengrowth and the implementation of security measures as a precaution against possible attacks
would result in increased cost to Pengrowths business.
    
    Substantial and sustained reductions in commodity prices or equity markets, including Pengrowths
unit price, in some circumstances could result in Pengrowth reducing the recorded book value of
some of its assets.
    
    Delays in business operations could adversely affect Pengrowths distributions to unitholders and
the market price of the trust units.
  SUBSEQUENT EVENTS
  Remaining term
    
    
    Volume (bbl/d)
    
    
    Reference Point
    
    
    Price per bblFinancial:Mar 1, 2009 - Dec 31, 2009
    
    
    
    500
    
    
    WTI
    (1)
    
    $58.00 CdnApril 1, 2009 - Dec 31, 2009
    
    
    
    1,000
    
    
    WTI
    (1)
    
    $57.78 CdnJan 1, 2010 - Dec 31, 2010
    
    
    
    5,000
    
    
    WTI
    (1)
    
    $69.06 Cdn
 
 (1)
    
    Associated Cdn $/U.S. $ foreign exchange rate has been fixed OUTLOOK
   PENGROWTH 2008




---



##### 



CURRENT GLOBAL ECONOMIC CONDITIONS
   RECENT ACCOUNTING PRONOUNCEMENTS
      PENGROWTH 2008




---



##### 



DISCLOSURE CONTROLS AND PROCEDURES
    PENGROWTH 2008




---



##### 



INTERNAL CONTROL OVER FINANCIAL REPORTING
     PENGROWTH 2008




---



##### 



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




---



##### 



-s- James S. Kinnear
    
    -s- Christopher G. WebsterJames S. Kinnear
    
    Christopher G. WebsterChairman, President and
    
    Chief Financial OfficerChief Executive OfficerMarch 2, 2009
 PENGROWTH 2008




---



##### 



(KPMG LLP)Chartered AccountantsCalgary, CanadaMarch 1, 2009
 PENGROWTH 2008




---



##### 



(KPMG LLP)Chartered AccountantsCalgary, CanadaMarch 1, 2009
 PENGROWTH 2008




---



##### 



As at December 31
    
    
    2008
    
    
    
    2007ASSETSCurrent assetsCash and term deposits
    
    
    $
    
    
    
    
    $
    2,017Accounts receivable
    
    
    
    197,131
    
    
    
    
    206,583Due from Pengrowth Management Limited
    
    
    
    623
    
    
    
    
    731Fair value of risk management contracts (Note 20)
    
    
    
    122,841
    
    
    
    
    8,034Future income taxes (Note 11)
    
    
    
    
    
    
    
    
    18,751320,595
    
    
    
    
    236,116Fair value of risk management contracts(Note 20)
    
    
    
    41,851
    
    
    
    
    6,024Other assets(Note 5)
    
    
    
    42,618
    
    
    
    
    24,831Property, plant and equipment(Note 6)
    
    
    
    4,251,381
    
    
    
    
    4,306,682Goodwill
    
    
    
    660,896
    
    
    
    
    660,598TOTAL ASSETS
    
    
    $
    5,317,341
    
    
    
    $
    5,234,251LIABILITIES AND UNITHOLDERS EQUITYCurrent liabilitiesBank indebtedness
    
    
    $
    2,631
    
    
    
    $
    Accounts payable and accrued liabilities
    
    
    
    260,828
    
    
    
    
    239,091Distributions payable to unitholders
    
    
    
    87,142
    
    
    
    
    111,119Fair value of risk management contracts (Note 20)
    
    
    
    2,706
    
    
    
    
    70,846Future income taxes (Note 11)
    
    
    
    34,964
    
    
    
    
    Contract liabilities (Note 7)
    
    
    
    2,483
    
    
    
    
    4,663390,754
    
    
    
    
    425,719Fair value of risk management contracts(Note 20)
    
    
    
    16,021
    
    
    
    
    22,613Contract liabilities(Note 7)
    
    
    
    9,680
    
    
    
    
    12,162Convertible debentures(Note 8)
    
    
    
    74,915
    
    
    
    
    75,030Long term debt(Note 9)
    
    
    
    1,524,503
    
    
    
    
    1,203,236Asset retirement obligations(Note 10)
    
    
    
    344,345
    
    
    
    
    352,171Future income taxes(Note 11)
    
    
    
    293,318
    
    
    
    
    387,100Trust unitholders equity(Note 12)Trust Unitholders capital
    
    
    
    4,588,587
    
    
    
    
    4,432,737Equity portion of convertible debentures
    
    
    
    160
    
    
    
    
    160Contributed surplus
    
    
    
    16,579
    
    
    
    
    9,679Deficit (Note 14)
    
    
    
    (1,941,521
    )
    
    
    
    (1,686,356
    )2,663,805
    
    
    
    
    2,756,220Commitments(Note 21)Contingencies(Note 22)Subsequent events(Note 23)TOTAL LIABILITIES AND UNITHOLDERS EQUITY
    
    
    $
    5,317,341
    
    
    
    $
    5,234,251
   (SIGNATURE)
    
    (SIGNATURE)Director
    
    Director
 PENGROWTH 2008




---



##### 



Years ended December 31
    
    
    2008
    
    
    
    2007REVENUESOil and gas sales
    
    
    $
    1,919,049
    
    
    
    $
    1,722,038Unrealized gain (loss) on commodity risk management (Note 20)
    
    
    
    249,899
    
    
    
    
    (122,307
    )Processing and other income
    
    
    
    15,525
    
    
    
    
    20,573Royalties, net of incentives
    
    
    
    (433,970
    )
    
    
    
    (319,319
    )Net revenue
    
    
    
    1,750,503
    
    
    
    
    1,300,985EXPENSESOperating
    
    
    
    418,497
    
    
    
    
    406,522Transportation
    
    
    
    12,519
    
    
    
    
    12,672Amortization of injectants for miscible floods
    
    
    
    25,876
    
    
    
    
    34,063Interest on bank indebtedness
    
    
    
    
    
    
    
    
    13,876Interest on long term debt
    
    
    
    76,304
    
    
    
    
    70,416General and administrative
    
    
    
    58,937
    
    
    
    
    55,903Management fee
    
    
    
    6,950
    
    
    
    
    6,807Foreign exchange loss (gain) (Note 15)
    
    
    
    189,172
    
    
    
    
    (61,857
    )Depletion, depreciation and amortization
    
    
    
    609,326
    
    
    
    
    639,084Accretion (Note 10)
    
    
    
    28,051
    
    
    
    
    25,722Other expenses
    
    
    
    946
    
    
    
    
    2,7371,426,578
    
    
    
    
    1,205,945Income before taxes
    
    
    
    323,925
    
    
    
    
    95,040Future income tax reduction (Note 11)
    
    
    
    (71,925
    )
    
    
    
    (264,612
    )NET INCOME AND COMPREHENSIVE INCOME
    
    
    $
    395,850
    
    
    
    $
    359,652Deficit, beginning of year
    
    
    
    (1,686,356
    )
    
    
    
    (1,339,407
    )Distributions declared
    
    
    
    (651,015
    )
    
    
    
    (706,601
    )DEFICIT, END OF YEAR
    
    
    $
    (1,941,521
    )
    
    
    $
    (1,686,356
    )Net income per trust unit (Note 18)Basic
    
    
    $
    1.58
    
    
    
    $
    1.47Diluted
    
    
    $
    1.58
    
    
    
    $
    1.46
  PENGROWTH 2008




---



##### 



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




---



##### 



BASIS OF PRESENTATION
   PENGROWTH 2008




---



##### 



JOINT INTEREST OPERATIONS
  PROPERTY, PLANT AND EQUIPMENT
       GOODWILL
  INJECTANT COSTS
  PENGROWTH 2008




---



##### 



ASSET RETIREMENT OBLIGATIONS
   INCOME TAXES
  TRUST UNIT COMPENSATION PLANS
   FINANCIAL INSTRUMENTS
    PENGROWTH 2008




---



##### 



FOREIGN CURRENCY
  EQUITY INVESTMENT
  MEASUREMENT UNCERTAINTY
   NET INCOME PER TRUST UNIT
  REVENUE RECOGNITION
  CASH AND TERM DEPOSITS
  COMPARATIVE FIGURES
  PENGROWTH 2008




---



##### 



PENGROWTH 2008




---



##### 



2008 ACQUISITIONS
  Allocation of Purchase Price:Property, plant and equipment
    
    
    $
    146,463Bank debt
    
    
    
    (16,289
    )Asset retirement obligations
    
    
    
    (2,685
    )Working capital deficit
    
    
    
    (5,548
    )Future income taxes
    
    
    
    (31,858
    )$
    90,083Consideration:Pengrowth units
    
    
    $
    89,253Acquisition costs
    
    
    
    830$
    90,083
   2007 ACQUISITIONS
  Allocation of Purchase Price:Property, plant and equipment
    
    $
    1,360,491Goodwill
    
    
    62,594Asset retirement obligations
    
    
    (90,772
    )Future income taxes
    
    
    (305,144
    )$
    1,027,169Consideration:Cash
    
    $
    1,024,873Acquisition costs
    
    
    2,296$
    1,027,169
 PENGROWTH 2008




---



##### 



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




---



##### 



2008
    
    
    2007Property, plant and equipment, at cost
    
    
    $
    7,136,374
    
    
    $
    6,577,484Accumulated depletion, depreciation and amortization
    
    
    
    (2,907,409
    )
    
    
    (2,298,083
    )Net book value of property, plant and equipment
    
    
    $
    4,228,965

    
    
    $
    4,279,401Net book value of deferred injectant costs
    
    
    
    22,416

    
    
    
    27,281Net book value of property, plant and equipment and deferred injectants
    
    
    $
    4,251,381

    
    
    $
    4,306,682
   Foreign
    
    Edmonton
    
    AECOWTI Oil
    
    Exchange Rate
    
    Light Crude Oil
    
    GasYear
    
    
    (U.S.$/bbl)
    
    (U.S.$/Cdn$)
    
    (Cdn$/bbl)
    
    (Cdn$/mmbtu)2009
    
    
    $
    57.50

    
    
    0.825

    
    $
    68.61

    
    $
    7.582010
    
    
    $
    68.00
    

    
    0.850
    
    $
    78.94

    
    $
    7.942011
    
    
    $
    74.00

    
    
    0.875

    
    $
    83.54

    
    $
    8.342012
    
    
    $
    85.00

    
    
    0.925

    
    $
    90.92

    
    $
    8.702013
    
    
    $
    92.01

    
    
    0.950

    
    $
    95.91

    
    $
    8.952014
    
    
    $
    93.85

    
    
    0.950

    
    $
    97.84

    
    $
    9.142015
    
    
    $
    95.73

    
    
    0.950

    
    $
    99.82

    
    $
    9.342016
    
    
    $
    97.64

    
    
    0.950

    
    $
    101.83

    
    $
    9.542017
    
    
    $
    99.59

    
    
    0.950

    
    $
    103.89

    
    $
    9.752018
    
    
    $
    101.59

    
    
    0.950

    
    $
    105.99

    
    $
    9.95Thereafter
    
    
    + 2.0 percent/yr
    
    
    0.950

    
    + 2.0 percent/yr
    
    + 2.0 percent/yr
   2008
    
    
    2007Fixed price commodity contract
    
    
    $
    956

    
    
    $
    4,110Firm transportation contracts
    
    
    
    11,207

    
    
    
    12,71512,163

    
    
    
    16,825Less current portion
    
    
    
    (2,483
    )

    
    
    (4,663
    )$
    9,680

    
    
    $
    12,162
  PENGROWTH 2008




---



##### 



Debt
    
    
    Equity
    
    
    TotalBalance, December 31, 2007
    
    
    $
    75,030
    
    
    $
    160
    
    
    $
    75,190Amortization of debt premium
    
    
    
    (115
    )
    
    
    
    
    
    
    (115
    )Balance, December 31, 2008
    
    
    $
    74,915
    
    
    $
    160
    
    
    $
    75,075
  2008
    
    
    
    2007U.S. dollar denominated senior unsecured notes:150 million at 4.93 percent due April 2010
    
    
    $
    182,180
    
    
    
    $
    148,05350 million at 5.47 percent due April 2013
    
    
    
    60,727
    
    
    
    
    49,351400 million at 6.35 percent due July 2017
    
    
    
    485,080
    
    
    
    
    394,390265 million at 6.98 percent due August 2018
    
    
    
    321,231
    
    
    
    
    $
    1,049,218
    
    
    
    $
    591,794U.K. pound sterling denominated 50 million unsecured
notes at 5.46 percent due December 2015
    
    
    
    88,285
    
    
    
    
    97,444Canadian dollar 15 million senior unsecured
notes at 6.61 percent due August 2018
    
    
    
    15,000
    
    
    
    
    Canadian dollar revolving credit facility borrowings
    
    
    
    372,000
    
    
    
    
    513,998$
    1,524,503
    
    
    
    $
    1,203,236
   PENGROWTH 2008




---



##### 



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




---



##### 



Remediation trust funds
   
 Remediation Trust Funds
    
    
    2008
    
    
    
    2007Opening balance
    
    
    $
    18,094
    
    
    
    $
    11,144Contributions to Judy Creek Remediation Trust Fund
    
    
    
    831
    
    
    
    
    917Contributions to SOEP Environmental Restoration Fund
    
    
    
    8,485
    
    
    
    
    6,441Remediation funded by Judy Creek Remediation Trust Fund
    
    
    
    (288
    )
    
    
    
    (408
    )Change in remediation trust funds
    
    
    
    9,028
    
    
    
    
    6,950Closing balance
    
    
    $
    27,122
    
    
    
    $
    18,094
 Expenditures on ARO
    
    
    2008
    
    
    
    2007Expenditures on ARO not covered by the trust funds
    
    
    $
    32,403
    
    
    
    $
    11,020Expenditures on ARO covered by the trust funds
    
    
    
    288
    
    
    
    
    408$
    32,691
    
    
    
    $
    11,428




---



##### 



2008
    
    
    
    2007Income before taxes
    
    
    $
    323,925
    
    
    
    $
    95,040Combined federal and provincial tax rate
    
    
    
    29.50
    %
    
    
    
    32.10
    %Expected income tax
    
    
    
    95,558
    
    
    
    
    30,508Net income of the Trust
    
    
    
    (200,998
    )
    
    
    
    (123,227
    )Impact of SIFT legislation
    
    
    
    
    
    
    
    
    (71,048
    )Unrealized foreign exchange (gain) loss
    
    
    
    24,783
    
    
    
    
    (9,254
    )Book to tax differential on dispositions
    
    
    
    
    
    
    
    
    (68,722
    )Change in enacted tax rates
    
    
    
    (3,745
    )
    
    
    
    (59,230
    )Future tax rate difference
    
    
    
    4,175
    
    
    
    
    19,679Other including stock based compensation
    
    
    
    1,859
    
    
    
    
    16,682Valuation allowance
    
    
    
    6,443
    
    
    
    
    Future income tax reduction
    
    
    $
    (71,925
    )
    
    
    $
    (264,612
    )
   2008
    
    
    
    2007Future income tax assets:Asset retirement obligation
    
    
    $
    84,090
    
    
    
    $
    85,717Non-capital losses
    
    
    
    117,987
    
    
    
    
    68,611Unrealized commodity loss
    
    
    
    
    
    
    
    
    22,066Unrealized foreign exchange loss
    
    
    
    6,443
    
    
    
    
    Contract liabilities
    
    
    
    3,292
    
    
    
    
    3,106211,812
    
    
    
    
    179,500Less: Valuation allowance
    
    
    
    (6,443
    )
    
    
    
    205,369
    
    
    
    
    179,500Future income tax liabilities:Property, plant, equipment and other assets
    
    
    
    (491,170
    )
    
    
    
    (504,319
    )Unrealized commodity gain
    
    
    
    (42,481
    )
    
    
    
    Unrealized foreign exchange gain
    
    
    
    
    
    
    
    
    (15,601
    )Deferred partnership income
    
    
    
    
    
    
    
    
    (27,929
    )Net future tax liability
    
    
    $
    (328,282
    )
    
    
    $
    (368,349
    )




---



##### 



2008
    
    
    
    2007Number of
    
    
    
    
    
    
    
    Number ofTrust Units Issued
    
    
    Trust Units
    
    
    Amount
    
    
    
    Trust Units
    
    
    AmountBalance, beginning of year
    
    
    
    246,846,420
    
    
    $
    4,432,737
    
    
    
    
    244,016,623
    
    
    $
    4,383,993Issued on redemption
of DEUs (non-cash)(1)
    
    
    
    238,633
    
    
    
    2,484
    
    
    
    
    2,931
    
    
    
    55Issued for cash on exercise of trust
unit options and rights
    
    
    
    290,363
    
    
    
    4,274
    
    
    
    
    350,615
    
    
    
    4,006Issued for cash under Distribution
Reinvestment Plan (DRIP)
    
    
    
    3,727,256
    
    
    
    59,423
    
    
    
    
    2,461,299
    
    
    
    44,880Issued for the Accrete business combination
    
    
    
    4,973,325
    
    
    
    89,253
    
    
    
    
    
    
    
    
    Issued on redemption of Royalty Units
(non-cash)
    
    
    
    
    
    
    
    
    
    
    
    
14,952
    
    
    
    Trust unit rights incentive plan (non-cash
exercised)
    
    
    
    
    
    
    
    614
    
    
    
    
    
    
    
    
    548Issue costs
    
    
    
    
    
    
    
    (198
    )
    
    
    
    
    
    
    
    (745
    )Balance, end of year
    
    
    
    256,075,997
    
    
    $
    4,588,587
    
    
    
    
    246,846,420
    
    
    $
    4,432,737
 (1)
    
    Includes 2005 DEU grants vested in 2008 with a performance multiplier of 120% and DEUs granted
to retirees.  Redemption Rights
  Distribution Reinvestment Plan
  At The Market Distribution




---



##### 



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




---



##### 



2008
    
    
    
    2007Number
    
    
    Weighted
    
    
    
    Number
    
    
    WeightedDEU
    
    
    of DEUs
    
    
    average price
    
    
    
    of DEUs
    
    
    average priceOutstanding, beginning of year
    
    
    
    868,042
    
    
    $
    20.13
    
    
    
    
    399,568
    
    
    $
    20.55Granted
    
    
    
    578,833
    
    
    $
    17.88
    
    
    
    
    451,615
    
    
    $
    19.73Forfeited
    
    
    
    (158,532
    )
    
    $
    19.54
    
    
    
    
    (92,672
    )
    
    $
    20.15Exercised
    
    
    
    (202,020
    )
    
    $
    18.51
    
    
    
    
    (2,931
    )
    
    $
    20.06Deemed DRIP
    
    
    
    184,427
    
    
    $
    19.70
    
    
    
    
    112,462
    
    
    $
    20.27Outstanding, end of year
    
    
    
    1,270,750
    
    
    $
    19.38
    
    
    
    
    868,042
    
    
    $
    20.13
 Trust Unit Rights Incentive Plan
   2008
    
    
    
    2007Number
    
    
    Weighted
    
    
    
    Number
    
    
    WeightedTrust Unit Rights
    
    
    of rights
    
    
    average price
    
    
    
    of rights
    
    
    average priceOutstanding, beginning of year
    
    
    
    2,250,056
    
    
    $
    17.39
    
    
    
    
    1,534,241
    
    
    $
    16.06Granted(1)
    
    
    
    1,703,892
    
    
    $
    17.96
    
    
    
    
    1,259,562
    
    
    $
    19.75Forfeited
    
    
    
    (397,469
    )
    
    $
    17.49
    
    
    
    
    (199,822
    )
    
    $
    14.63Exercised
    
    
    
    (263,857
    )
    
    $
    14.55
    
    
    
    
    (343,925
    )
    
    $
    11.35Outstanding, end of year
    
    
    
    3,292,622
    
    
    $
    16.78
    
    
    
    
    2,250,056
    
    
    $
    17.39Exercisable, end of year
    
    
    
    1,950,375
    
    
    $
    16.52
    
    
    
    
    1,317,296
    
    
    $
    16.30
 
 (1)
    
    Weighted average exercise price of rights granted are based on the exercise price at
the date of grant.  Rights Outstanding
    
    
    Rights ExercisableWeighted average
    
    
    Weighted
    
    
    
    
    
    
    Weightedremaining
    
    
    average
    
    
    
    
    
    
    averageNumber
    
    
    contractual
    
    
    exercise
    
    
    Number
    
    
    exerciseRange of exercise prices
    
    
    outstanding
    
    
    life (years)
    
    
    price
    
    
    exercisable
    
    
    price$10.00 to $13.99
    
    
    
    544,386
    
    
    
    0.3
    
    
    $
    12.13
    
    
    
    447,656
    
    
    $
    11.96$14.00 to $17.99
    
    
    
    2,351,560
    
    
    
    2.7
    
    
    $
    17.40
    
    
    
    1,128,871
    
    
    $
    17.35$18.00 to $22.15
    
    
    
    396,676
    
    
    
    0.3
    
    
    $
    19.45
    
    
    
    373,848
    
    
    $
    19.46$10.00 to $22.15
    
    
    
    3,292,622
    
    
    
    3.2
    
    
    $
    16.78
    
    
    
    1,950,375
    
    
    $
    16.52




---



##### 



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




---



##### 



2008
    
    
    
    2007Accumulated earnings
    
    
    $
    2,071,188
    
    
    
    $
    1,675,338Accumulated distributions declared
    
    
    
    (4,012,709
    )
    
    
    
    (3,361,694
    )$
    (1,941,521
    )
    
    
    $
    (1,686,356
    )
  Distributions paid
   2008
    
    
    
    2007Unrealized foreign exchange loss (gain) on translation of U.S. dollar denominated debt
    
    
    $
    181,856
    
    
    
    $
    (57,820
    )Unrealized foreign exchange gain on translation of U.K. pound denominated debt
    
    
    
    (9,230
    )
    
    
    
    (16,120
    )$
    172,626
    
    
    
    $
    (73,940
    )Unrealized loss on foreign exchange risk management contracts
    
    
    
    24,533
    
    
    
    
    8,067$
    197,159
    
    
    
    $
    (65,873
    )Realized foreign exchange (gain) loss
    
    
    
    (7,987
    )
    
    
    
    4,016$
    189,172
    
    
    
    $
    (61,857
    )
  CHANGE IN NON-CASH OPERATING WORKING CAPITAL
 Cash provided by (used for):
    
    
    2008
    
    
    
    2007Accounts receivable
    
    
    $
    9,452
    
    
    
    $
    (34,707
    )Accounts payable and accrued liabilities
    
    
    
    23,536
    
    
    
    
    21,699Due from Pengrowth Management Limited
    
    
    
    108
    
    
    
    
    (2,832
    )Net working capital on acquisition
    
    
    
    (5,548
    )
    
    
    
    $
    27,548
    
    
    
    $
    (15,840
    )
 CHANGE IN NON-CASH INVESTING WORKING CAPITAL
 Cash provided by (used for):
    
    
    2008
    
    
    
    2007Accounts payable and capital accruals
    
    
    $
    (1,799
    )
    
    
    $
    (3,821
    )
 CASH INTEREST PAYMENTS
 2008
    
    
    
    2007Interest on long term debt
    
    
    $
    66,267
    
    
    
    $
    58,192Interest on bank indebtedness
    
    
    
    
    
    
    
    
    13,876$
    66,267
    
    
    
    $
    72,068




---



##### 



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




---



##### 



($ thousands)
    
    
    December 31,
    
    
    
    December 31,As at:
    
    
    2008
    
    
    
    2007Term credit facilities
    
    
    $
    372,000
    
    
    
    $
    513,998Senior unsecured notes
    
    
    
    1,152,503
    
    
    
    
    689,238Working
capital deficit
    
    
    
    70,159
    
    
    
    
    189,603Convertible debentures
    
    
    
    74,915
    
    
    
    
    75,030Total debt including convertible debentures
    
    
    $
    1,669,577
    
    
    
    $
    1,467,869
    RISK MANAGEMENT OVERVIEW
   MARKET RISK
  Commodity Price Risk




---



##### 



Remaining term
    
    
    Volume (bbl/d)
    
    
    Reference Point
    
    
    Price per bblFinancial:Jan 1, 2009  Dec 31, 2009
    
    
    
    13,000
    
    
    WTI
    (1)
    
    $86.34 CdnJan 1, 2010  Dec 31, 2010
    
    
    
    6,500
    
    
    WTI
    (1)
    
    $93.19 CdnJan 1, 2011  Nov 30, 2011
    
    
    
    500
    
    
    WTI
    (1)
    
    $82.30 Cdn
 (1)
    
    Associated Cdn $/U.S.$ foreign exchange rate has been fixed  Volume
    
    
    Reference
    
    
    Price perRemaining term
    
    
    (mmbtu/d)
    
    
    Point
    
    
    mmbtuFinancial:Jan 1, 2009  Dec 31, 2009
    
    
    
    10,000
    
    
    NYMEX
    (1)
    
    $8.50 CdnJan 1, 2009  Dec 31, 2009
    
    
    
    49,760
    
    
    AECO
    
    
    $7.76 CdnJan 1, 2009  Dec 31, 2009
    
    
    
    15,000
    
    
    Chicago MI
    (1)
    
    $8.45 CdnJan 1, 2010  Dec 31, 2010
    
    
    
    16,587
    
    
    AECO
    
    
    $8.64 Cdn
 (1)
    
    Associated Cdn $/U.S. $ foreign exchange rate has been fixed   Commodity Risk Management Contracts
    
    
    2008
    
    
    
    2007Current portion of unrealized risk management assets
    
    
    $
    122,841
    
    
    
    $
    8,034Non-current portion of unrealized risk management assets
    
    
    
    41,851
    
    
    
    
    66Current portion of unrealized risk management (liabilities)
    
    
    
    
    
    
    
    
    (70,694
    )Non-current portion of unrealized risk management (liabilities)
    
    
    
    
    
    
    
    
    (22,613
    )Total unrealized risk management (liabilities) assets at year end
    
    
    $
    164,692
    
    
    
    $
    (85,207
    )
 2008
    
    
    
    2007Total unrealized risk management (liabilities) assets at year end
    
    
    $
    164,692
    
    
    
    $
    (85,207
    )Less: Unrealized risk management (liabilities) assets at beginning of year
    
    
    
    (85,207
    )
    
    
    
    37,100Unrealized (loss) gain on risk management contracts for the year
    
    
    $
    249,899
    
    
    
    $
    (122,307
    )




---



##### 



Remaining Term
    
    
    Volume (mmbtu/d)
    
    
    Price per mmbtuJan 1, 2009  Apr 30, 2009
    
    
    
    3,886
    
    
    $2.40 Cdn
    Foreign Exchange Risk
     Foreign Exchange Risk Management Contracts
    
    
    2008
    
    
    
    2007Current portion of unrealized risk management liabilities
    
    
    
    (2,706
    )
    
    
    
    (152
    )Non-current portion of unrealized risk management (liabilities) assets
    
    
    
    (16,021
    )
    
    
    
    5,958Total unrealized risk management (liabilities) assets at year end
    
    
    $
    (18,727
    )
    
    
    $
    5,8062008
    
    
    
    
    2007Total unrealized risk management (liabilities) assets at year end
    
    
    $
    (18,727
    )
    
    
    $
    5,806Less: Unrealized risk management assets at beginning of year
    
    
    
    5,806
    
    
    
    
    13,873Unrealized loss on risk management contracts for the year
    
    
    $
    (24,533
    )
    
    
    $
    (8,067
    )




---



##### 



Cdn $0.01 Exchange Rate ChangeForeign Exchange Sensitivity
    
    
    Cdn - U.S.
    
    
    Cdn - U.K.Unrealized foreign exchange gain or loss
    
    
    $
    8,650
    
    
    $
    500Unrealized foreign exchange risk management gain or loss
    
    
    
    
    
    
    
    577
 Interest Rate Risk
  Interest Rate Sensitivity
  Equity Price Risk
  FAIR VALUE




---



##### 



2008
    
    
    
    2007As at December 31, 2008
    
    
    Carrying Amount
    
    
    Fair Value
    
    
    
    Carrying Amount
    
    
    Fair ValueFinancial AssetsRemediation Trust Funds
    
    
    $
    27,122
    
    
    $
    26,948
    
    
    
    $
    18,094
    
    
    $
    18,107Financial LiabilitiesU.S. dollar denominated senior unsecured notes
    
    
    $
    1,049,218
    
    
    $
    1,213,723
    
    
    
    $
    591,794
    
    
    $
    627,674Cdn dollar senior unsecured notes
    
    
    $
    15,000
    
    
    $
    16,075
    
    
    
    
    
    
    
    
    U.K. Pound Sterling denominated unsecured notes
    
    
    $
    88,285
    
    
    $
    95,495
    
    
    
    $
    97,444
    
    
    $
    96,181Convertible debentures
    
    
    $
    74,915
    
    
    $
    68,014
    
    
    
    $
    75,030
    
    
    $
    74,741
 CREDIT
RISK
    LIQUIDITY RISK




---



##### 



Carrying
    
    
    Contractual
    
    
    within
    
    
    
    
    
    
    
    
    
    
    More thanDecember 31, 2008
    
    
    Amount
    
    
    Cash Flows
    
    
    1 year
    
    
    1-2 years
    
    
    2-5 years
    
    
    5 yearsCdn dollar revolving credit facility(1)
    
    
    $
    372,000
    
    
    $
    393,919
    
    
    $
    8,630
    
    
    $
    8,630
    
    
    $
    376,658
    
    
    $
    Cdn dollar senior unsecured notes(1)
    
    
    
    15,000
    
    
    
    24,556
    
    
    
    992
    
    
    
    992
    
    
    
    2,975
    
    
    
    19,599U.S. dollar denominated senior
unsecured notes(1)
    
    
    
    1,049,218
    
    
    
    1,570,918
    
    
    
    65,805
    
    
    
    65,805
    
    
    
    414,482
    
    
    
    1,024,826U.K. Pound Sterling denominated
unsecured notes(1)
    
    
    
    88,285
    
    
    
    122,286
    
    
    
    4,847
    
    
    
    4,847
    
    
    
    14,541
    
    
    
    98,052Convertible debentures(1)
    
    
    
    74,915
    
    
    
    84,457
    
    
    
    4,858
    
    
    
    79,599
    
    
    
    
    
    
    
    Remediation trust fund payments
    
    
    
    
    
    
    
    12,500
    
    
    
    250
    
    
    
    250
    
    
    
    750
    
    
    
    11,250Foreign Exchange Risk
Management Contracts
Cash Outflow (Inflow)
    
    
    
    18,727
    
    
    
    210
    
    
    
    30
    
    
    
    30
    
    
    
    90
    
    
    
    60
 (1)
    
    Contractual cash flows include future interest payments calculated at period end exchange rates
and interest rates.  2009
    
    
    2010
    
    
    2011
    
    
    2012
    
    
    2013
    
    
    Thereafter
    
    
    TotalOperating leases
    
    
    $
    11,098
    
    
    $
    10,750
    
    
    $
    9,907
    
    
    $
    8,157
    
    
    $
    8,176
    
    
    $
    31,735
    
    
    $
    79,823
       Remaining term
    
    
    Volume (bbl/d)
    
    
    Reference Point
    
    
    Price per bblFinancial:Mar 1, 2009  Dec 31, 2009
    
    
    
    500
    
    
    WTI
    (1)
    
    $58.00 CdnApril 1, 2009  Dec 31, 2009
    
    
    
    1,000
    
    
    WTI
    (1)

    
    $57.78 CdnJan 1, 2010  Dec 31, 2010
    
    
    
    5,000
    
    
    WTI
    (1)

    
    $69.06 Cdn
 (1)
    
    Associated Cdn $/U.S. $ foreign exchange rate has been fixed




---



##### 








---



##### 



2008
    
    
    
    2007Number
    
    
    Intrinsic
    
    
    
    Number
    
    
    IntrinsicExercised
    
    
    Value
    
    
    
    Exercised
    
    
    ValueDEUs
    
    
    
    202,020
    
    
    $
    4,511
    
    
    
    
    2,931
    
    
    $
    58Trust Unit Rights
    
    
    
    263,857
    
    
    
    1,271
    
    
    
    
    343,925
    
    
    
    2,837Trust Unit Options
    
    
    
    26,506
    
    
    
    64
    
    
    
    
    6,690
    
    
    
    32Total
    
    
    
    492,383
    
    
    $
    5,846
    
    
    
    
    353,546
    
    
    $
    2,927
  Trust Units
    
    
    Trust UnitAt December 31, 2008
    
    
    Options
    
    
    Rights
    
    
    DEUsNumber vested and expected to vest
    
    
    
    1,700
    
    
    
    3,158,397
    
    
    
    1,117,550Weighted average exercise price per unit(1)
    
    
    $
    14.95
    
    
    $
    16.76
    
    
    $
    Aggregate intrinsic value(2)
    
    
    $
    
    
    
    $
    
    
    
    $
    10,449Weighted average remaining life (years)
    
    
    
    0.5
    
    
    
    3.20
    
    
    
    1.4
 Trust Units
    
    
    Trust UnitAt December 31, 2007
    
    
    Options
    
    
    Rights
    
    
    DEUsNumber vested and expected to vest
    
    
    
    66,318
    
    
    
    2,088,505
    
    
    
    921,480Weighted average exercise price per unit(1)
    
    
    $
    15.25
    
    
    $
    17.26
    
    
    $
    Aggregate intrinsic value(2)
    
    
    $
    157
    
    
    $
    756
    
    
    $
    16,236Weighted average remaining life (years)
    
    
    
    0.8
    
    
    
    3.3
    
    
    
    1.5
 (1)
    
    No proceeds are received upon exercise of DEUs(2)
    
    Based on December 31 closing trust unit price.  Trust Units
    
    
    Trust UnitAt December 31, 2008
    
    
    Options
    
    
    Rights
    
    
    DEUsNumber exercisable(1)
    
    
    
    1,700
    
    
    
    1,950,375
    
    
    
    2,209Weighted average exercise price per unit(2)
    
    
    $
    14.95
    
    
    $
    16.52
    
    
    $
    Aggregate intrinsic value(3)
    
    
    $
    
    
    
    $
    
    
    
    $
    25Weighted average remaining life (years)
    
    
    
    0.5
    
    
    
    2.70
    
    
    
    
 Trust Units
    
    
    Trust UnitAt December 31, 2007
    
    
    Options
    
    
    Rights
    
    
    DEUsNumber exercisable
    
    
    
    66,318
    
    
    
    1,317,296
    
    
    
    Weighted average exercise price per unit(1)
    
    
    $
    15.25
    
    
    $
    16.30
    
    
    $
    Aggregate intrinsic value(2)
    
    
    $
    157
    
    
    $
    1,743
    
    
    $
    Weighted average remaining life (years)
    
    
    
    0.8
    
    
    
    3.3
    
    
    
    
 (1)
    
    DEUs exercisable at December 31, 2008 were granted to employees on long-term leave on vesting
date. DEUs will be exercised upon return from long-term leave or termination from the plan. No DEUs
were exercisable at December 31, 2007(2)
    
    No proceeds are received upon exercise of DEUs.(3)
    
    Based on December 31 closing price.




---



##### 



2008
    
    
    
    2007Balance, January 1
    
    
    $
    17,810
    
    
    
    $
    Additions based on tax positions in the year
    
    
    
    3,859
    
    
    
    
    17,810Decrease due to change in tax rates
    
    
    
    (430
    )
    
    
    
    Balance, December 31
    
    
    $
    21,239
    
    
    
    $
    17,810
  Jurisdiction
    
    
    YearsFederal
    
    
    
    2004  2008Alberta, British Columbia, Saskatchewan, and Nova Scotia
    
    
    
    2004  2008




---



##### 



Fair Value Measurements Using:Quoted Prices in
    
    
    Significant
    
    
    SignificantCarrying
    
    
    
    
    
    
    Active Markets
    
    
    Other Observable
    
    
    UnobservableAs at December 31, 2008
    
    
    Amount
    
    
    Fair Value
    
    
    (Level 1)
    
    
    Inputs (Level 2)
    
    
    Inputs (Level 3)Financial AssetsRemediation trust funds
    
    
    $
    27,122
    
    
    $
    26,948
    
    
    $
    26,948
    
    
    $
    
    
    
    $
    Fair value of risk
management contracts
    
    
    
    164,692
    
    
    
    164,692
    
    
    
    
    
    
    
    164,692
    
    
    
    Other Assets- Investment in Result Energy Inc
    
    
    
    624
    
    
    
    624
    
    
    
    624
    
    
    
    
    
    
    
    Financial LiabilitiesU.S. dollar denominated debt
    
    
    
    1,049,218
    
    
    
    1,213,723
    
    
    
    
    
    
    
    1,213,723
    
    
    
    U.K. PoundSterling denominated debt
    
    
    
    88,285
    
    
    
    95,495
    
    
    
    
    
    
    
    95,495
    
    
    
    Canadian dollar denominated debt
    
    
    
    15,000
    
    
    
    16,074
    
    
    
    
    
    
    
    16,074
    
    
    
    Convertible debentures
    
    
    
    74,915
    
    
    
    68,014
    
    
    
    68,014
    
    
    
    
    
    
    
    Fair value of risk management contracts
    
    
    
    18,727
    
    
    
    18,727
    
    
    
    
    
    
    
    18,727
    
    
    
    
 Fair Value Measurements Using:Quoted Prices in
    
    
    Significant
    
    
    SignificantCarrying
    
    
    
    
    
    
    Active Markets
    
    
    Other Observable
    
    
    UnobservableAs at December 31, 2007
    
    
    Amount
    
    
    Fair Value
    
    
    (Level 1)
    
    
    Inputs (Level 2)
    
    
    Inputs (Level 3)Financial Assets
Remediation trust funds
    
    
    $
    18,094
    
    
    $
    18,107
    
    
    $
    18,107
    
    
    $
    
    
    
    $
    Fair value of risk
management contracts
    
    
    
    14,058
    
    
    
    14,058
    
    
    
    
    
    
    
    14,058
    
    
    
    Financial LiabilitiesU.S. dollar denominated debt
    
    
    
    591,794
    
    
    
    627,674
    
    
    
    
    
    
    
    627,674
    
    
    
    U.K. Pound Sterling
denominated debt
    
    
    
    97,444
    
    
    
    96,181
    
    
    
    
    
    
    
    96,181
    
    
    
    Convertible debentures
    
    
    
    75,030
    
    
    
    74,741
    
    
    
    74,741
    
    
    
    
    
    
    
    Fair value of risk
management contracts
    
    
    
    93,459
    
    
    
    93,459
    
    
    
    
    
    
    
    93,459
    
    
    
    




---



##### 



LEVEL 1 FAIR VALUE MEASUREMENTS
    LEVEL 2 FAIR VALUE MEASUREMENTS




---



##### 



Years ended December 31
    
    
    2008
    
    
    
    2007Net income for the period, as reported
    
    
    $
    395,850
    
    
    
    $
    359,652Adjustments:Depletion and depreciation (a)
    
    
    
    24,735
    
    
    
    
    35,761Ceiling test write-down (a)
    
    
    
    (1,529,935
    )
    
    
    
    Deferred foreign exchange loss
    
    
    
    
    
    
    
    
    (242
    )Amortization of discontinued hedge (b)
    
    
    
    272
    
    
    
    
    272Non-cash interest on convertible debentures (f)
    
    
    
    40
    
    
    
    
    69Future tax adjustments
    
    
    
    421,369
    
    
    
    
    69,040Net (loss) income  U. S. GAAP
    
    
    $
    (687,669
    )
    
    
    $
    464,552Other comprehensive (loss) income:Amortization of discontinued hedge (b)
    
    
    
    (272
    )
    
    
    
    (272
    )Comprehensive (loss) income  U. S. GAAP
    
    
    $
    (687,941
    )
    
    
    $
    464,280Net (Loss) Income  U. S. GAAP  basic and diluted
    
    
    $
    (2.75
    )
    
    
    $
    1.89
    IncreaseAs at December 31, 2008
    
    
    As Reported
    
    
    (Decrease)
    
    
    U. S. GAAPAssetsProperty, plant and equipment (a)
    
    
    $
    4,251,381
    
    
    $
    (1,751,873
    )
    
    $
    2,499,508Future income taxes (d)(g)
    
    
    
    
    
    
    
    183,366
    
    
    
    183,366$
    (1,568,507
    )LiabilitiesConvertible debentures (f)
    
    
    $
    74,915
    
    
    $
    80
    
    
    $
    74,995Future income taxes (d) (g)
    
    
    
    328,282
    
    
    
    (328,282
    )
    
    
    Other long term liabilities (g)
    
    
    
    
    
    
    
    21,239
    
    
    
    21,239Unitholders equity (c):Accumulated other comprehensive income (b)
    
    
    $
    
    
    
    $
    1,902
    
    
    $
    1,902Trust unitholders equity (a)
    
    
    
    2,663,805
    
    
    
    (1,263,446
    )
    
    
    1,400,359$
    (1,568,507
    )




---



##### 



IncreaseAs at December 31, 2007
    
    As Reported
    
    
    (Decrease)
    
    
    U. S. GAAPAssetsProperty, plant and equipment (a)
    
    $
    4,306,682
    
    
    $
    (246,673
    )
    
    $
    4,060,009$
    (246,673
    )LiabilitiesConvertible debentures (f)
    
    $
    75,030
    
    
    $
    120
    
    
    $
    75,150Future income taxes (d)(g)
    
    
    387,100
    
    
    
    (86,850
    )
    
    
    300,250Other long term liabilities (g)
    
    
    
    
    
    
    17,810
    
    
    
    17,810Unitholders equity (c):Accumulated other comprehensive income (b)
    
    $
    
    
    
    $
    2,174
    
    
    $
    2,174Trust unitholders equity (a)
    
    
    2,756,220
    
    
    
    (179,927
    )
    
    
    2,576,293$
    (246,673
    )
   As at December 31
    
    
    2008
    
    
    
    2007Trade
    
    
    $
    159,274
    
    
    
    $
    179,253Prepaid
    
    
    
    37,857
    
    
    
    
    27,330$
    197,131
    
    
    
    $
    206,583
  As at December 31
    
    
    2008
    
    
    
    2007Accounts payable
    
    
    $
    94,799
    
    
    
    $
    93,180Accrued liabilities
    
    
    
    166,029
    
    
    
    
    145,911$
    260,828
    
    
    
    $
    239,091




---



##### 



APPENDIX D
 OIL AND GAS PRODUCING ACTIVITIES PREPARED IN ACCORDANCE WITH SFAS NO. 69  DISCLOSURES ABOUT OIL
AND GAS PRODUCING ACTIVITIES




---



##### 



SUPPLEMENTAL INFORMATION  OIL AND GAS PRODUCING ACTIVITIES
(unaudited)
  OIL AND GAS RESERVES




---



##### 



RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
  2008
    
    
    2007RevenueSales
    
    $
    1,500,604
    
    
    $
    1,422,148DeductProduction costs
    
    
    (394,532
    )
    
    
    (378,216
    )Transportation costs
    
    
    (12,519
    )
    
    
    (12,672
    )Amortization of injectant costs
    
    
    (25,876
    )
    
    
    (34,063
    )Technical support and other
    
    
    (23,965
    )
    
    
    (28,306
    )Depletion, depreciation and amortization
    
    
    (596,176
    )
    
    
    (603,323
    )Results of operations from producing activities
    
    $
    447,536
    
    
    $
    365,568
 
 1.
    
    The costs in this schedule exclude corporate overhead, interest expense and other operating
costs which are not directly related to producing activities. COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
  2008
    
    
    2007Property acquisition costsProved
    
    $
    182,401
    
    
    $
    986,148Unproved
    
    
    
    
    
    
    383,355Exploration costs
    
    
    22,012
    
    
    
    21,192Development costs
    
    
    365,304
    
    
    
    261,866Injectants costs
    
    
    21,009
    
    
    
    26,052$
    590,726
    
    
    $
    1,678,613




---



##### 



CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
  2008
    
    
    2007Oil and gas properties
    
    $
    7,079,703
    
    
    $
    6,534,343Less accumulated depletion, depreciation and amortization
    
    
    (4,635,531
    )
    
    
    (2,529,218
    )Net capitalized costs
    
    $
    2,444,172
    
    
    $
    4,005,125Unproved oil and gas properties
    
    $
    484,426
    
    
    $
    1,056,851Proven oil and gas properties
    
    
    1,959,746
    
    
    
    2,948,274Net capitalized costs
    
    $
    2,444,172
    
    
    $
    4,005,125
 OIL AND GAS RESERVE INFORMATION




---



##### 



NET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIES
 Crude Oil
    
    
    Naturaland NGLs
    
    
    GasMMbbl
    
    
    BcfEnd of year 2006
    
    
    102.2
    
    
    
    491.9Revisions of previous estimates
(including infill
drilling & improved recovery)
    
    
    4.5
    
    
    
    34.2Purchase of reserves in
place
    
    
    20.6
    
    
    
    133.4Sale of reserves in
place
    
    
    -4.3
    
    
    
    -79.9Discoveries and
extensions
    
    
    1.1
    
    
    
    27.1Production
    
    
    -12.6
    
    
    
    -78.0End of year 2007
    
    
    111.5
    
    
    
    528.7Revisions of previous estimates
(including infill drilling &
improved recovery)
    
    
    3.6
    
    
    
    40.3Purchase of reserves in
place
    
    
    2.6
    
    
    
    16.1Sale of reserves in
place
    
    
    0.0
    
    
    
    -1.0Discoveries and
extensions
    
    
    1.3
    
    
    
    12.3Production
    
    
    -12.3
    
    
    
    -71.5End of year 2008
    
    
    106.7
    
    
    
    524.9
 NET PROVED DEVELOPED RESERVES AFTER ROYALTIES
 Crude Oil
    
    Naturaland NGLs
    
    GasMMbbl
    
    BcfEnd of year 2006
    
    
    84.1
    
    
    
    453.1End of year 2007
    
    
    93.0
    
    
    
    474.9End of year 2008
    
    
    87.9
    
    
    
    474.4
 
 Notes:1.
    
    Net after royalty reserves are the Trusts lessor royalty, overriding royalty, and working
interest share of the gross remaining reserves, after deduction of any crown, freehold and
overriding royalties. Crown royalties are subject to change by legislation or regulation and
vary depending on production rates, selling prices and potentially timing of initial
production.2.
    
    Reserves are the estimated quantities of crude oil, natural gas and related substances
anticipated from geological and engineering data to be recoverable from known accumulations,
from a given date forward, by known technology, under existing operating conditions and prices
in effect at year end.3.
    
    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing economic and
operating conditions.4.
    
    Proved developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Proved undeveloped
reserves are reserves that are expected to be recovered from known accumulations where a
significant expenditure is required.




---



##### 



STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS
RESERVES
     STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES
  2008
    
    
    2007Future cash inflows
    
    $
    8,843
    
    
    $
    12,796Future costsFuture production and development costs
    
    
    (5,409
    )
    
    
    (4,957
    )Future income taxes
    
    
    (635
    )
    
    
    (2,000
    )Future net cash flows
    
    
    2,799
    
    
    
    5,839Deduct: 10% annual discount factor
    
    
    (1,012
    )
    
    
    (2,149
    )Standardized measure of discounted future net cash flows
    
    $
    1,787
    
    
    $
    3,690




---



##### 



CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS
RESERVES
  2008
    
    
    2007$MM
    
    
    $MMFuture discounted net cash flow at beginning of year
    
    
    3,690
    
    
    
    3,166Sales & transfer, net of production costs
    
    
    (1,044
    )
    
    
    (970
    )Net change in sales & transfer prices
    
    
    (2,406
    )
    
    
    1,111Development costs incurred during the period
    
    
    362
    
    
    
    271Change in future development costs
    
    
    (371
    )
    
    
    (346
    )Change due
to extensions, discoveries and improved recovery
    
    
    33
    
    
    
    130Change due to revisions (including infill drilling)
    
    
    111
    
    
    
    234Accretion of discount
    
    
    459
    
    
    
    317Sales of reserves in place
    
    
    (4
    )
    
    
    (303
    )Purchase of reserves in place
    
    
    56
    
    
    
    983Net change in Income Taxes
    
    
    616
    
    
    
    (895
    )Changes in timing of future net cash flow and other
    
    
    285
    
    
    
    (8
    )Future discounted net cash flow at end of year
    
    
    1,787
    
    
    
    3,690
 
 Note:1.
    
    The schedules above are calculated using year-end prices, costs, statutory tax rates and
proved oil and gas reserves. The value of exploration properties and probable reserves, future
exploration costs, future changes in oil and gas prices and in production and development
costs are excluded.




---



##### 



APPENDIX
E
 PENGROWTH ENERGY TRUST CODE OF BUSINESS CONDUCT AND ETHICS
DATED FEBRUARY 17, 2009




---



##### 



February 17, 2009




---



##### 



TABLE OF CONTENTS
 PageApplication
    
    
    1Purpose
    
    
    1Policy
    
    
    1Compliance with the Law
    
    
    2Health, Safety and the Environment
    
    
    3Public Reporting
    
    
    3Conflict of Interest
    
    
    4Private Business
    
    
    5Payments
    
    
    5Political Contributions
    
    
    6Involvement with Not-for-Profit Organizations
    
    
    6Outside Employment
    
    
    6Directorships
    
    
    7Government Relations
    
    
    7Confidential Information
    
    
    7Company Information
    
    
    7Inside Information
    
    
    8Books of Account
    
    
    9Patents and Inventions
    
    
    9Community Relations
    
    
    9Company Property and Opportunities
    
    
    10Accounting and Financial Reporting
    
    
    10Employee Relations and Reporting
    
    
    10Policies, Procedures and Internal Controls
    
    
    10Acknowledgement
    
    
    11Exceptions and Changes
    
    
    11Appendix A Complaint Procedures For Accounting, Financial Reporting
and Auditing Matters and Violations of the Code of Business Conduct
and Ethics
    
    
    12Appendix B Awareness Statement on Code of Business Conduct and Ethics
    
    
    15




---



##### 



Application
 Code Member Pengrowth
 Purpose
   
    
    assure compliance with laws and regulations that govern the business activities of
Pengrowth;
    
    maintain a corporate climate in which the integrity and dignity of each individual
is valued;
    
    foster a standard of conduct that reflects positively on Pengrowth; and
    
    protect Pengrowth from unnecessary exposure to financial loss.
   Policy
  Page 1




---



##### 



Compliance with the Law
      Page 2




---



##### 



Health, Safety and the Environment
     Public Reporting
  Page 3




---



##### 




    
    all accounting records, and the reports produced from such records, must be in accordance
with all applicable laws;
    
    all accounting records must fairly and accurately reflect the transactions or occurrences
to which they relate;
    
    all accounting records must fairly and accurately reflect in reasonable detail Pengrowths
assets, liabilities, revenues and expenses;
    
    no accounting records should contain any false or intentionally misleading entries;
    
    no transactions should be intentionally misclassified as to accounts, departments or
accounting periods;
    
    all transactions must be supported by accurate documentation in reasonable detail and
recorded in the proper account and in the proper accounting period;
    
    no information should be concealed from the internal auditors or the independent auditors;
and
    
    compliance with Pengrowths system of internal controls is required.
 Conflict of Interest
    Page 4




---



##### 



Private Business
   Payments
    Page 5




---



##### 



Ø
    
    they are not in cash or securities and are of nominal value;Ø
    
    they do not contravene any law and are made as a matter of general and accepted
practice or in accordance with corporate policy; andØ
    
    if subsequently disclosed to the public, they would not in any way embarrass
Pengrowth or their recipients.
  Political Contributions
  (a)
    
    any such contribution may only be made to a political party and not to an
individual candidate for election to public office;(b)
    
    any such contribution requires the approval of the Chief Executive Officer; and(c)
    
    any such contribution must be within the approved operating budget of Pengrowth.
  Involvement with Not-for-Profit Organizations
  Outside Employment
  Page 6




---



##### 



Directorships
  Government Relations
  Confidential Information
   Company Information
    Page 7




---



##### 



Inside Information
      If you have knowledge of a material fact, pending change of fact, or
material change related to the affairs of Pengrowth or any public
issuer involved in a transaction with Pengrowth which is not
generally known, no purchase or sale may be made until the knowledge
has been made public. In addition, this knowledge must not be
conveyed to any other person for the purpose of assisting that
person in trading securities.
 Page 8




---



##### 



Policy on Trading in Securities
 Books of Account
  Patents and Inventions
   Community Relations
 Corporate
Disclosure Policy
 Page 9




---



##### 



Company Property and Opportunities
  Accounting and Financial Reporting
   Employee Relations and Reporting
     Policies, Procedures and Internal Controls
  Page 10




---



##### 



Acknowledgement
   personal
 Exceptions and Changes
   Page 11




---



##### 



Appendix A
Complaint Procedures
For Accounting, Financial Reporting and Auditing Matters
and Violations of the Code of Business Conduct and Ethics
    Receipt of Complaints
 
    
    Directors, officers and employees with concerns regarding an Accounting Matter may report
their concerns to the chairman of the Audit Committee.
    
    Directors, officers, employees, consultants or contractors with concerns regarding a
Conduct Matter may report their concerns to the chairman of the Corporate Governance
Committee.
    
    Directors, officers and employees may report concerns regarding an Accounting Matter or a
Conduct Matter on a confidential or anonymous basis to Grant Thornton LLP, at 1-888-747-7171
or usecare@GrantThornton.ca.
    
    A director, officer or employee who makes an anonymous submission must be sure to provide
sufficient detail to identify the concern being raised. Because the submission is made
anonymously, the Audit Committee or the Corporate Governance Committee, as the case may be,
will be unable to follow up if there are additional questions. The complaint should, at a
minimum, contain dates, places, persons involved and witnesses such that a reasonable
investigation or assessment can be conducted.
 Scope of Accounting Matters Covered by These Procedures
  Page 12




---



##### 




    
    fraud or deliberate error in the preparation, evaluation, review or audit of any financial
statement of Pengrowth;
    
    fraud or deliberate error in the recording and maintaining of financial records of
Pengrowth;
    
    deficiencies in or non-compliance with Pengrowths internal accounting controls;
    
    misrepresentation or false statement to or by a director, officer, employee or external
accountant regarding a matter contained in the financial records, financial reports or audit
reports of Pengrowth; or
    
    deviation from full and fair reporting of Pengrowths financial condition.
 Treatment of Complaints
 
    
    Grant Thornton LLP shall inform (i) the chairman of the Audit Committee of all complaints
and concerns provided to it in respect of Accounting Matters; and (ii) the chairman of the
Corporate Governance Committee of all complaints provided to it in respect of Conduct Matters.
    
    Upon receipt of a complaint or concern, the chairman of the Audit Committee or chairman of
the Corporate Governance Committee, as the case may be, will (i) determine whether or not the
complaint actually pertains to an Accounting Matter or a Conduct Matter and (ii) when
possible, acknowledge receipt of the complaint to the sender.
    
    Complaints relating to an Accounting Matter will be reviewed by the Audit Committee,
outside legal counsel or such other persons as the Audit Committee determines to be
appropriate. Complaints relating to a Conduct Matter will be reviewed by the Corporate
Governance Committee, outside legal counsel and such and the persons as the Corporate
Governance Committee determines to be appropriate. In any case, confidentiality will be
maintained to the fullest extent possible, consistent with the need to conduct an adequate
review.
    
    Prompt and appropriate corrective action will be taken when and as warranted in the
judgment of the Audit Committee or the Corporate Governance Committee, as the case may be.
    
    Pengrowth will not discharge, demote, suspend, threaten, harass or in any manner
discriminate against any individual in the terms and conditions of employment based upon any
lawful actions of such individual with respect to reporting of complaints in good faith
regarding any Accounting Matter or any Conduct Matter.
    
    Pengrowth will regard the making of any deliberately false or malicious allegations by an
employee as a serious offence which may result in recommendations to the Board of Directors or
to senior management of Pengrowth for disciplinary action including dismissal for cause and,
if warranted, legal proceedings.
 Page 13




---



##### 



Reporting and Retention of Complaints and Investigations
 
    
    The chairman of the Audit Committee and the chairman of the Corporate Governance Committee
will maintain a log of all complaints, tracking their receipt, investigation and resolution
and shall prepare a periodic summary report thereof for the Audit Committee or the Corporate
Governance Committee, as the case may be.
  Page 14




---



##### 



Appendix B
Awareness Statement on Code of Business Conduct and Ethics
 To be completed by all directors, officers, employees, consultants and contractors
of Pengrowth Energy Trust and its subsidiaries (Pengrowth)
  1.
    
    I understand the content and consequences of contravening the Code and agree to abide by the
Code.2.
    
    I am in compliance with the Code.3.
    
    All facts and dealings which I believe to be non-compliant with the Code have been
communicated to the appropriate representative of Pengrowth and are detailed below.4.
    
    (If applicable) After due inquiry and to my best knowledge and belief, no employee,
consultant or contractor under my direct supervision is in violation of the Code.5.
    
    I have and will continue to exercise my best efforts to assure full compliance with the Code
by myself and (if applicable) all employees, consultants and contractors under my direct
supervision.
 Print or type name:Signature:Title and location:Date:
 Facts and dealings that I believe to be non-compliant with the Code
  1.2.
  Page 15