##### Table of Contents



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, 2009       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
 Puglisi & Associates
850 Library Avenue, Suite 204
New York, Delaware 19711
(302)738-6680
 
  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
    þ o
  o o




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##### Table of Contents



DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT
  Appendix
    
    DocumentsA
    
    Pengrowth Energy Trust Annual Information Form for the year ended
December 31, 2009.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
    
    Supplemental Unaudited Disclosures
about Oil and Gas Producing Activities required under United States
Generally Accepted Accounting Principles.E
    
    Pengrowth Energy Trust Code of Business Conduct and Ethics dated
November 11, 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




---



##### Table of Contents



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




---



##### Table of Contents



SIGNATURES
  Date:  March 8,
2010
    PENGROWTH ENERGY TRUST
by its Administrator
PENGROWTH CORPORATIONBy:

/s/
Derek W. EvansDerek W. EvansPresident and
Chief Executive Officer




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##### Table of Contents



EXHIBIT INDEX
 Exhibit
    

Description1
    
    Consent of Independent Registered Public Accounting Firm2
    
    Consent of GLJ Petroleum Consultants Ltd.3
    
    Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 13504
    
    Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 13505
    
    Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 19346
    
    Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934




---



##### Table of Contents



APPENDIX
A
 PENGROWTH ENERGY TRUST ANNUAL INFORMATION FORM FOR THE YEAR
ENDED DECEMBER 31, 2009




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##### Table of Contents



PENGROWTH ENERGY TRUST
 ANNUAL INFORMATION FORM
 For the year ended December 31, 2009
 March
8, 2010




---



##### 



TABLE OF CONTENTS
 GLOSSARY OF TERMS AND ABBREVIATIONS
    
    
    1CONVERSION
    
    
    4PRESENTATION OF OUR FINANCIAL INFORMATION
    
    
    5PRESENTATION OF OUR RESERVE INFORMATION
    
    
    5FORWARD-LOOKING STATEMENTS
    
    
    5PENGROWTH ENERGY TRUST
    
    
    7Introduction
    
    
    7The Trust
    
    
    7The Corporation
    
    
    7Intercorporate Relationships
    
    
    8Business Strategy
    
    
    8Recent Developments
    
    
    9Historical Developments  2007 and 2008
    
    
    13Trends
    
    
    14PENGROWTH  OPERATIONAL INFORMATION
    
    
    15Principal Properties
    
    
    15Light Oil Properties
    
    
    16Heavy Oil Properties
    
    
    19Conventional Gas Properties
    
    
    20Shallow Gas Properties
    
    
    23Offshore Gas Properties
    
    
    25Oil Sands Properties
    
    
    25Statement of Oil and Gas Reserves and Reserves Data
    
    
    26Additional Information Relating to Reserves Data
    
    
    36Future Development Costs
    
    
    38Finding, Development and Acquisition Costs
    
    
    38Future Development Capital
    
    
    39Other Oil and Gas Information
    
    
    40Forward Contracts
    
    
    43Additional Information Concerning Abandonment & Reclamation Costs
    
    
    43Costs Incurred
    
    
    43Exploration and Development Activities
    
    
    44Production Estimates
    
    
    44Production History (Netback)
    
    
    45Before Tax Net Asset Value (NAV) at December 31, 2009
    
    
    46TRUST UNITS
    
    
    47The Trust Indenture
    
    
    47The Trustee
    
    
    47Stock Exchange Listings
    
    
    48Ownership Restrictions
    
    
    48Redemption Right
    
    
    49Conversion Rights
    
    
    49Exchangeable Shares
    
    
    49Voting at Meetings of Unitholders
    
    
    49Voting at Meetings of Corporation
    
    
    50Termination of the Trust
    
    
    50Unitholder Limited Liability
    
    
    50THE ROYALTY INDENTURE
    
    
    51Royalty Units
    
    
    51The Royalty
    
    
    51Replacement of Properties
    
    
    52The Trustee
    
    
    52Exhibit 1Exhibit 2Exhibit 3Exhibit 4Exhibit 5Exhibit 6




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DISTRIBUTIONS
    
    
    52General
    
    
    52Historical Distributions
    
    
    52Restrictions on Distributions
    
    
    54CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
    
    
    56Taxation of the Trust
    
    
    56Taxation of Unitholders Resident in Canada
    
    
    57Taxation of Unitholders who are Non-Residents of Canada
    
    
    58UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
    
    
    59Classification of the Trust as a Corporation
    
    
    60Ownership and Disposition of Trust Units
    
    
    60Other Considerations
    
    
    61INDUSTRY CONDITIONS
    
    
    62Government Regulation
    
    
    62Pricing and Marketing  Oil
    
    
    62Pricing and Marketing  Natural Gas
    
    
    62Pricing and Marketing  Natural Gas Liquids
    
    
    63Royalties
    
    
    63Environmental Regulation
    
    
    66Climate Change
    
    
    66RISK FACTORS
    
    
    68MARKET FOR SECURITIES
    
    
    79DIRECTORS AND OFFICERS
    
    
    80Directors and Officers of the Corporation
    
    
    80Corporate Cease Trade Orders or Bankruptcies
    
    
    81Personal Bankruptcies
    
    
    82Penalties or Sanctions
    
    
    82AUDIT COMMITTEE
    
    
    82Principal Accountant Fees and Services
    
    
    83Pre-approval Policies and Procedures
    
    
    83CONFLICTS OF INTEREST
    
    
    84LEGAL PROCEEDINGS
    
    
    84INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    
    
    84INTERESTS OF EXPERTS
    
    
    85AUDITORS, TRANSFER AGENT AND REGISTRAR
    
    
    85MATERIAL CONTRACTS
    
    
    85CODE OF ETHICS
    
    
    85OFF-BALANCE SHEET ARRANGEMENTS
    
    
    86DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
    
    
    86ADDITIONAL INFORMATION
    
    
    86
 Appendix A  Report on Reserves Data by Independent Qualified Reserves Evaluator on Form
51-101F2
 Appendix B   Report of Management and Directors on Oil and Gas Disclosure on Form 51-101F3
 Appendix C   Audit Committee Terms of Reference
 Unless otherwise indicated, all of the information provided in this Annual Information Form is as
at December 31, 2009.
 - iii -




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GLOSSARY OF TERMS AND ABBREVIATIONS
  Corporate
 Board Board of Directors
 Computershare
 Corporation
 Credit Facility
 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
 - 1 -




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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
 - 2 -




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Reserve Life Index
 reserves
 Royalty Interest
 Total
Proved Plus Probable Reserves P+P
 Undeveloped Reserves
 Working Interest
 Abbreviations
 API
 o API
 bbl Mbbl MMbbl Bbbl
 bblpd
 boe Mboe MMboe
 boepd
 bwpd
 CBM
 EOR
 EDGAR
 GAAP Canadian GAAP
 $M $MM
 - 3 -




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MMBtu
 Mcf MMcf Bcf
 Mcfe
 Mcfpd MMcfpd
 NGLs
 NYSE
 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.
 
 CONVERSION
  To Convert From
    
    To
    
    
    Multiply byMcf
    
    cubic metre
    
    
    28.174bbl
    
    cubic metre
    
    
    0.159MMBtu
    
    gigajoule
    
    
    1.0546cubic metre
    
    bbl
    
    
    6.29metre
    
    feet
    
    
    3.281mile
    
    kilometre
    
    
    1.609kilometre
    
    mile
    
    
    0.621acre
    
    hectare
    
    
    0.405
 - 4 -




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PRESENTATION OF OUR FINANCIAL INFORMATION
 www.sec.gov
  
 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 www.sec.gov
 
 FORWARD-LOOKING STATEMENTS
 Private Securities Litigation Reform Act of 1995
 - 5 -




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Risk Factors Business Risks
  - 6 -




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PENGROWTH ENERGY TRUST
 
 Introduction
  
 The Trust
   
 The Corporation
    Pengrowth Energy Trust  Recent Developments  Expiry of the Management Agreement
 - 7 -




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Intercorporate Relationships
  
 
 Business Strategy
 Pengrowth Energy Trust  Recent
Developments  Changes to our Value Creation Strategy
 2
  - 8 -




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
    
    net present value of future cash flow as compared to the capital invested;
    
    rate of return of future cash flows;
    
    potential for continued, repeatable and scalable development; and
    
    investments necessary to maintain existing facilities and wells.
 
 Recent Developments
  2010 Forecast Capital, Production and Operating Costs
   Planned Capital Expenditures
    
    ($ millions)Drill, Complete and Tie-In
    
    $
    192Major Projects (Lindbergh, Horn River)
    
    
    28Land and Seismic
    
    
    8Total Development Capital
    
    $
    228Facilities Maintenance
    
    
    50Total Development Capital Including Facilities
    
    $
    278Other (e.g., IT)
    
    
    7Total Capital
    
    $
    285Average Daily Production Volume (boepd)
    
    
    74,000  76,000
    (1)Operating Costs (per boe)
    
    $
    14.40
    (2)General and Administrative Costs (per boe)
    
    $
    2.23
    (2)
 Notes:
 (1)
    
    The 2010 estimate excludes potential additions arising from acquisitions or reductions from
dispositions.(2)
    
    Assuming production targets for 2010 are achieved.
      - 9 -




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##### Table of Contents



Convertible Debentures
  Equity Financing
  Gross Overriding Royalties Created
  Result Acquisition
  Reduction
in Distributions
  Changes to our Value Creation Strategy
  
    
    Shifting internal capital expenditures on our existing high quality asset base to
focus on existing low cost, low risk plays (Carson Creek, shallow gas, CBM) as well as
to identify, test and develop other resource plays where repeatable, predictable and
scalable results can be achieved.
    
    Increasing capital expenditures as a percentage of cash flow to facilitate higher
reinvestment levels on our existing assets as well as to advance longer term value of
our Lindbergh, EOR and Horn River resource plays.
    
    Adopting a sustainable business model where distributions plus capital expenditures
are equal to cash flow.
    
    Enhancing our low cost culture ensuring a high level of capital efficiency and cost
discipline.
    
    Reducing debt to levels more consistent with energy trust averages projected for the next 18
months.
    
    Acquiring other WCSB assets with low cost, low risk, repeatable, predictable and
scalable drilling opportunities.
    
    Maintaining or modestly growing production and reserves on a debt adjusted per unit
basis.
  - 10 -




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##### Table of Contents



Taxability of Distributions Paid to U.S. Residents
  Expiry of the Management Agreement
  Board of Directors and Management Changes
    Amendments to the Trust Indenture and the Unanimous Shareholder Agreement
  - 11 -




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Trust Units  The Trustee
 SIFT Legislation Considerations
     At-the-Market Equity Distribution Program
  - 12 -




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Historical Developments  2007 and 2008
        - 13 -




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Trends
      Managements Discussion and Analysis  Outlook
 - 14 -




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PENGROWTH  OPERATIONAL INFORMATION
 
 Principal Properties
   Summary of Company Interest
at December 31, 2009 (1)  (Forecast Prices and Costs) (2)
 P+PRemaining
    
    
    Reserve
    
    
    Value BeforeP+P
    
    
    Reserve
    
    
    Life
    
    
    Tax at 10%
    
    
    2009 Oil
    
    
    2009 Gas
    
    
    2009 NGL
    
    
    2009 TotalReserves
    
    
    Life
    
    
    Index
    
    
    Discount
    
    
    Production
    
    
    Production
    
    
    Production
    
    
    ProductionField
    
    (Mboe)(4)
    
    
    (years)
    
    
    (years)
    
    
    ($MM)
    
    
    (bblpd)
    
    
    (MMcfpd)
    
    
    (bblpd)
    
    
    (boepd)(4)Light Oil PropertiesJudy Creek
    
    
    34,085
    
    
    
    50
    
    
    
    13.4
    
    
    
    758.3
    
    
    
    6,221
    
    
    
    5.3
    
    
    
    1,899
    
    
    
    8,998Weyburn
    
    
    21,811
    
    
    
    48
    
    
    
    22.1
    
    
    
    405.1
    
    
    
    2,653
    
    
    
    0.0
    
    
    
    0
    
    
    
    2,652Swan Hills
    
    
    16,684
    
    
    
    50
    
    
    
    18.2
    
    
    
    232.1
    
    
    
    2,058
    
    
    
    2.1
    
    
    
    301
    
    
    
    2,707Carson Creek
    
    
    15,749
    
    
    
    44
    
    
    
    14.4
    
    
    
    264.3
    
    
    
    2,150
    
    
    
    4.3
    
    
    
    247
    
    
    
    3,110Deer Mountain
    
    
    6,000
    
    
    
    47
    
    
    
    20.4
    
    
    
    105.8
    
    
    
    576
    
    
    
    0.1
    
    
    
    73
    
    
    
    672Fenn Big Valley
    
    
    5,799
    
    
    
    50
    
    
    
    9.6
    
    
    
    90.5
    
    
    
    741
    
    
    
    4.9
    
    
    
    78
    
    
    
    1,639Other(3)
    
    
    30,859
    
    
    
    
    
    
    
    10.4
    
    
    
    619.4
    
    
    
    6,768
    
    
    
    6.2
    
    
    
    386
    
    
    
    8,190Subtotal
    
    
    130,987
    
    
    
    
    
    
    
    13.9
    
    
    
    2,475.5
    
    
    
    21,166
    
    
    
    22.9
    
    
    
    2,984
    
    
    
    27,969Heavy Oil PropertiesBodo
    
    
    7,603
    
    
    
    37
    
    
    
    11.4
    
    
    
    139.2
    
    
    
    1,655
    
    
    
    1.4
    
    
    
    0
    
    
    
    1,889Jenner
    
    
    6,756
    
    
    
    24
    
    
    
    6.2
    
    
    
    202.1
    
    
    
    2,900
    
    
    
    2.6
    
    
    
    20
    
    
    
    3,353Tangleflags
    
    
    4,667
    
    
    
    43
    
    
    
    7.3
    
    
    
    72.8
    
    
    
    2,074
    
    
    
    0.3
    
    
    
    0
    
    
    
    2,117Other(3)
    
    
    4,324
    
    
    
    
    
    
    
    7.7
    
    
    
    64.6
    
    
    
    929
    
    
    
    4.3
    
    
    
    0
    
    
    
    1,646Subtotal
    
    
    23,350
    
    
    
    
    
    
    
    7.9
    
    
    
    478.7
    
    
    
    7,559
    
    
    
    8.6
    
    
    
    20
    
    
    
    9,005Conventional Gas PropertiesOlds
    
    
    18,020
    
    
    
    50
    
    
    
    12.6
    
    
    
    224.2
    
    
    
    7
    
    
    
    18.8
    
    
    
    709
    
    
    
    3,849Harmattan
    
    
    17,410
    
    
    
    50
    
    
    
    10.3
    
    
    
    219.2
    
    
    
    393
    
    
    
    18.6
    
    
    
    1,679
    
    
    
    5,172Carson Creek
    
    
    7,920
    
    
    
    19
    
    
    
    4.5
    
    
    
    198.8
    
    
    
    40
    
    
    
    6.6
    
    
    
    1,126
    
    
    
    2,262Dunvegan
    
    
    5,786
    
    
    
    33
    
    
    
    10.3
    
    
    
    77.1
    
    
    
    32
    
    
    
    7.5
    
    
    
    414
    
    
    
    1,698Quirk Creek
    
    
    5,545
    
    
    
    40
    
    
    
    9.2
    
    
    
    76.9
    
    
    
    0
    
    
    
    6.5
    
    
    
    345
    
    
    
    1,430Kaybob
    
    
    3,316
    
    
    
    34
    
    
    
    13.3
    
    
    
    43.5
    
    
    
    0
    
    
    
    4.1
    
    
    
    41
    
    
    
    722Blackstone
    
    
    3,110
    
    
    
    32
    
    
    
    10.3
    
    
    
    32.9
    
    
    
    0
    
    
    
    5.3
    
    
    
    0
    
    
    
    886McLeod River
    
    
    3,083
    
    
    
    47
    
    
    
    8.2
    
    
    
    48.4
    
    
    
    22
    
    
    
    5.5
    
    
    
    214
    
    
    
    1,150Other(3)
    
    
    10,878
    
    
    
    
    
    
    
    7.9
    
    
    
    160.1
    
    
    
    462
    
    
    
    23.5
    
    
    
    391
    
    
    
    4,771Subtotal
    
    
    75,069
    
    
    
    
    
    
    
    9.0
    
    
    
    1,081.1
    
    
    
    956
    
    
    
    96.4
    
    
    
    4,919
    
    
    
    21,939Shallow Gas PropertiesTwining/Three Hills Creek
    
    
    11,779
    
    
    
    50
    
    
    
    10.5
    
    
    
    194.6
    
    
    
    389
    
    
    
    12.4
    
    
    
    342
    
    
    
    2,794Coal Bed Methane
    
    
    9,066
    
    
    
    39
    
    
    
    12.6
    
    
    
    105.9
    
    
    
    0
    
    
    
    12.4
    
    
    
    9
    
    
    
    2,069Monogram
    
    
    6,999
    
    
    
    40
    
    
    
    8.8
    
    
    
    114.5
    
    
    
    0
    
    
    
    15.2
    
    
    
    0
    
    
    
    2,533Jenner
    
    
    6,313
    
    
    
    32
    
    
    
    9.8
    
    
    
    74.7
    
    
    
    21
    
    
    
    10.1
    
    
    
    10
    
    
    
    1,707Lethbridge
    
    
    2,851
    
    
    
    47
    
    
    
    9.2
    
    
    
    33.4
    
    
    
    2
    
    
    
    6.0
    
    
    
    0
    
    
    
    1,005Other(3)
    
    
    13,942
    
    
    
    
    
    
    
    9.7
    
    
    
    163.4
    
    
    
    300
    
    
    
    26.6
    
    
    
    128
    
    
    
    4,864Subtotal
    
    
    50,950
    
    
    
    
    
    
    
    10.1
    
    
    
    686.6
    
    
    
    713
    
    
    
    82.6
    
    
    
    489
    
    
    
    14,971Offshore Gas PropertiesSable Island
    
    
    9,031
    
    
    
    8
    
    
    
    4.4
    
    
    
    146.0
    
    
    
    0
    
    
    
    26.7
    
    
    
    1,178
    
    
    
    5,633Subtotal
    
    
    9,031
    
    
    
    
    
    
    
    4.4
    
    
    
    146.0
    
    
    
    0
    
    
    
    26.7
    
    
    
    1,178
    
    
    
    5,633Oil Sands PropertiesLindbergh
    
    
    6,348
    
    
    
    16
    
    
    
    
    
    
    
    17.0
    
    
    
    0
    
    
    
    0.0
    
    
    
    0
    
    
    
    0
 - 15 -




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##### Table of Contents



P+PRemaining
    
    
    Reserve
    
    
    Value BeforeP+P
    
    
    Reserve
    
    
    Life
    
    
    Tax at 10%
    
    
    2009 Oil
    
    
    2009 Gas
    
    
    2009 NGL
    
    
    2009 TotalReserves
    
    
    Life
    
    
    Index
    
    
    Discount
    
    
    Production
    
    
    Production
    
    
    Production
    
    
    ProductionField
    
    (Mboe)(4)
    
    
    (years)
    
    
    (years)
    
    
    ($MM)
    
    
    (bblpd)
    
    
    (MMcfpd)
    
    
    (bblpd)
    
    
    (boepd)(4)Subtotal
    
    
    6,348
    
    
    
    
    
    
    
    
    
    
    
    17.0
    
    
    
    0
    
    
    
    0.0
    
    
    
    0
    
    
    
    0Total
    
    
    295,734
    
    
    
    
    
    
    
    10.6
    
    
    
    4,884.9
    
    
    
    30,393
    
    
    
    237.2
    
    
    
    9,590
    
    
    
    79,518
 
 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)
    
    All Other includes our Working Interests and Royalty Interests in approximately 85 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.(5)
    
    We assess our asset portfolio by aggregating production from properties into the following
categories: light oil; heavy oil; conventional gas; shallow gas and
coal bed methane; offshore
gas; and oil sands. Because all of the production from the properties are aggregated into one
of these groups, as opposed to the actual commodities, the production and reserves by
commodity reported elsewhere will be different than those reported above. 
 Light Oil Properties
 Judy Creek
  2009 Development Activity
  2010 Development Activity
  Carbon Dioxide (CO 2 ) Pilot
 2 2 2 2 2 2 2
 - 16 -




---



##### Table of Contents



2 2
 Weyburn Unit
 2
 2009 Development Activity
 2 2 2 2
 2010 Development Activity
 2 2
 Swan Hills
  2009 Development Activity
  2010 Development Activity
  Carson Creek
  - 17 -




---



##### Table of Contents



2009 Development Activity
  2010 Development Activity
  Deer Mountain Area
  2009 Development Activity
  2010 Development Activity
  Fenn Big Valley
  2009 Development Activity
  - 18 -




---



##### Table of Contents



2010 Development Activity
  
 Heavy Oil Properties
 Bodo
  2009 Development Activity
  2010 Development Activity
  Jenner
 °
 2009 Development Activity
  2010 Development Activity
  Tangleflags
  - 19 -




---



##### Table of Contents



2009 Development Activity
  2010 Development Activity
  
 Conventional Gas Properties
 Olds
 2
  2009 Development Activity
  2010 Development Activity
  Harmattan
  - 20 -




---



##### Table of Contents



2009 Development Activity
  2010 Development Activity
  Carson Creek
   2009 Development Activity
  2010 Development Activity
  Dunvegan
  2009 Development Activity
  2010 Development Activity
  - 21 -




---



##### Table of Contents



Quirk Creek
  2009 Development Activity
  2010 Development Activity
  Kaybob
  2009 Development Activity
  2010 Development Activity
  Blackstone
  2009 Development Activity
  - 22 -




---



##### Table of Contents



2010 Development Activity
  McLeod River
  2009 Development Activity
  2010 Development Activity
  
 Shallow Gas Properties
 Twining/Three Hills Creek
  2009 Development Activity
  2010 Development Activity
  Coal Bed Methane (CBM)
  2009 Development Activity
  - 23 -




---



##### Table of Contents



2010 Development Activity
  Monogram Gas Unit
  2009 Development Activity
  2010 Development Activity
  Jenner
  2009 Development Activity
  2010 Development Activity
  Lethbridge
  2009 Development Activity
 During 2009, we performed 16 coiled tubing cleanouts and reactivated two wells.
 - 24 -




---



##### Table of Contents



2010 Development Activity
  
 Offshore Gas Properties
 Sable Offshore Energy Project
   2009 Development Activity
  2010 Development Activity
  
 Oil Sands Properties
 Lindbergh
 °
 Lindbergh Oil Sands Contingent Resources
 2009 Development Activity
  2010 Development Activity
  - 25 -




---



##### Table of Contents



Statement of Oil and Gas Reserves and Reserves Data
 Disclosure of Reserves Data
   Lindbergh
Oil Sands Reserves and Contingent Resources
 Our future net revenues associated with the production and reserves contained in this Annual
Information Form reflect the royalty programs in-place on December 31, 2009.
  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.
 - 26 -




---



##### Table of Contents



We determined the future net revenue and present value of future net revenue after income taxes
after taking into account the impact of the SIFT Legislation. Certain Canadian Federal Income
Tax Considerations  Taxation of the Trust  SIFT Legislation
 
    
    SIFT tax starting January 2011 at 27.06 percent (and 25.56 percent in 2012 and thereafter).
The SIFT tax is based on the provincial allocation from the Corporations December 31, 2008
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 $2.9 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 we file and would file future tax returns. See Canadian Income Tax
Considerations.
   - 27 -




---



##### Table of Contents



Reserves Data (Forecast Prices and Costs)
 Summary of Oil and Gas Reserves
as of December 31, 2009
(Forecast Prices and Costs) (1)
 Light and Medium Oil
    
    
    Heavy Oil(2)
    
    
    Natural Gas LiquidsCompany Interest
    
    
    Gross Interest
    
    
    Net Interest
    
    
    Company Interest
    
    
    Gross Interest
    
    
    Net Interest
    
    
    Company Interest
    
    
    Gross Interest
    
    
    Net InterestReserves Category
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)Proved ReservesProved Developed Producing
    
    
    65,640
    
    
    
    65,504
    
    
    
    52,047
    
    
    
    14,370
    
    
    
    14,362
    
    
    
    12,750
    
    
    
    19,253
    
    
    
    19,165
    
    
    
    14,026Proved Developed Non-
Producing
    
    
    804
    
    
    
    804
    
    
    
    556
    
    
    
    139
    
    
    
    139
    
    
    
    127
    
    
    
    1,030
    
    
    
    1,029
    
    
    
    769Proved Undeveloped
    
    
    16,358
    
    
    
    16,351
    
    
    
    12,391
    
    
    
    1,846
    
    
    
    1,846
    
    
    
    1,533
    
    
    
    1,190
    
    
    
    1,190
    
    
    
    795Total Proved Reserves
    
    
    82,803
    
    
    
    82,659
    
    
    
    64,995
    
    
    
    16,355
    
    
    
    16,347
    
    
    
    14,410
    
    
    
    21,473
    
    
    
    21,384
    
    
    
    15,591Probable Reserves
    
    
    29,446
    
    
    
    29,400
    
    
    
    22,476
    
    
    
    11,370
    
    
    
    11,367
    
    
    
    9,976
    
    
    
    8,114
    
    
    
    8,091
    
    
    
    5,892Total Proved Plus
Probable Reserves
    
    
    112,249
    
    
    
    112,059
    
    
    
    87,471
    
    
    
    27,724
    
    
    
    27,713
    
    
    
    24,386
    
    
    
    29,587
    
    
    
    29,475
    
    
    
    21,482
 Natural Gas
    
    
    Coal Bed Methane
    
    
    Total Oil Equivalent Basis(3)Net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Company Interest
    
    
    Gross Interest
    
    
    Net InterestCompany Interest
    
    
    Gross Interest
    
    
    Interest
    
    
    Company Interest
    
    
    Gross Interest
    
    
    Net Interest
    
    
    (Mboe)
    
    
    (Mboe)
    
    
    (Mboe)RESERVES CATEGORY
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (3)
    
    
    (3)
    
    
    (3)Proved ReservesProved Developed Producing
    
    
    484,396
    
    
    
    481,215
    
    
    
    409,311
    
    
    
    23,034
    
    
    
    21,906
    
    
    
    21,635
    
    
    
    183,835
    
    
    
    182,885
    
    
    
    150,648Proved Developed Non-
Producing
    
    
    18,490
    
    
    
    18,322
    
    
    
    14,460
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,055
    
    
    
    5,025
    
    
    
    3,862Proved Undeveloped
    
    
    30,360
    
    
    
    30,359
    
    
    
    26,463
    
    
    
    19,263
    
    
    
    19,184
    
    
    
    16,325
    
    
    
    27,665
    
    
    
    27,644
    
    
    
    21,851Total Proved Reserves
    
    
    533,246
    
    
    
    529,897
    
    
    
    450,234
    
    
    
    42,297
    
    
    
    41,090
    
    
    
    37,960
    
    
    
    216,554
    
    
    
    215,554
    
    
    
    176,361Probable Reserves
    
    
    170,204
    
    
    
    169,277
    
    
    
    140,778
    
    
    
    11,293
    
    
    
    11,037
    
    
    
    10,226
    
    
    
    79,180
    
    
    
    78,911
    
    
    
    63,511Total Proved Plus
Probable Reserves
    
    
    703,449
    
    
    
    699,175
    
    
    
    591,013
    
    
    
    53,590
    
    
    
    52,127
    
    
    
    48,186
    
    
    
    295,734
    
    
    
    294,464
    
    
    
    239,872
 Notes:
 
 (1)
    
    Forecast prices are shown under the heading   Pricing Assumptions.(2)
    
    Includes 6,348 Mbbl of Company Interest heavy oil Probable Reserves for the Lindbergh oil sands property in the GLJ Report.(3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil. - 28 -




---



##### Table of Contents



Summary of Net Present Value
of Future Net Revenue
as of December 31, 2009
Before and After Income Taxes
(Forecast 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
    
    
    5,793
    
    
    
    4,301
    
    
    
    3,442
    
    
    
    2,888
    
    
    
    2,502
    
    
    
    22.85
    
    
    
    3.81Proved Developed Non-Producing
    
    
    162
    
    
    
    118
    
    
    
    93
    
    
    
    77
    
    
    
    66
    
    
    
    24.11
    
    
    
    4.02Proved Undeveloped
    
    
    1,046
    
    
    
    571
    
    
    
    335
    
    
    
    203
    
    
    
    124
    
    
    
    15.32
    
    
    
    2.55Total Proved Reserves
    
    
    7,002
    
    
    
    4,989
    
    
    
    3,870
    
    
    
    3,168
    
    
    
    2,691
    
    
    
    21.94
    
    
    
    3.66Probable Reserves
    
    
    3,141
    
    
    
    1,641
    
    
    
    1,015
    
    
    
    696
    
    
    
    510
    
    
    
    15.99
    
    
    
    2.66Total Proved Plus Probable Reserves
    
    
    10,143
    
    
    
    6,630
    
    
    
    4,885
    
    
    
    3,865
    
    
    
    3,202
    
    
    
    20.36
    
    
    
    3.39
 After Income TaxesDiscounted at (%/Year)(3)0%
    
    
    5%
    
    
    10%
    
    
    15%
    
    
    20%Reserves Category
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    5,189
    
    
    
    3,840
    
    
    
    3,079
    
    
    
    2,594
    
    
    
    2,260Proved Developed Non-Producing
    
    
    103
    
    
    
    76
    
    
    
    60
    
    
    
    51
    
    
    
    44Proved Undeveloped
    
    
    674
    
    
    
    337
    
    
    
    184
    
    
    
    101
    
    
    
    52Total Proved Reserves
    
    
    5,966
    
    
    
    4,253
    
    
    
    3,323
    
    
    
    2,746
    
    
    
    2,356Probable Reserves
    
    
    2,361
    
    
    
    1,194
    
    
    
    733
    
    
    
    505
    
    
    
    372Total Proved Plus Probable Reserves
    
    
    8,327
    
    
    
    5,447
    
    
    
    4,056
    
    
    
    3,251
    
    
    
    2,728
 
 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 our net
reserves.(3)
    
    After tax figures were calculated assuming we would
continue to be organized as a trust and would be subject to the SIFT
Legislation. See  Statement of Oil and Gas
Reserves and Reserves Data  Disclosure of Reserves Data
for a description of the assumptions made in calculating the after tax figures. - 29 -




---



##### Table of Contents



Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2009
(Forecast Prices and Costs) (1)
 Capital Development
    
    
    Abandonment
    
    
    Future Net Revenue
    
    
    
    
    
    
    Future Net RevenueRevenue
    
    
    Royalties(2)
    
    
    Operating Costs
    
    
    Costs
    
    
    Costs(3)
    
    
    Before Income Taxes
    
    
    Income Tax
    
    
    After Income TaxesReserves Category
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)Proved Reserves
    
    
    15,658
    
    
    
    3,031
    
    
    
    4,853
    
    
    
    537
    
    
    
    235
    
    
    
    7,002
    
    
    
    1,035
    
    
    
    5,967Total Proved PlusProbable Reserves
    
    
    22,388
    
    
    
    4,426
    
    
    
    6,670
    
    
    
    887
    
    
    
    262
    
    
    
    10,143
    
    
    
    1,816
    
    
    
    8,327
 
 Notes:
 (1)
    
    Forecast prices are shown under the heading   Pricing Assumptions.(2)
    
    Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova
Scotia and any freehold and over-riding royalties payable. This includes the impact of the
New Royalty Framework implemented by the Government of Alberta on January 1, 2009, the
optional Transitional Royalty and any drilling incentive programs currently in effect.(3)
    
    Includes the cost of well abandonments and abandonment of Sable Island facilities and subsea pipelines,
but does not include abandonment costs for other facilities or any 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, 2009
(Forecast Prices and Costs) (1)
 Future Net RevenueBefore Income Taxes(discounted at10%/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)
    
    
    2,015
    
    
    
    25.86
    
    
    
    4.31Heavy Oil (including solution gas and other by-products)(2)
    
    
    395
    
    
    
    24.99
    
    
    
    4.16Natural Gas (including by-products but excluding solution gas from oil wells)(3)
    
    
    1,374
    
    
    
    18.00
    
    
    
    3.00Coal Bed Methane
    
    
    87
    
    
    
    13.74
    
    
    
    2.29Total
    
    
    3,870
    
    
    
    21.94
    
    
    
    3.66Total Proved Plus
    
    Light and Medium Crude Oil (including solution gas and other by-products)(2)
    
    
    2,510
    
    
    
    24.11
    
    
    
    4.02Probable Reserves
    
    Heavy Oil (including solution gas and other by-products)(2)
    
    
    506
    
    
    
    19.21
    
    
    
    3.20Natural Gas (including by-products but excluding solution gas from oil wells)(3)
    
    
    1,759
    
    
    
    17.36
    
    
    
    2.89Coal Bed Methane
    
    
    109
    
    
    
    13.59
    
    
    
    2.26Total
    
    
    4,885
    
    
    
    20.36
    
    
    
    3.39
 
 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 our net
reserves. - 30 -




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##### Table of Contents



Reserves Data (Constant Prices and Costs)
 Summary of Oil And Gas Reserves
as of December 31, 2009
(Constant Prices and Costs) (1)
 Light and Medium Oil
    
    
    Heavy Oil(2)
    
    
    Natural Gas LiquidsNet
    
    
    
    
    
    
    
    
    
    
    Net
    
    
    
    
    
    
    
    
    
    
    NetCompany Interest
    
    
    Gross Interest
    
    
    Interest
    
    
    Company Interest
    
    
    Gross Interest
    
    
    Interest
    
    
    Company Interest
    
    
    Gross Interest
    
    
    InterestReserves Category
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)
    
    
    (Mbbl)Proved ReservesProved Developed
Producing
    
    
    62,736
    
    
    
    62,613
    
    
    
    54,860
    
    
    
    13,951
    
    
    
    13,944
    
    
    
    12,731
    
    
    
    17,220
    
    
    
    17,137
    
    
    
    12,592Proved Developed
Non-Producing
    
    
    783
    
    
    
    783
    
    
    
    573
    
    
    
    139
    
    
    
    139
    
    
    
    132
    
    
    
    1,048
    
    
    
    1,047
    
    
    
    795Proved Undeveloped
    
    
    16,080
    
    
    
    16,072
    
    
    
    13,543
    
    
    
    1,841
    
    
    
    1,841
    
    
    
    1,634
    
    
    
    992
    
    
    
    992
    
    
    
    665Total Proved Reserves
    
    
    79,599
    
    
    
    79,467
    
    
    
    68,976
    
    
    
    15,931
    
    
    
    15,924
    
    
    
    14,498
    
    
    
    19,260
    
    
    
    19,175
    
    
    
    14,052Probable Reserves
    
    
    29,807
    
    
    
    29,764
    
    
    
    25,625
    
    
    
    11,269
    
    
    
    11,266
    
    
    
    10,609
    
    
    
    8,532
    
    
    
    8,511
    
    
    
    6,234Total Proved Plus
Probable Reserves
    
    
    109,405
    
    
    
    109,231
    
    
    
    94,601
    
    
    
    27,200
    
    
    
    27,190
    
    
    
    25,106
    
    
    
    27,792
    
    
    
    27,686
    
    
    
    20,286
 Natural Gas
    
    
    Coal Bed Methane
    
    
    Total Oil Equivalent Basis(3)NetNet
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Company Interest
    
    
    
    
    
    
    InterestCompany Interest
    
    
    Gross Interest
    
    
    Interest
    
    
    Company Interest
    
    
    Gross Interest
    
    
    Net Interest
    
    
    (Mboe)
    
    
    Gross Interest
    
    
    (Mboe)Reserves Category
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (MMcf)
    
    
    (3)
    
    
    (Mboe)(3)
    
    
    (3)Proved ReservesProved Developed
Producing
    
    
    413,139
    
    
    
    410,444
    
    
    
    361,187
    
    
    
    20,546
    
    
    
    19,464
    
    
    
    19,336
    
    
    
    166,188
    
    
    
    165,345
    
    
    
    143,603Proved Developed
Non-Producing
    
    
    16,666
    
    
    
    16,528
    
    
    
    13,505
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,748
    
    
    
    4,723
    
    
    
    3,752Proved Undeveloped
    
    
    11,896
    
    
    
    11,894
    
    
    
    10,538
    
    
    
    12,780
    
    
    
    12,731
    
    
    
    10,810
    
    
    
    23,025
    
    
    
    23,008
    
    
    
    19,400Total Proved Reserves
    
    
    441,701
    
    
    
    438,866
    
    
    
    385,230
    
    
    
    33,326
    
    
    
    32,195
    
    
    
    30,146
    
    
    
    193,960
    
    
    
    193,077
    
    
    
    166,755Probable Reserves
    
    
    167,893
    
    
    
    167,103
    
    
    
    145,333
    
    
    
    10,395
    
    
    
    10,160
    
    
    
    9,484
    
    
    
    79,323
    
    
    
    79,085
    
    
    
    68,271Total Proved Plus
Probable Reserves
    
    
    609,594
    
    
    
    605,970
    
    
    
    530,563
    
    
    
    43,720
    
    
    
    42,355
    
    
    
    39,630
    
    
    
    273,283
    
    
    
    272,162
    
    
    
    235,025
 
 Notes:
 (1)
    
    Constant prices are shown under the heading   Pricing Assumptions.(2)
    
    Includes 6,348 Mbbl of Company Interest heavy oil Probable Reserves for the Lindbergh oil sands property in the GLJ Report.(3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil. - 31 -




---



##### Table of Contents



Summary of Net Present Value
of Future Net Revenue
as of December 31, 2009
Before and After Income Tax
(Constant 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
    
    
    2,796
    
    
    
    2,204
    
    
    
    1,835
    
    
    
    1,581
    
    
    
    1,397
    
    
    
    12.78
    
    
    
    2.13Proved Developed Non-Producing
    
    
    75
    
    
    
    58
    
    
    
    47
    
    
    
    40
    
    
    
    35
    
    
    
    12.65
    
    
    
    2.11Proved Undeveloped
    
    
    526
    
    
    
    276
    
    
    
    150
    
    
    
    79
    
    
    
    37
    
    
    
    7.71
    
    
    
    1.29Total Proved Reserves
    
    
    3,397
    
    
    
    2,538
    
    
    
    2,032
    
    
    
    1,701
    
    
    
    1,469
    
    
    
    12.18
    
    
    
    2.03Probable Reserves
    
    
    1,413
    
    
    
    775
    
    
    
    484
    
    
    
    328
    
    
    
    234
    
    
    
    7.09
    
    
    
    1.18Total Proved Plus Probable
Reserves
    
    
    4,809
    
    
    
    3,313
    
    
    
    2,516
    
    
    
    2,029
    
    
    
    1,703
    
    
    
    10.70
    
    
    
    1.78
 After Income TaxesDiscounted At (%/Year)(3)0%
    
    
    5%
    
    
    10%
    
    
    15%
    
    
    20%Reserves Category
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    2,725
    
    
    
    2,143
    
    
    
    1,780
    
    
    
    1,533
    
    
    
    1,353Proved Developed Non-Producing
    
    
    50
    
    
    
    39
    
    
    
    32
    
    
    
    27
    
    
    
    24Proved Undeveloped
    
    
    522
    
    
    
    271
    
    
    
    147
    
    
    
    78
    
    
    
    36Total Proved Reserves
    
    
    3,297
    
    
    
    2,453
    
    
    
    1,959
    
    
    
    1,638
    
    
    
    1,413Probable Reserves
    
    
    1,209
    
    
    
    642
    
    
    
    394
    
    
    
    265
    
    
    
    190Total Proved Plus Probable
Reserves
    
    
    4,506
    
    
    
    3,095
    
    
    
    2,353
    
    
    
    1,903
    
    
    
    1,603
 
 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 our net
reserves.(3)
    
    After tax figures were calculated assuming we would
continue to be organized as a trust and would be subject to the SIFT
Legislation. See  Statement of Oil and Gas
Reserves and Reserves Data  Disclosure of Reserves Data
for a description of the assumptions made in calculating the after tax figures. - 32 -




---



##### Table of Contents



Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2009
(Constant Prices and Costs) (1)
 Future Net RevenueCapital Development
    
    
    Abandonment
    
    
    Before
    
    
    
    
    
    
    Future net RevenueRevenue

    
    
    Royalties(2)
    
    
    Operating Costs
    
    
    Costs
    
    
    Costs(3)
    
    
    Income Taxes
    
    
    Income Tax
    
    
    After Income TaxesReserves Category
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)
    
    
    ($MM)Proved Reserves
    
    
    8,559
    
    
    
    1,184
    
    
    
    3,418
    
    
    
    392
    
    
    
    167
    
    
    
    3,397
    
    
    
    100
    
    
    
    3,297Total Proved PlusProbable Reserves
    
    
    12,060
    
    
    
    1,655
    
    
    
    4,693
    
    
    
    727
    
    
    
    176
    
    
    
    4,809
    
    
    
    303
    
    
    
    4,506
 
 Notes:
 (1)
    
    Constant prices are shown under the heading   Pricing Assumptions.(2)
    
    Crown royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova
Scotia and any freehold and over-riding royalties payable. This includes the impact of the
New Royalty Framework implemented by the Government of Alberta on January 1, 2009, the
optional Transitional Royalty and any drilling incentive programs still in effect.(3)
    
    Includes  the cost of well abandonments and abandonment of Sable Island facilities and subsea pipelines,
 but does not include abandonment costs for other facilities or any 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, 2009
(Constant Prices and Costs) (1)
 Future NetRevenue BeforeIncome Taxes(discounted at10%/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)
    
    
    1,175
    
    
    
    14.41
    
    
    
    2.40Heavy Oil (including solution gas and other by-products)(2)
    
    
    266
    
    
    
    16.80
    
    
    
    2.80Natural Gas (including by-products
but excluding solution gas from oil wells)(3)
    
    
    566
    
    
    
    8.79
    
    
    
    1.46Coal Bed Methane
    
    
    25
    
    
    
    4.97
    
    
    
    0.83Total
    
    
    2,032
    
    
    
    12.18
    
    
    
    2.03Total Proved Plus
    
    Light and Medium Crude Oil
(including solution gas and other by-products)(2)
    
    
    1,457
    
    
    
    13.09
    
    
    
    2.18Probable Reserves
    
    Heavy Oil (including solution gas and other by-products)(2)
    
    
    310
    
    
    
    11.48
    
    
    
    1.91Natural Gas (including by-products
but excluding solution gas from oil wells)(3)
    
    
    717
    
    
    
    7.95
    
    
    
    1.33Coal Bed Methane
    
    
    32
    
    
    
    4.81
    
    
    
    0.80Total
    
    
    2,516
    
    
    
    10.70
    
    
    
    1.78
 
 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 our net
reserves. - 33 -




---



##### Table of Contents



Pricing Assumptions
 Forecast Prices used in Estimates
  Oil
    
    
    Natural Gas
    
    
    Natural Gas Liquids(1)Hardisty HeavyEdmonton Par Price
    
    
    Cromer Medium
    
    
    12°
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Inflation
    
    
    ExchangeWTI Cushing
    
    
    40°API
    
    
    29.3°API
    
    
    API
    
    
    AECO Gas Price
    
    
    
    
    
    
    
    
    
    
    Pentanes Plus
    
    
    Rates(2)
    
    
    Rate(3)Year
    
    Oklahoma ($US/bbl)
    
    
    ($Cdn/bbl)
    
    
    ($Cdn/bbl)
    
    
    ($Cdn/bbl)
    
    
    ($Cdn/MMBtu)
    
    
    Propane ($Cdn/bbl)
    
    
    Butane ($Cdn/bbl)
    
    
    ($Cdn/bbl)
    
    
    (%/Year)
    
    
    ($US/Cdn)2009(4)
    
    
    61.56
    
    
    
    66.43
    
    
    
    63.19
    
    
    
    54.36
    
    
    
    4.20
    
    
    
    37.58
    
    
    
    47.31
    
    
    
    67.99
    
    
    
    
    
    
    
    2010
    
    
    80.00
    
    
    
    83.26
    
    
    
    76.60
    
    
    
    64.99
    
    
    
    5.96
    
    
    
    52.46
    
    
    
    64.11
    
    
    
    84.93
    
    
    
    2.0
    
    
    
    0.952011
    
    
    83.00
    
    
    
    86.42
    
    
    
    78.64
    
    
    
    65.24
    
    
    
    6.79
    
    
    
    54.45
    
    
    
    66.54
    
    
    
    88.15
    
    
    
    2.0
    
    
    
    0.952012
    
    
    86.00
    
    
    
    89.58
    
    
    
    80.62
    
    
    
    65.33
    
    
    
    6.89
    
    
    
    56.43
    
    
    
    68.98
    
    
    
    91.37
    
    
    
    2.0
    
    
    
    0.952013
    
    
    89.00
    
    
    
    92.74
    
    
    
    82.54
    
    
    
    65.26
    
    
    
    6.95
    
    
    
    58.42
    
    
    
    71.41
    
    
    
    94.59
    
    
    
    2.0
    
    
    
    0.952014
    
    
    92.00
    
    
    
    95.90
    
    
    
    85.35
    
    
    
    67.52
    
    
    
    7.05
    
    
    
    60.42
    
    
    
    73.84
    
    
    
    97.82
    
    
    
    2.0
    
    
    
    0.952015
    
    
    93.84
    
    
    
    97.84
    
    
    
    87.07
    
    
    
    68.90
    
    
    
    7.16
    
    
    
    61.64
    
    
    
    75.33
    
    
    
    99.79
    
    
    
    2.0
    
    
    
    0.952016
    
    
    95.72
    
    
    
    99.81
    
    
    
    88.83
    
    
    
    70.32
    
    
    
    7.42
    
    
    
    62.88
    
    
    
    76.85
    
    
    
    101.81
    
    
    
    2.0
    
    
    
    0.952017
    
    
    97.64
    
    
    
    101.83
    
    
    
    90.63
    
    
    
    71.76
    
    
    
    7.95
    
    
    
    64.15
    
    
    
    78.41
    
    
    
    103.86
    
    
    
    2.0
    
    
    
    0.952018
    
    
    99.59
    
    
    
    103.88
    
    
    
    92.46
    
    
    
    73.22
    
    
    
    8.52
    
    
    
    65.45
    
    
    
    79.99
    
    
    
    105.96
    
    
    
    2.0
    
    
    
    0.952019
    
    
    101.58
    
    
    
    105.98
    
    
    
    94.32
    
    
    
    74.72
    
    
    
    8.69
    
    
    
    66.77
    
    
    
    81.60
    
    
    
    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 2009. Constant Prices used in Estimates
  Oil
    
    
    
    
    
    
    Natural Gas
    
    
    Natural Gas Liquids(1)Edmonton Par Price
    
    
    Cromer Medium
    
    
    Hardisty Heavy
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    ExchangeWTI Cushing
    
    
    40°
    
    
    29.3°
    
    
    12° API
    
    
    AECO Gas Price
    
    
    
    
    
    
    
    
    
    
    Pentanes Plus
    
    
    Inflation Rate
    
    
    Rate(2)Year
    
    Oklahoma ($US/bbl)
    
    
    API ($Cdn/bbl)
    
    
    API ($Cdn/bbl)
    
    
    ($Cdn/bbl)
    
    
    ($Cdn/MMBtu)
    
    
    Propane ($Cdn/bbl)
    
    
    Butane ($Cdn/bbl)
    
    
    ($Cdn/bbl)
    
    
    (%/Year)
    
    
    ($US/Cdn)2010
    
    
    61.04
    
    
    
    63.59
    
    
    
    59.56
    
    
    
    51.80
    
    
    
    3.84
    
    
    
    36.87
    
    
    
    46.87
    
    
    
    66.67
    
    
    
    0.0
    %
    
    
    0.8728
 Notes:
 (1)
    
    FOB Edmonton.(2)
    
    The exchange rate used to generate the benchmark reference prices in this table. - 34 -




---



##### Table of Contents



Reserves Reconciliation
  Reserves Reconciliation
By Principal Product Type
(Forecast Prices and Costs)
 Light and Medium Oil
    
    Heavy Oil
    
    Natural Gas LiquidsGross
    
    
    
    
    
    
    
    
    
    Gross
    
    
    
    
    
    
    
    
    
    GrossGross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    Proved PlusProved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable(Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)
    
    (Mbbl)December 31, 2008
    
    
    90,261
    
    
    
    30,846
    
    
    
    121,107
    
    
    
    16,268
    
    
    
    11,448
    
    
    
    27,716
    
    
    
    23,436
    
    
    
    8,873
    
    
    
    32,309Extensions
    
    
    252
    
    
    
    452
    
    
    
    704
    
    
    
    139
    
    
    
    (71
    )
    
    
    68
    
    
    
    934
    
    
    
    289
    
    
    
    1,223Infill Drilling
    
    
    137
    
    
    
    128
    
    
    
    265
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    656
    
    
    
    (2
    )
    
    
    655Improved Recovery
    
    
    1,152
    
    
    
    (526
    )
    
    
    626
    
    
    
    225
    
    
    
    63
    
    
    
    288
    
    
    
    7
    
    
    
    17
    
    
    
    24Technical Revisions
    
    
    (1,570
    )
    
    
    (1,828
    )
    
    
    (3,398
    )
    
    
    2,350
    
    
    
    (114
    )
    
    
    2,236
    
    
    
    (29
    )
    
    
    (1,045
    )
    
    
    (1,075
    )Discoveries
    
    
    100
    
    
    
    200
    
    
    
    300
    
    
    
    129
    
    
    
    43
    
    
    
    172
    
    
    
    
    
    
    
    
    
    
    
    Acquisitions
    
    
    877
    
    
    
    206
    
    
    
    1,083
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    214
    
    
    
    47
    
    
    
    260Dispositions
    
    
    (245
    )
    
    
    (77
    )
    
    
    (323
    )
    
    
    (7
    )
    
    
    (2
    )
    
    
    (9
    )
    
    
    (353
    )
    
    
    (88
    )
    
    
    (441
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (8,305
    )
    
    
    
    
    
    
    (8,305
    )
    
    
    (2,756
    )
    
    
    
    
    
    
    (2,756
    )
    
    
    (3,480
    )
    
    
    
    
    
    
    (3,480
    )December 31, 2009
    
    
    82,659
    
    
    
    29,400
    
    
    
    112,059
    
    
    
    16,347
    
    
    
    11,367
    
    
    
    27,713
    
    
    
    21,384
    
    
    
    8,091
    
    
    
    29,475
 Natural Gas
    
    Coal Bed Methane
    
    Total Oil Equivalent BasisGross
    
    
    
    
    
    
    
    
    
    Gross
    
    
    
    
    
    
    
    
    
    GrossGross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    Proved Plus
    
    Gross
    
    Gross
    
    Proved PlusProved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable(MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (MMcf)
    
    (Mboe)(1)
    
    (Mboe)(1)
    
    (Mboe)(1)December 31, 2008
    
    
    591,413
    
    
    
    205,163
    
    
    
    796,576
    
    
    
    33,019
    
    
    
    14,960
    
    
    
    47,979
    
    
    
    234,036
    
    
    
    87,855
    
    
    
    321,891Extensions
    
    
    6,467
    
    
    
    2,382
    
    
    
    8,849
    
    
    
    729
    
    
    
    145
    
    
    
    873
    
    
    
    2,523
    
    
    
    1,092
    
    
    
    3,615Infill Drilling
    
    
    3,923
    
    
    
    2,021
    
    
    
    5,943
    
    
    
    7,642
    
    
    
    1,422
    
    
    
    9,064
    
    
    
    2,721
    
    
    
    700
    
    
    
    3,421Improved Recovery
    
    
    843
    
    
    
    901
    
    
    
    1,743
    
    
    
    451
    
    
    
    (451
    )
    
    
    
    
    
    
    1,600
    
    
    
    (371
    )
    
    
    1,229Technical Revisions
    
    
    16,212
    
    
    
    (38,680
    )
    
    
    (22,468
    )
    
    
    3,652
    
    
    
    (5,038
    )
    
    
    (1,386
    )
    
    
    4,062
    
    
    
    (10,275
    )
    
    
    (6,213
    )Discoveries
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    229
    
    
    
    243
    
    
    
    472Acquisitions
    
    
    1,432
    
    
    
    306
    
    
    
    1,738
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,329
    
    
    
    304
    
    
    
    1,633Dispositions
    
    
    (9,615
    )
    
    
    (2,815
    )
    
    
    (12,430
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,208
    )
    
    
    (637
    )
    
    
    (2,845
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (80,777
    )
    
    
    
    
    
    
    (80,777
    )
    
    
    (4,403
    )
    
    
    
    
    
    
    (4,403
    )
    
    
    (28,738
    )
    
    
    
    
    
    
    (28,738
    )December 31, 2009
    
    
    529,897
    
    
    
    169,278
    
    
    
    699,175
    
    
    
    41,090
    
    
    
    11,037
    
    
    
    52,127
    
    
    
    215,554
    
    
    
    78,911
    
    
    
    294,464
 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. - 35 -




---



##### Table of Contents



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, 2008
    
    
    200,580
    
    
    
    235,224
    
    
    
    323,463Extensions
    
    
    2,052
    
    
    
    2,532
    
    
    
    3,617Infill Drilling
    
    
    2,763
    
    
    
    2,721
    
    
    
    3,425Improved Recovery
    
    
    1,558
    
    
    
    1,620
    
    
    
    1,259Technical Revisions
    
    
    6,758
    
    
    
    4,191
    
    
    
    (6,194
    )Discoveries
    
    
    129
    
    
    
    229
    
    
    
    472Acquisitions
    
    
    1,287
    
    
    
    1,329
    
    
    
    1,633Dispositions
    
    
    (2,266
    )
    
    
    (2,267
    )
    
    
    (2,916
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (29,025
    )
    
    
    (29,025
    )
    
    
    (29,025
    )December 31, 2009
    
    
    183,835
    
    
    
    216,554
    
    
    
    295,734
 
 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.  
    
    Certain probable undeveloped reserves were removed as a result of changing corporate
strategy regarding future capital deployment. Also, various performance related
revisions were made to previous estimates. Together this resulted in a net negative change in
Total Proved Plus Probable Reserves. The largest revisions occurred at Sable Island
(+1,625 Mboe), Carson Creek (+1,184 Mboe), Jenner (-948 Mboe), Judy Creek (-1,771 Mboe)
and Olds (-6,434 Mboe). The
majority of the strategy related reserve changes were made at Olds where management does not
foresee drilling a large number of gas wells.
    
    Reserve additions from drilling activity, improved recovery and technical revisions
replaced 2009 production by 39 percent and nine percent for Total Proved and Proved
Plus Probable Reserves, respectively. Based on all changes, including acquisitions and
dispositions, reserve replacement was 36 percent and four percent for Total Proved and
Proved Plus Probable Reserves, respectively. Pengrowth reinvested 38 percent of operating cash flow into capital projects.
    
    New reserve additions for development activity during 2009 amounted to 8.8 MMboe of
Total Proved Plus Probable Reserves. Most significant were infill drilling and
extensions at Carson Creek and in the Twining CBM area and improved recovery and infill
drilling adds at Weyburn. Reserve increases in the Proved Producing category also
resulted from reclassification of Proved or Probable Undeveloped Reserves to producing
primarily for infill drilling and drilling extensions at Carson Creek, Weyburn, Sable
Island and Monogram.
    
    The net decrease of 1.3 MMboe to Proved Plus Probable Reserves from acquisitions and
dispositions was due to the sale of some minor non-core properties mainly at Niton,
Karr and Pine Creek, offset by some small strategic asset acquisitions at House
Mountain and Carson Creek.
 
 Additional Information Relating to Reserves Data
 Undeveloped Reserves
   - 36 -




---



##### Table of Contents



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
    
    
    20,521
    
    
    
    36,107
    
    
    
    1,994
    
    
    
    3,590
    
    
    
    45,093
    
    
    
    73,203
    
    
    
    3,955
    
    
    
    3,955
    
    
    
    1,509
    
    
    
    2,527
    
    
    
    32,198
    
    
    
    55,0842007
    
    
    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
    
    
    
    29,6062009
    
    
    1,347
    
    
    
    16,351
    
    
    
    130
    
    
    
    1,846
    
    
    
    2,778
    
    
    
    30,359
    
    
    
    10,140
    
    
    
    19,184
    
    
    
    209
    
    
    
    1,190
    
    
    
    3,840
    
    
    
    27,644
 Probable 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
    
    
    10,681
    
    
    
    19,454
    
    
    
    2,013
    
    
    
    3,092
    
    
    
    36,315
    
    
    
    73,467
    
    
    
    4,306
    
    
    
    4,306
    
    
    
    1,593
    
    
    
    3,213
    
    
    
    21,058
    
    
    
    38,7212007
    
    
    3,065
    
    
    
    13,497
    
    
    
    726
    
    
    
    2,269
    
    
    
    25,386
    
    
    
    64,986
    
    
    
    8,170
    
    
    
    10,155
    
    
    
    670
    
    
    
    2,716
    
    
    
    10,054
    
    
    
    31,0062008
    
    
    1,805
    
    
    
    12,372
    
    
    
    6,997
    
    
    
    7,857
    
    
    
    17,686
    
    
    
    68,822
    
    
    
    4,514
    
    
    
    7,948
    
    
    
    782
    
    
    
    3,478
    
    
    
    13,329
    
    
    
    36,5022009
    
    
    1,565
    
    
    
    11,514
    
    
    
    68
    
    
    
    7,853
    
    
    
    9,450
    
    
    
    37,134
    
    
    
    2,177
    
    
    
    5,178
    
    
    
    934
    
    
    
    2,510
    
    
    
    4,505
    
    
    
    28,929
 
 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
  - 37 -




---



##### Table of Contents



Probable Undeveloped Reserves
  
 Future Development Costs
  TotalDiscounted2010
    
    2011
    
    2012
    
    2013
    
    2014
    
    Remainder
    
    Undiscounted
    
    at 10%Reserve Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
(Constant Prices and Costs)
    
    
    121
    
    
    
    69
    
    
    
    39
    
    
    
    34
    
    
    
    21
    
    
    
    108
    
    
    
    392
    
    
    
    282Proved Reserves
(Forecast Prices and Costs)
    
    
    155
    
    
    
    91
    
    
    
    58
    
    
    
    37
    
    
    
    24
    
    
    
    172
    
    
    
    537
    
    
    
    370Proved & Probable Reserves
(Forecast Prices and Costs)
    
    
    219
    
    
    
    172
    
    
    
    119
    
    
    
    98
    
    
    
    36
    
    
    
    243
    
    
    
    887
    
    
    
    622
  
 Finding, Development and Acquisition Costs
 Finding and Development Costs
    - 38 -




---



##### Table of Contents



2
     Acquisitions and Divestitures
   
 Future Development Capital
  - 39 -




---



##### Table of Contents



2009 Finding, Development and Acquisition Costs
Company Interest Reserves
(Forecast Prices and Costs)
 Proved plusFD&A Costs Excluding Changes in Future Development Capital
    
    Proved
    
    ProbableExploration and Development Capital Expenditures ($M)
    
    
    202,200
    
    
    
    202,200Exploration and Development Reserve Additions including Revisions (Mboe)(1)
    
    
    11,291
    
    
    
    2,577Finding and Development Cost ($/boe)(1)
    
    
    17.91
    
    
    
    78.47Net Acquisition Capital ($M)
    
    
    (6,230
    )
    
    
    (6,230
    )Net Acquisition Reserve Additions (Mboe)(1)
    
    
    (937
    )
    
    
    (1,283
    )Net Acquisition Cost ($/boe)(1)
    
    
    6.65
    
    
    
    4.86Total Capital Expenditures including Net Acquisitions ($M)
    
    
    195,970
    
    
    
    195,970Reserve Additions including Net Acquisitions (Mboe)(1)
    
    
    10,354
    
    
    
    1,294Finding Development and Acquisition Cost ($/boe)(1)
    
    
    18.93
    
    
    
    151.41FD&A Costs Including Changes in Future Development CapitalExploration and Development Capital Expenditures ($M)
    
    
    202,200
    
    
    
    202,200Exploration and Development Change in FDC ($M)
    
    
    (42,800
    )
    
    
    (122,800
    )Exploration and Development Capital including Change in FDC ($M)
    
    
    159,400
    
    
    
    79,400Exploration and Development Reserve Additions including Revisions (Mboe)(1)
    
    
    11,291
    
    
    
    2,577Finding and Development Cost ($/boe)(1)
    
    
    14.12
    
    
    
    30.81Net Acquisition Capital ($M)
    
    
    (6,230
    )
    
    
    (6,230
    )Net Acquisition FDC ($M)
    
    
    800
    
    
    
    800Net Acquisition Capital including FDC ($M)
    
    
    (5,430
    )
    
    
    (5,430
    )Net Acquisition Reserve Additions (Mboe)(1)
    
    
    (937
    )
    
    
    (1,283
    )Net Acquisition Cost ($/boe)(1)
    
    
    5.79
    
    
    
    4.23Total Capital Expenditures including Net Acquisitions ($M)
    
    
    195,970
    
    
    
    195,970Total Change in FDC ($M)
    
    
    (42,000
    )
    
    
    (122,000
    )Total Capital including Change in FDC ($M)
    
    
    153,970
    
    
    
    73,970Reserve Additions including Net Acquisitions (Mboe)(1)
    
    
    10,354
    
    
    
    1,294Finding Development and Acquisition Cost including change in FDC ($/boe)(1)
    
    
    14.87
    
    
    
    57.15
 
 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.   
 Other Oil and Gas Information
 Oil and Gas Wells
  Producing
    
    Non-ProducingGross
    
    Net
    
    Gross
    
    NetCrude Oil WellsAlberta
    
    
    1,669
    
    
    
    1,025
    
    
    
    645
    
    
    
    364British Columbia
    
    
    89
    
    
    
    58
    
    
    
    139
    
    
    
    89Saskatchewan
    
    
    904
    
    
    
    201
    
    
    
    510
    
    
    
    193Nova Scotia
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Natural Gas WellsAlberta
    
    
    4,954
    
    
    
    2,543
    
    
    
    442
    
    
    
    239British Columbia
    
    
    142
    
    
    
    83
    
    
    
    98
    
    
    
    58Saskatchewan
    
    
    29
    
    
    
    27
    
    
    
    41
    
    
    
    31Nova Scotia
    
    
    19
    
    
    
    2
    
    
    
    
    
    
    
    
 - 40 -




---



##### Table of Contents



Producing
    
    Non-ProducingGross
    
    Net
    
    Gross
    
    NetOther(1)Alberta
    
    
    
    
    
    
    
    
    
    
    345
    
    
    
    210British Columbia
    
    
    
    
    
    
    
    
    
    
    52
    
    
    
    38Saskatchewan
    
    
    
    
    
    
    
    
    
    
    12
    
    
    
    7Total
    
    
    7,806
    
    
    
    3,938
    
    
    
    2,284
    
    
    
    1,230
 
 Note:(1)
    
    We cannot classify these wells as either oil or gas. Properties with No Attributed Reserves
  Unproved Properties
as at December 31, 2009
 Maximum Net AcresExpected to ExpireLocation
    
    Gross Acres
    
    Net Acres
    
    During 2010Alberta
    
    
    884,573
    
    
    
    617,850
    
    
    
    72,204British Columbia
    
    
    299,790
    
    
    
    174,081
    
    
    
    9,220Ontario
    
    
    4,776
    
    
    
    
    
    
    
    Saskatchewan
    
    
    62,297
    
    
    
    51,708
    
    
    
    1,318Nova Scotia
    
    
    200,650
    
    
    
    15,957
    
    
    
    Total
    
    
    1,452,086
    
    
    
    859,596
    
    
    
    82,742
  Lindbergh Oil Sands Reserves and Contingent Resources
 °
    - 41 -




---



##### Table of Contents



- Principal Properties - Statement of Oil
and Gas Reserves and Reserves Data
 Pilot Project Probable and Probable  plus Possible Reserves and Net Present Value of Future Net Revenue
as of December 31, 2009
(Forecast Prices and Costs)
 Probable plusProbable
    
    PossibleReserves(1)
    
    ReservesReserves (MMbbl)
    
    
    6.3
    
    
    
    35.8Before tax net present value of
future net revenue0% discount rate ($MM)
    
    $
    106.9
    
    
    $
    1,239.05% discount rate ($MM)
    
    $
    50.4
    
    
    $
    339.610% discount rate ($MM)
    
    $
    17.0
    
    
    $
    118.715% discount rate ($MM)
    
    $
    (2.9
    )
    
    $
    42.920% discount rate ($MM)
    
    $
    (14.9
    )
    
    $
    9.8
 
 Note:(1)
    
    GLJ has estimated our undiscounted pilot capital to be $131 million and the ten percent
discounted pilot  capital amount to be $97 million to develop the Probable Reserves.  December 31, 2008
    
    December 31, 2009Contingent Resources(1)
    
    Contingent Resources(1)(MMbbl)
    
    (MMbbl)Low estimate(2)
    
    
    144.2
    
    
    
    148.5Best estimate(3)
    
    
    194.2
    
    
    
    193.4High Estimate(4)
    
    
    264.1
    
    
    
    241.1
 
 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 ninety 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 fifty 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 ten percent confidence
level.  - 42 -




---



##### Table of Contents



Forward Contracts
  
 Additional Information Concerning Abandonment & Reclamation Costs
    Asset Retirement Obligations
 2010
    
    2011
    
    2012
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment, Reclamation,
Remediation & Dismantling
    
    
    12.5
    
    
    
    7.7
    
    
    
    9.7
    
    
    
    1,986.3
    
    
    
    2,016.2Discounted at ten percent
    
    
    12.0
    
    
    
    6.7
    
    
    
    7.7
    
    
    
    187.2
    
    
    
    213.6
  
 Costs Incurred
  AmountNature of Cost
    
    ($M)Acquisition CostsProved
    
    
    24,653Unproved
    
    
    11,002Exploration Costs
    
    
    13,915Development Costs
    
    
    188,288Total
    
    
    237,858
 - 43 -




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##### Table of Contents



Exploration and Development Activities
  Development
    
    Exploration
    
    TotalWells
    
    Gross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetGas
    
    
    135
    
    
    
    67.0
    
    
    
    1
    
    
    
    0.5
    
    
    
    136
    
    
    
    67.5Oil
    
    
    13
    
    
    
    7.3
    
    
    
    2
    
    
    
    2.0
    
    
    
    15
    
    
    
    9.3Service
    
    
    10
    
    
    
    6.2
    
    
    
    
    
    
    
    
    
    
    
    10
    
    
    
    6.2Dry
    
    
    5
    
    
    
    3.2
    
    
    
    3
    
    
    
    2.6
    
    
    
    8
    
    
    
    5.8Total
    
    
    163
    
    
    
    83.8
    
    
    
    6
    
    
    
    5.1
    
    
    
    169
    
    
    
    88.9
 Pengrowth Energy Trust  Recent Developments  2010 Forecast Capital Production and
Operating Costs
 
 Production Estimates
  2010 Estimated ProductionConstant Prices and Costs
    
    Forecast Prices and CostsTotal Proved Plus
    
    
    
    
    
    Total Proved PlusTotal Proved
    
    Probable
    
    Total Proved
    
    ProbableLight and Medium Crude Oil
(bblpd)
    
    
    20,365
    
    
    
    21,649
    
    
    
    20,813
    
    
    
    21,750Heavy Oil (bblpd)
    
    
    6,947
    
    
    
    7,260
    
    
    
    7,039
    
    
    
    7,350Natural Gas (Mcfpd)
    
    
    196,624
    
    
    
    209,021
    
    
    
    207,388
    
    
    
    219,008Natural Gas Liquids (bblpd)
    
    
    8,654
    
    
    
    9,983
    
    
    
    8,832
    
    
    
    10,053Total (boepd)
    
    
    68,737
    
    
    
    73,729
    
    
    
    71,249
    
    
    
    75,654
 - 44 -




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##### Table of Contents



Production History (Netback)
  YearQuarter Ended
    
    
    EndedMarch 31,
    
    
    June
    
    
    September
    
    
    December
    
    
    December2009
    
    
    30, 2009
    
    
    30, 2009
    
    
    31, 2009
    
    
    31, 2009Light Crude OilAverage Daily Oil Production(1) (bblpd)
    
    
    23,424
    
    
    
    23,078
    
    
    
    22,930
    
    
    
    21,948
    
    
    
    22,841Sales Price (after realized commodity price risk management) ($/bbl)
    
    
    66.12
    
    
    
    73.26
    
    
    
    74.40
    
    
    
    75.79
    
    
    
    72.36Processing and other income ($/bbl)
    
    
    1.16
    
    
    
    1.50
    
    
    
    0.77
    
    
    
    0.69
    
    
    
    1.03Royalties ($/bbl)
    
    
    (9.28
    )
    
    
    (12.18
    )
    
    
    (15.94
    )
    
    
    (17.35
    )
    
    
    (13.65
    )Amortization of injectants ($/bbl)
    
    
    (2.53
    )
    
    
    (2.56
    )
    
    
    (2.29
    )
    
    
    (2.19
    )
    
    
    (2.40
    )Production Costs(2)($/bbl)
    
    
    (17.98
    )
    
    
    (18.52
    )
    
    
    (16.54
    )
    
    
    (17.94
    )
    
    
    (16.28
    )Operating Netback ($/bbl)
    
    
    37.49
    
    
    
    41.50
    
    
    
    40.40
    
    
    
    39.00
    
    
    
    40.50Heavy OilAverage Daily Oil Production(1) (bblpd)
    
    
    7,672
    
    
    
    7,822
    
    
    
    7,480
    
    
    
    7,235
    
    
    
    7,551Sales Price ($/bbl)
    
    
    34.31
    
    
    
    55.47
    
    
    
    59.21
    
    
    
    62.16
    
    
    
    52.72Processing and other income ($/bbl)
    
    
    0.41
    
    
    
    1.43
    
    
    
    1.05
    
    
    
    (0.84
    )
    
    
    0.53Royalties ($/bbl)
    
    
    (4.08
    )
    
    
    (12.05
    )
    
    
    (6.74
    )
    
    
    (12.81
    )
    
    
    (8.91
    )Production Costs(2)($/bbl)
    
    
    (16.59
    )
    
    
    (11.25
    )
    
    
    (14.18
    )
    
    
    (12.31
    )
    
    
    (14.35
    )Operating Netback ($/bbl)
    
    
    14.05
    
    
    
    33.60
    
    
    
    39.34
    
    
    
    36.20
    
    
    
    29.99NGLsAverage Daily NGL Production(1) (bblpd)
    
    
    9,815
    
    
    
    10,004
    
    
    
    8,984
    
    
    
    9,564
    
    
    
    9,590Sales Price ($/bbl)
    
    
    35.62
    
    
    
    36.68
    
    
    
    41.87
    
    
    
    54.52
    
    
    
    42.12Royalties ($/bbl)
    
    
    (9.11
    )
    
    
    (11.40
    )
    
    
    (10.70
    )
    
    
    (17.06
    )
    
    
    (12.08
    )Production Costs(2)($/bbl)
    
    
    (14.31
    )
    
    
    (8.68
    )
    
    
    (11.91
    )
    
    
    (11.34
    )
    
    
    (11.99
    )Operating Netback ($/bbl)
    
    
    12.20
    
    
    
    16.60
    
    
    
    19.26
    
    
    
    26.12
    
    
    
    18.05Natural GasAverage Daily Gas Production(1) (Mcfpd)
    
    
    236,232
    
    
    
    247,604
    
    
    
    232,444
    
    
    
    232,682
    
    
    
    237,217Sales Price after realized commodity price risk management) ($/Mcf)
    
    
    6.00
    
    
    
    4.78
    
    
    
    4.34
    
    
    
    5.45
    
    
    
    5.14Processing and other income ($/Mcf)
    
    
    0.14
    
    
    
    0.08
    
    
    
    0.06
    
    
    
    0.09
    
    
    
    0.09Royalties ($/Mcf)
    
    
    (0.45
    )
    
    
    (0.11
    )
    
    
    (0.12
    )
    
    
    (0.58
    )
    
    
    (0.31
    )Production Costs(2)($/Mcf)
    
    
    (2.27
    )
    
    
    (1.64
    )
    
    
    (1.97
    )
    
    
    (1.97
    )
    
    
    (1.99
    )Operating Netback ($/Mcf)
    
    
    3.42
    
    
    
    3.11
    
    
    
    2.31
    
    
    
    2.99
    
    
    
    2.93Barrels of Oil Equivalent Basis(3)Average Daily Production(1) (boepd)
    
    
    80,284
    
    
    
    82,171
    
    
    
    78,135
    
    
    
    77,528
    
    
    
    79,518Sales Price after realized commodity price risk management) ($/boe)
    
    
    44.57
    
    
    
    44.74
    
    
    
    45.25
    
    
    
    50.37
    
    
    
    46.27Processing and other income ($/boe)
    
    
    0.79
    
    
    
    0.79
    
    
    
    0.48
    
    
    
    0.35
    
    
    
    0.54Royalties ($/boe)
    
    
    (5.52
    )
    
    
    (6.29
    )
    
    
    (6.91
    )
    
    
    (9.95
    )
    
    
    (7.15
    )Amortization of injectants ($/boe)
    
    
    (0.74
    )
    
    
    (0.72
    )
    
    
    (0.67
    )
    
    
    (0.62
    )
    
    
    (0.69
    )Production
Costs(2) ($/boe)
    
    
    (15.23
    )
    
    
    (12.24
    )
    
    
    (13.43
    )
    
    
    (13.52
    )
    
    
    (13.59
    )Operating Netback ($/boe)
    
    
    23.87
    
    
    
    26.28
    
    
    
    24.72
    
    
    
    26.63
    
    
    
    25.38
 
 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. - 45 -




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##### Table of Contents



Before Tax Net Asset Value (NAV) at December 31, 2009
 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)
    
    
    267Working Capital Deficit(2)
    
    
    (16
    )Reclamation Funds
    
    
    35Long Term Debt
    
    
    (1,128
    )Fair Value of Risk Management Contracts(3)
    
    
    (27
    )Other Liabilities(4)
    
    
    (84
    )Asset Retirement Obligations(5)
    
    
    (145
    )Total Other Assets and Liabilities
    
    
    (1,098
    )
    
    
    (1,098
    )
    
    
    (1,098
    )
    
    
    (1,098
    )
    
    
    (1,098
    )Value of Total Proved Plus Probable Reserves(6)
    
    
    10,143
    
    
    
    6,630
    
    
    
    4,885
    
    
    
    3,865
    
    
    
    3,202Total Net Asset Value
    
    
    9,045
    
    
    
    5,532
    
    
    
    3,787
    
    
    
    2,767
    
    
    
    2,104NAV per Trust Unit

(289.8 million Trust Units outstanding as at December 31,
2009 on an undiluted basis)
    
    $
    31.21
    
    
    $
    19.09
    
    
    $
    13.06
    
    
    $
    9.55
    
    
    $
    7.26
 
 Notes:(1)
    
    Our internal estimate, calculated using the average land sale prices paid in 2009 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, 2009.(4)
    
    Other liabilities include convertible debt and non-current contract liabilities.(5)
    
    The asset retirement obligation is based on our 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. - 46 -




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##### Table of Contents



TRUST UNITS
 
 The Trust Indenture
   Canadian Deposit Insurance Corporation Act
 
 The Trustee
    
    
    preparing all returns, filings and documents for which the trustee is responsible;
    
    preparing and filing tax returns on behalf of the Trust and its subsidiaries;
    
    approving and executing continuous disclosure documents;
 - 47 -




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##### Table of Contents




    
    managing the subsidiaries of the Trust;
    
    overseeing the management and stewardship of the Trusts assets including the
acquisition, exploration, development, operation and disposition of properties, the
marketing of production and risk management provision in respect thereof;
    
    all matters relating to offerings of securities;
    
    responsibility for any take-over bid, merger, amalgamation or arrangement involving
the Trust, including the implementation of any Unitholder rights protection plan;
    
    dealing with banks and other financial institutions;
    
    elections in respect of the Trusts entity classification for U.S. tax purposes;
    
    the maintenance of the listing of the securities of the Trust;
    
    the calling and holding of annual and/or special meetings of Unitholders;
    
    the determination and approval of distributions;
    
    all matters relating to the redemption of Trust Units;
    
    generally providing all other services and support as may be necessary or as
requested by the trustee for the administration of the Trust and that are not otherwise
expressly granted to the Corporation, including, but not limited to, evaluating the appropriate response to the SIFT
Legislation.
   
 Stock Exchange Listings
  
 Ownership Restrictions
  - 48 -




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Redemption Right
 in specie
 
 Conversion Rights
  
 Exchangeable Shares
  
 Voting at Meetings of Unitholders
    - 49 -




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Voting at Meetings of Corporation
  
 Termination of the Trust
  
    
    a vote may be held only if: (i) requested in writing by the holders of not less than
25 percent of the Trust Units, 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
  - 50 -




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THE ROYALTY INDENTURE
 
 Royalty Units
    
 The Royalty
  
    
    operating costs and capital expenditures;
    
    general and administrative costs;
    
    management fees and debt service charges;
    
    taxes or other charges payable by the Corporation; and
    
    any amounts paid into the reserve.
   - 51 -




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##### Table of Contents



Replacement of Properties
  
 The Trustee
   
 DISTRIBUTIONS
 
 General
 th th
 
 Historical Distributions
  - 52 -




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##### Table of Contents



Pengrowth Energy Trust -
Recent Developments  Changes to our Value Creation Strategy
 Risk Factors
  2009
    
    2008
    
    2007
    
    2006
    
    2005
    
    2004First Quarter
    
    $
    0.30
    
    
    $
    0.675
    
    
    $
    0.75
    
    
    $
    0.75
    
    
    $
    0.69
    
    
    $
    0.63Second Quarter
    
    
    0.30
    
    
    
    0.675
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.64Third Quarter
    
    
    0.27
    
    
    
    0.675
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.67Fourth Quarter
    
    
    0.21
    
    
    
    0.565
    
    
    
    0.675
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69Total
    
    $
    1.08
    
    
    $
    2.59
    
    
    $
    2.93
    
    
    $
    3.00
    
    
    $
    2.82
    
    
    $
    2.63
 Certain Canadian Federal Income Tax
Considerations and United States Federal Income Tax
Considerations
  2009
    
    
    2008
    
    
    2007
    
    
    2006
    
    
    2005
    
    
    2004Taxable Income(1)(per Trust Unit)
    
    $
    1.28
    
    
    $
    2.70
    
    
    $
    2.78
    
    
    $
    2.40
    
    
    $
    2.22
    
    
    $
    1.43(percent of distributions classified as taxable income)
    
    
    (100
    %)
    
    
    (100
    %)
    
    
    (95
    %)
    
    
    (80
    %)
    
    
    (80
    %)
    
    
    (55
    %)(percent of distributions classified as return of
capital)
    
    
    (
    )
    
    
    (
    )
    
    
    (5
    %)
    
    
    (20
    %)
    
    
    (20
    %)
    
    
    (45
    %)
 
 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.
 - 53 -




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Risk
Factors
 
 Restrictions on Distributions
  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.
 - 54 -




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##### Table of Contents



Consolidated Senior Debt:
    
    All obligations, liabilities and indebtedness that would be classified as debt on the consolidated
balance sheet of the Trust, including, without limitation, certain items including all indebtedness for
borrowed money, but excluding certain items.Consolidated Total Debt:
    
    The aggregate of Consolidated Senior Debt and Subordinated Debt.Consolidated EBITDA:
    
    The aggregate of the last four quarters net income from operations plus the sum of: income taxes; interest expense; all provisions for federal, provincial or other income and capital taxes; depreciation, depletion and amortization expense; and other non-cash amounts.Material Acquisition:
    
    An acquisition or series of acquisitions which increases the consolidated tangible assets of
Pengrowth by more than five 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;
 - 55 -




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##### Table of Contents




    
    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.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.
 
 CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
 
 Taxation of the Trust
 SIFT Legislation
    - 56 -




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##### Table of Contents



No assurance can be provided
that the SIFT Legislation will not apply to the Trust prior to 2011.
   
 Taxation of Unitholders Resident in Canada
   - 57 -




---



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Taxation of Unitholders who are Non-Residents of Canada
      - 58 -




---



##### Table of Contents



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 may  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 should
Unitholders not approve Pengrowths conversion to a dividend paying corporation. See  Risk
Factors  The SIFT Legislation has and may continue to materially and adversely affect the Trust,
the Unitholders and the value of the Trust Units .
 
 UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
    - 59 -




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Classification of the Trust as a Corporation
  
 Ownership and Disposition of Trust Units
 Distributions
 PFIC Status
  Sale, Exchange or Other Taxable Disposition of Trust Units
 PFIC Status
 - 60 -




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PFIC Status
     
 Other Considerations
 Foreign Tax Credits
  The Receipt of Canadian Currency
  - 61 -




---



##### Table of Contents



Information Reporting and Backup Withholding
  UNITED STATES HOLDERS SHOULD CONSULT THEIR TAX ADVISORS REGARDING THE TAX CONSEQUENCES TO THEM OF
THE OWNERSHIP AND DISPOSITION OF THE TRUST UNITS, INCLUDING THE EFFECTS OF UNITED STATES FEDERAL,
STATE AND LOCAL, NON-UNITED STATES AND OTHER TAX LAWS.
 
 INDUSTRY CONDITIONS
 
 Government Regulation
  
 Pricing and Marketing  Oil
  
 Pricing and Marketing  Natural Gas
  - 62 -




---



##### Table of Contents



Pricing and Marketing  Natural Gas Liquids
  
 Royalties
   Alberta
 ad valorem
    - 63 -




---



##### Table of Contents



British Columbia
 Net Profit Royalty Regulation,
    - 64 -




---



##### Table of Contents



Saskatchewan
  3 3
 3 3
  3
    Nova Scotia
   - 65 -




---



##### Table of Contents



Environmental Regulation
  
 Climate Change
 Federal
 Regulatory
Framework for Air Emissions Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas
Emissions
  Canadian Environmental Protection Act, 1999 2
  Alberta
 Climate Change and Emissions Management Act Specified Gas Reporting Regulation Specified Gas Emitters Regulation
 - 66 -




---



##### Table of Contents



2 2
  British Columbia
 Greenhouse Gas Reduction Targets
Act
 Saskatchewan
 An Act Respecting the
Management and Reduction of Greenhouse Gases and Adaptation to Climate Change.
 Nova Scotia
 Environmental Goals and Sustainable Prosperity Act
 General Discussion
  - 67 -




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##### Table of Contents



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, 2009.
 Low oil and natural gas prices could have a material adverse effect on our 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;
 - 68 -




---



##### Table of Contents




    
    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, which result from lower
commodity prices and the decision by Pengrowth to make capital expenditures using cash flow. A
reduction in distributions 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 may
negatively affect the market price of the Trust Units and distributions to our Unitholders.
  
    
    historical production from the area compared with production rates from similar producing
areas;
    
    the assumed effect of government regulation;
 - 69 -




---



##### Table of Contents




    
    assumptions about future commodity prices, exchange rates, production and development
costs, capital expenditures, abandonment costs, environmental liabilities, and applicable
royalty regimes;
    
    initial production rates;
    
    production decline rates;
    
    ultimate recovery of reserves;
    
    marketability of production; and
    
    other government levies that may be imposed over the producing life of reserves.
   If we are unable to acquire additional reserves, the value of the Trust Units and distributions to
our Unitholders may decline.
  Continued uncertainty in the credit markets may restrict the availability or increase the cost of
borrowing required for future development and acquisitions.
  - 70 -




---



##### Table of Contents



In the normal course of our business, we have entered into contractual arrangements with third
parties that subject us to the risk that such parties may default on their obligations.
  Our operation of oil and natural gas wells could subject us to potential environmental claims and
liabilities, which will be funded out of our cash flow and will reduce cash flow otherwise
available for distribution to 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.
  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
 - 71 -




---



##### Table of Contents



We are dependent on our management and the loss of our key management and other personnel could
negatively impact our business.
  A decline in our ability to market our 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.
   - 72 -




---



##### Table of Contents



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, the market
price of the Trust Units and distributions to our Unitholders.
   Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of
the Corporation. If the oil and natural gas reserves associated with the resource properties of
the Corporation are not supplemented through additional development or the acquisition of oil and
natural gas properties, our ability to continue to generate cash flow for distribution to
Unitholders may be adversely affected.
  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.
  - 73 -




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Changes in Canadian legislation could adversely affect the value of our Trust Units.
  The SIFT Legislation has and may continue to materially and adversely affect Pengrowth, the Unitholders
and the value of the Trust Units.
    If the Trust ceases to qualify as a
mutual fund trust prior to the imposition of the SIFT Legislation it would adversely affect the value of our
Trust Units.
   
    
    The Trust Units would cease to be a qualified investment for trusts governed by RRSPs,
RRIFs, RESPs and DPSPs, as defined in the Tax Act. Where, at the end of a month, a RRSP,
RRIF, RESP or DPSP holds Trust Units that ceased to be a qualified investment, the RRSP, RRIF,
RESP or DPSP, as the case may be, must, in respect of that month, pay a tax under Part XI.1 of
the Tax Act equal to 1 percent of the fair market value of the Trust Units at the time such
Trust Units were acquired by the RRSP, RRIF, RESP or DPSP. In addition, trusts governed by a
RRSP or a RRIF which hold Trust Units that are not qualified investments will be subject to
tax on the income attributable to the Trust Units while they are non-qualified investments,
including the full capital gains, if any, realized on the disposition of such Trust Units.
Where a trust governed by a RRSP or a RRIF acquires Trust Units that are not qualified
investments, the value of the investment will be included in the income of the annuitant for
the year of the acquisition. Trusts governed by RESPs which hold Trust Units that are not
qualified investments can have their registration revoked by the Canada Revenue Agency.
    
    The Trust would be required to pay a tax under Part XII.2 of the Tax Act. The payment of
Part XII.2 tax by the Trust may have adverse income tax consequences for certain Unitholders,
including non-resident persons and residents of Canada who are exempt from Part I tax.
    
    The Trust would not be entitled to use the capital gains refund mechanism otherwise
available for mutual fund trusts.
    
    The Trust Units would constitute taxable Canadian property for the purposes of the Tax
Act, potentially subjecting non-residents of Canada to tax pursuant to the Tax Act on the
disposition (or deemed disposition) of such Trust Units.
 Changes to accounting policies, including the implementation of IFRS, may result in significant
adjustments to our financial results, which could negatively impact our business, including increasing the
risk of failing a financial covenant contained within our Credit Facility.
 Distributions 
Restrictions on Distributions  Revolving Credit
Facility
 The ability of investors resident in the United States to enforce civil remedies may be negatively
affected for a number of reasons.
  - 74 -




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##### Table of Contents



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.
   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.
   - 75 -




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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.
  
    
    A non-United States entity treated as a corporation for United States federal income tax
purposes will be a PFIC if it generates primarily passive income or the greater part of its
assets generate, or are held for the production of, passive income. We currently believe that
we are not a PFIC although no assurance can be given that we will not be a PFIC in 2010 or
thereafter. If we were classified as a PFIC, for any year during which a United States
Unitholder owns Trust Units, such United States Unitholder would generally be subject to
special adverse rules including taxation at maximum ordinary income rates plus an interest
charge on both gains on sale and certain dividends. Certain elections may be available to a
United States Unitholders if we were classified as a PFIC to alleviate these adverse tax
consequences.
    
    Qualified dividend income received from the Trust before January 1, 2011 will be subject to
a maximum rate of United States federal income tax of 15 percent to a United States Holder that is
not a corporation, including an individual. This preferred rate may not be extended beyond
December 31, 2010.
 Changes in government regulations that affect the crude oil and natural gas industry could
adversely affect us and reduce our distributions to our Unitholders.
   - 76 -




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##### Table of Contents



Terrorist attacks and the threat of terrorist attacks may have an adverse impact on Pengrowth.
  Delays in business operations could adversely affect the Trusts distributions to Unitholders and
the market price of the Trust Units.
  
    
    restrictions imposed by lenders;
    
    accounting delays;
    
    delays in the sale or delivery of products;
    
    delays in the connection of wells to a gathering system;
    
    blowouts or other accidents;
    
    adjustments for prior periods;
    
    recovery by the operator of expenses incurred in the operation of the properties; or
    
    the establishment by the operator of reserves for these expenses.
  Changes in market-based factors may adversely affect the trading price of the Trust Units.
  The limited liability of Unitholders is uncertain.
  - 77 -




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##### Table of Contents



The redemption right of Unitholders is limited.
 Description of Trust Units  Redemption Right in specie
 The industry in which we operate exposes us to potential liabilities that may not be covered by
insurance.
  - 78 -




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##### Table of Contents



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)2009January
    
    
    12.33
    
    
    
    9.24
    
    
    
    10.15
    
    
    
    8,358,692
    
    
    
    10.11
    
    
    
    7.40
    
    
    
    8.31
    
    
    
    28,890,238February
    
    
    10.49
    
    
    
    6.33
    
    
    
    7.26
    
    
    
    8,912,881
    
    
    
    8.57
    
    
    
    5.07
    
    
    
    5.64
    
    
    
    29,011,962March
    
    
    8.15
    
    
    
    5.84
    
    
    
    7.10
    
    
    
    13,292,672
    
    
    
    6.67
    
    
    
    4.51
    
    
    
    5.58
    
    
    
    32,749,969April
    
    
    8.13
    
    
    
    6.71
    
    
    
    7.75
    
    
    
    7,903,867
    
    
    
    6.82
    
    
    
    5.30
    
    
    
    6.57
    
    
    
    22,218,019May
    
    
    9.75
    
    
    
    7.71
    
    
    
    9.50
    
    
    
    10,671,708
    
    
    
    8.85
    
    
    
    6.39
    
    
    
    8.76
    
    
    
    31,814,565June
    
    
    9.81
    
    
    
    8.68
    
    
    
    9.18
    
    
    
    8,358,692
    
    
    
    9.00
    
    
    
    7.50
    
    
    
    7.90
    
    
    
    28,810,956July
    
    
    9.09
    
    
    
    7.49
    
    
    
    8.78
    
    
    
    7,701,403
    
    
    
    8.39
    
    
    
    6.43
    
    
    
    8.23
    
    
    
    28,337,061August
    
    
    9.77
    
    
    
    8.85
    
    
    
    9.40
    
    
    
    7,476,432
    
    
    
    9.01
    
    
    
    8.21
    
    
    
    8.62
    
    
    
    21,763,092September
    
    
    11.33
    
    
    
    8.95
    
    
    
    11.33
    
    
    
    13,588,246
    
    
    
    10.54
    
    
    
    8.08
    
    
    
    10.51
    
    
    
    31,307,977October
    
    
    11.39
    
    
    
    9.60
    
    
    
    10.26
    
    
    
    23,603,708
    
    
    
    10.61
    
    
    
    8.80
    
    
    
    9.20
    
    
    
    47,559,265November
    
    
    10.52
    
    
    
    9.76
    
    
    
    10.13
    
    
    
    8,142,095
    
    
    
    10.04
    
    
    
    9.04
    
    
    
    9.61
    
    
    
    22,417,294December
    
    
    10.42
    
    
    
    9.40
    
    
    
    10.15
    
    
    
    10,736,778
    
    
    
    9.94
    
    
    
    8.88
    
    
    
    9.63
    
    
    
    26,691,909
  Toronto Stock ExchangeDebenture Price RangeHigh
    
    Low
    
    Close
    
    Volume(Canadian $ per Debenture)2009January
    
    
    97.00
    
    
    
    93.00
    
    
    
    96.50
    
    
    
    746,150February
    
    
    96.25
    
    
    
    91.50
    
    
    
    95.75
    
    
    
    1,079,000March
    
    
    95.50
    
    
    
    90.00
    
    
    
    93.00
    
    
    
    912,000April
    
    
    95.00
    
    
    
    92.00
    
    
    
    95.00
    
    
    
    7,555,000May
    
    
    99.95
    
    
    
    94.50
    
    
    
    99.55
    
    
    
    3,083,150June
    
    
    100.00
    
    
    
    99.50
    
    
    
    100.00
    
    
    
    3,468,000July
    
    
    101.50
    
    
    
    99.60
    
    
    
    100.50
    
    
    
    2,540,000August
    
    
    102.00
    
    
    
    100.65
    
    
    
    101.50
    
    
    
    742,000September
    
    
    102.99
    
    
    
    100.70
    
    
    
    101.85
    
    
    
    1,310,000October
    
    
    102.00
    
    
    
    101.50
    
    
    
    101.50
    
    
    
    1,623,000November
    
    
    102.75
    
    
    
    101.50
    
    
    
    102.75
    
    
    
    925,000December
    
    
    102.99
    
    
    
    102.00
    
    
    
    102.25
    
    
    
    1,342,000
 Pengrowth Energy Trust  Recent Developments  Convertible Debentures
 - 79 -




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DIRECTORS AND OFFICERS
  
 Directors and Officers of the Corporation
  Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)John
B.
Zaozirny(2)(3)
    
    Chairman and Director (Director since
    
    Vice Chair
    
    35,100Alberta, Canada
    
    1988)
    
    Canaccord Capital CorporationDerek W. Evans
    
    President, Chief Executive Officer and
    
    President and Chief
    
    155,380Alberta, Canada
    
    Director (since 2009)
    
    Executive Officer
Pengrowth CorporationThomas A. Cumming(3)(4)(5)
    
    Director (since 2000)
    
    Business Consultant
    
    8,678Alberta, CanadaWayne K. Foo(2)(4)
    
    Director (since 2006)
    
    President and Chief Executive
Officer
    
    4,273Alberta, Canada
    
    
    
    Parex  Resources Inc.
(energy company)James S. Kinnear
    
    Chairman Emeritus and Director (since 1988)
    
    President
    
    3,780,320Alberta, Canada
    
    
    
    Kinnear Financial LimitedJames D. McFarland(4)(5)
    
    Director (since 2010)
    
    Business Consultant
    
    Alberta, CanadaMichael
S. Parrett(2)(3)(5)
    
    Director (since 2004)
    
    Business Consultant
    
    4,000Ontario, CanadaA. Terence Poole(2)(5)
    
    Director (since 2005)
    
    Business Consultant
    
    40,000Alberta, CanadaD. Michael G. Stewart(3)(4)
    
    Director (since 2006)
    
    Corporate Director
    
    21,251Alberta, CanadaNicholas C.H. Villiers
    
    Director (since 2007)
    
    Business Consultant
    
    London, EnglandDouglas C. Bowles
    
    Vice President and Controller
    
    Vice President and
    
    36,590Alberta, Canada
    
    (since March 1, 2006)
    
    Controller PengrowthController (since 2005)
    
    CorporationJames E.A. Causgrove
    
    Vice President, Production and
    
    Vice President, Production
    
    75,015Alberta, Canada
    
    Operations (since 2005)
    
    and OperationsPengrowth CorporationWilliam G. Christensen
    
    Vice President, Strategic Planning and
    
    Vice President, Strategic
    
    56,514Alberta, Canada
    
    Reservoir Exploitation (since 2005)
    
    Planning and ReservoirExploitation PengrowthCorporationJames M. Donihee
    
    Vice President and Chief of Staff
    
    Vice President and Chief of
    
    36,607Alberta, Canada
    
    (since 2007)
    
    Staff Pengrowth Corporation
 - 80 -




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Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)Larry B. Strong
    
    Vice President, Geosciences (since 2005)
    
    Vice President, Geosciences
    
    53,981Alberta, Canada
    
    
    
    Pengrowth CorporationChristopher G. Webster
    
    Chief Financial Officer (since 2005)
    
    Chief Financial Officer
    
    120,295Alberta, Canada
    
    Treasurer (2000  2005)
    
    Pengrowth Corporation
 
 Notes:
 (1)
    
    As at December 31, 2009 and excluding Trust Units issuable upon the exercise of outstanding
 rights or deferred entitlement units.(1)
    
    Member of Corporate Governance Committee.(2)
    
    Member of Compensation Committee.(3)
    
    Member of Reserves, Operations and Environmental, Health and Safety Committee.(4)
    
    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.
 - 81 -




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Personal Bankruptcies
  
 Penalties or Sanctions
  (i)
    
    been subject to any penalties or sanctions imposed by a court relating to
securities legislation or by a securities regulatory authority or has entered into a
settlement agreement with a securities regulatory authority, other than penalties for
late filing of insider reports; or(ii)
    
    been subject to any other penalties or sanctions imposed by a court or
regulatory body that would likely be considered important to a reasonable investor in
making an investment decision.
 
 AUDIT COMMITTEE
 Audit Committees
 FinanciallyName
    
    Independent
    
    Literate
    
    Relevant Education and ExperienceThomas A. Cumming
    
    Yes
    
    Yes
    
    Mr. Cumming was President and
Chief Executive Officer of the
Alberta Stock Exchange from 1988
to 1999. His career also
includes 25 years with a major
Canadian bank both nationally
and internationally. He is
currently Chairman of Albertas
Electricity Balancing Pool, and
serves as a Director of the
Alberta Capital Market
Foundation. He is also a past
president of the Calgary Chamber
of Commerce. Mr. Cumming is a
professional engineer and holds
a Bachelor of Applied Science
degree in Engineering and
Business from the University of
Toronto.James D. McFarland
    
    Yes
    
    Yes
    
    Mr. McFarland has more than 37
years of experience in the oil
and gas industry, most recently
as President and CEO, director
and co-founder of Verenex Energy
Inc.  He has served in
senior executive roles as
Managing Director of Southern
Pacific Petroleum N.L. in
Australia, President and Chief
Operating Officer of Husky Oil
Limited and in a wide range of
upstream and corporate functions
in an earlier 23-year career
with Imperial Oil Limited and
other Exxon affiliates in
Canada, the US and western
Europe.Mr. McFarland is a member of the
Association of Professional
Engineers, Geologists and
Geophysicists of Alberta, and
the Society of Petroleum
Engineers International. Mr.
McFarland received a Bachelor of
Science in Chemical Engineering
from Queens University
and a Master of Science in
Petroleum Engineering from the
University of Alberta.
 - 82 -




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##### Table of Contents



FinanciallyName
    
    Independent
    
    Literate
    
    Relevant Education and ExperienceMichael S. Parrett
    
    Yes
    
    Yes
    
    Mr. Parrett is currently an
independent consultant providing
advisory service to various
companies in Canada and the
United States. Mr. Parrett is
Chairman of Gabriel Resources
Limited, a director of
Stillwater Mining Company 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.
 
 Principal Accountant Fees and Services
  2009
    
    2008Audit Fees
    
    
    1,314
    
    
    
    1,037Audit Related Fees
    
    
    
    
    
    
    Tax Fees
    
    
    208
    
    
    
    98All Other Fees
    
    
    
    
    
    
    Total
    
    
    1,522
    
    
    
    1,135
 Audit Fees
  Audit-Related Fees
  Tax Fees
  
 Pre-approval Policies and Procedures
  - 83 -




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de minimis
 
 CONFLICTS OF INTEREST
  
    
    the issuance of additional Trust Units;
    
    material acquisitions and dispositions of properties;
    
    material capital expenditures;
    
    borrowing; and
    
    the payment of distributable cash.
 Protection of Minority Security Holders in
Special Transactions.
  
 LEGAL PROCEEDINGS
  
 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
   - 84 -




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INTERESTS OF EXPERTS
   
 AUDITORS, TRANSFER AGENT AND REGISTRAR
  
 MATERIAL CONTRACTS
  1.
    
    Trust Indenture;2.
    
    Royalty Indenture;3.
    
    the Corporations unanimous shareholder agreement;4.
    
    the Fifth Amended and Restated Credit Agreement dated June 17, 2007 between Pengrowth and a
syndicate of eleven financial institutions concerning the Credit Facility;5.
    
    the Note Purchase Agreement dated August 21, 2008 concerning the 2008 Senior Notes;6.
    
    the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes;7.
    
    the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes;8.
    
    the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes;9.
    
    the Distribution Agreement; and10.
    
    the underwriting agreement relating to the October 23, 2009 bought deal public offering of
28,847,000 Trust Units.
  
 CODE OF ETHICS
 U.S.
Securities Exchange Act of 1934 www.pengrowth.com
 - 85 -




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OFF-BALANCE SHEET ARRANGEMENTS
  
 DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE
    
 ADDITIONAL INFORMATION
  - 86 -




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www.pengrowth.com  investorrelations@pengrowth.com
 - 87 -




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




---



##### Table of Contents



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, 2009. The
reserves data are estimates of proved reserves and probable reserves and related future net
revenue as at December 31, 2009, 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, 2009, 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, 2010
    
    Canada
    
    
    
    
    
    $
    4,885
    
    
    
    
    
    
    $
    4,885
 5.
    
    In our opinion, the reserves data respectively evaluated by us have, in all material
respects, been determined and are in accordance with the COGE Handbook.6.
    
    We have no responsibility to update our reports referred to in paragraph 4 for events and
circumstances occurring after their respective preparation dates.




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##### Table of Contents



7.
    
    Because the reserves data are based on judgments regarding future events, actual results will
vary and the variations may be material. However, any variations should be consistent with
the fact that reserves are categorized according to the probability of their recovery. EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 5, 2010.(signed) Doug R. SuttonDoug R. Sutton, P.Eng.Vice-President - 2 -




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




---



##### Table of Contents



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.




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##### Table of Contents



/s/
Derek W. EvansDerek W. EvansPresident and Chief Executive Officer
Pengrowth Corporation/s/
William G. ChristensenWilliam G. ChristensenVice President, Strategic Planning and Reservoir Exploitation
Pengrowth Corporation/s/
Wayne FooWayne FooDirector
Pengrowth Corporation/s/
D. Michael G. StewartD. Michael G. StewartDirector
Pengrowth Corporation  - 2 -




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APPENDIX C TO AIF
 Audit Committee Terms of Reference




---



##### Table of Contents



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




---



##### Table of Contents



-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




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##### Table of Contents



-3- and related managements discussion and analysis and interim
earnings press releases. This review should include discussions with management, the internal
auditors and the external auditors of significant issues regarding accounting principles,
practices and judgements. Discuss any significant changes to Pengrowths accounting
principles and any items required to be communicated by the external auditors in accordance
with Assurance and Related Services Guideline #11 (AuG-11).3.
    
    Ensure that adequate procedures are in place for the review of Pengrowths public disclosure
of financial information extracted or derived from Pengrowths financial statements, other
than the public disclosure referred to in paragraph 2 above and periodically assess the
adequacy of those procedures.4.
    
    Be responsible for reviewing the disclosure contained in Pengrowths annual information form
as required by Form 52-110F1 Audit Committee Information Required in an AIF, attached to 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.




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##### Table of Contents



-4- Discretionary Duties
  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 Board Chairman and the President and
CEO.
 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.




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-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




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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.




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




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B-1 Schedule B   Excerpts from Rule 10A-3 of the Securities and Exchange Act of 1934
 Standard of Independence
 b.
    
    Required standards.1.
    
    Independence.
 i.
    
    Each member of the audit committee must be a member of the board of directors
of the listed issuer, and must otherwise be independent; provided that, where a listed
issuer is one of two dual holding companies, those companies may designate one audit
committee for both companies so long as each member of the audit committee is a member
of the board of directors of at least one of such dual holding companies.ii.
    
    Independence requirements for non-investment company issuers.In order to be
considered to be independent for purposes of this paragraph (b)(1), a member of an
audit committee of a listed issuer that is not an investment company may not, other
than in his or her capacity as a member of the audit committee, the board of directors,
or any other board committee:
 A.
    
    Accept directly or indirectly any consulting, advisory, or
other compensatory fee from the issuer or any subsidiary thereof, provided
that, unless the rules of the national securities exchange or national
securities association provide otherwise, compensatory fees do not include the
receipt of fixed amounts of compensation under a retirement plan (including
deferred compensation) for prior service with the listed issuer (provided that
such compensation is not contingent in any way on continued service); orB.
    
    Be an affiliated person of the issuer or any subsidiary
thereof.
 e.
    
    Definitions. Unless the context otherwise requires, all terms used in this section have the
same meaning as in the Act. In addition, unless the context otherwise requires, the following
definitions apply for purposes of this section: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; and2.
    
    Is not an executive officer of the specified
person.
 B.
    
    Paragraph (e)(1)(ii)(A) of this section only creates a safe
harbor position that a person does not control a specified person. The
existence of the safe harbor does not create a presumption in any way that a
person exceeding the ownership
requirement in paragraph (e)(1)(ii)(A)(1) of this section controls or is
otherwise an affiliate of a specified person.




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




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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):




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C-2




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APPENDIX B
 MANAGEMENTS DISCUSSION AND ANALYSIS




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Summary
of Financial & Operating Results
 Three Months ended December 31
    
    Twelve Months ended December 31(monetary amounts in thousands, except per unit amounts)
    
    
    
    2009
    
    2008
    
    % Change
    
    2009
    
    2008
    
    % ChangeSTATEMENT OF INCOMEOil and gas sales
    
    
    
    $
    359,296
    
    
    $
    392,158
    
    
    
    (8
    )
    
    $
    1,343,167
    
    
    $
    1,919,049
    
    
    
    (30
    )Net income
    
    
    
    $
    50,523
    
    
    $
    148,688
    
    
    
    (66
    )
    
    $
    84,853
    
    
    $
    395,850
    
    
    
    (79
    )Net income per trust unit
    
    
    
    $
    0.18
    
    
    $
    0.58
    
    
    
    (69
    )
    
    $
    0.32
    
    
    $
    1.58
    
    
    
    (80
    )CASH FLOWCash flow from operating activities
    
    
    
    $
    149,933
    
    
    $
    154,807
    
    
    
    (3
    )
    
    $
    551,350
    
    
    $
    912,516
    
    
    
    (40
    )Cash flow from operating activities per trust unit
    
    
    
    $
    0.53
    
    
    $
    0.61
    
    
    
    (13
    )
    
    $
    2.09
    
    
    $
    3.65
    
    
    
    (43
    )Distributions declared
    
    
    
    $
    60,880
    
    
    $
    144,663
    
    
    
    (58
    )
    
    $
    287,853
    
    
    $
    651,015
    
    
    
    (56
    )Distributions declared per trust unit
    
    
    
    $
    0.21
    
    
    $
    0.565
    
    
    
    (63
    )
    
    $
    1.08
    
    
    $
    2.590
    
    
    
    (58
    )Ratio of distributions declared over
cash flow from operating activities
    
    
    
    
    41
    %
    
    
    93
    %
    
    
    
    
    
    
    52
    %
    
    
    71
    %Capital expenditures
    
    
    
    $
    46,215
    
    
    $
    125,876
    
    
    
    (63
    )
    
    $
    207,451
    
    
    $
    401,928
    
    
    
    (48
    )Capital expenditures per trust unit
    
    
    
    $
    0.16
    
    
    $
    0.49
    
    
    
    (67
    )
    
    $
    0.79
    
    
    $
    1.61
    
    
    
    (51
    )Weighted average number of trust units outstanding (000s)
    
    
    
    
    282,298
    
    
    
    255,473
    
    
    
    11
    
    
    
    264,121
    
    
    
    250,182
    
    
    
    6BALANCE SHEETWorking capital deficiency
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (217,007
    ) (1)
    
    $
    (70,159
    )
    
    
    209Property, plant and equipment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    3,789,369
    
    
    $
    4,251,381
    
    
    
    (11
    )Long term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    907,599
    
    
    $
    1,524,503
    
    
    
    (40
    )Trust unitholders equity
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    2,795,201
    
    
    $
    2,663,805
    
    
    
    5Trust unitholders equity per trust unit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    9.64
    
    
    $
    10.40
    
    
    
    (7
    )Currency (U.S.$/Cdn$) (closing rate at period end)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.9515
    
    
    
    0.8210Number of trust units outstanding at period end (000s)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    289,835
    
    
    
    256,076
    
    
    
    13AVERAGE DAILY PRODUCTIONCrude oil
(bbls)
    
    
    
    
    21,948
    
    
    
    24,236
    
    
    
    (9
    )
    
    
    22,841
    
    
    
    24,416
    
    
    
    (6
    )Heavy oil
(bbls)
    
    
    
    
    7,235
    
    
    
    8,217
    
    
    
    (12
    )
    
    
    7,551
    
    
    
    8,122
    
    
    
    (7
    )Natural gas (mcf)
    
    
    
    
    232,682
    
    
    
    241,709
    
    
    
    (4
    )
    
    
    237,217
    
    
    
    240,825
    
    
    
    (1
    )Natural gas
liquids (bbls)
    
    
    
    
    9,564
    
    
    
    10,634
    
    
    
    (10
    )
    
    
    9,590
    
    
    
    9,315
    
    
    
    3Total production (boe)
    
    
    
    
    77,529
    
    
    
    83,373
    
    
    
    (7
    )
    
    
    79,518
    
    
    
    81,991
    
    
    
    (3
    )TOTAL PRODUCTION(mboe)
    
    
    
    
    7,133
    
    
    
    7,670
    
    
    
    (7
    )
    
    
    29,024
    
    
    
    30,009
    
    
    
    (3
    )PRODUCTION PROFILECrude oil
    
    
    
    
    28
    %
    
    
    29
    %
    
    
    
    
    
    
    29
    %
    
    
    30
    %Heavy oil
    
    
    
    
    9
    %
    
    
    10
    %
    
    
    
    
    
    
    9
    %
    
    
    10
    %Natural gas
    
    
    
    
    50
    %
    
    
    48
    %
    
    
    
    
    
    
    50
    %
    
    
    49
    %Natural gas liquids
    
    
    
    
    13
    %
    
    
    13
    %
    
    
    
    
    
    
    12
    %
    
    
    11
    %AVERAGE REALIZED PRICES(after commodity risk management)Crude oil (per bbl)
    
    
    
    $
    75.79
    
    
    $
    65.87
    
    
    
    15
    
    
    $
    72.36
    
    
    $
    77.78
    
    
    
    (7
    )Heavy oil (per bbl)
    
    
    
    $
    62.16
    
    
    $
    42.20
    
    
    
    47
    
    
    $
    52.72
    
    
    $
    75.77
    
    
    
    (30
    )Natural gas (per mcf)
    
    
    
    $
    5.45
    
    
    $
    7.40
    
    
    
    (26
    )
    
    $
    5.14
    
    
    $
    8.19
    
    
    
    (37
    )Natural gas liquids (per bbl)
    
    
    
    $
    54.52
    
    
    $
    43.87
    
    
    
    24
    
    
    $
    42.12
    
    
    $
    70.67
    
    
    
    (40
    )Average realized price per boe
    
    
    
    $
    50.35
    
    
    $
    50.34
    
    
    
    0
    
    
    $
    46.19
    
    
    $
    62.76
    
    
    
    (26
    )PROVED PLUS PROBABLE RESERVESCrude oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    112,249
    
    
    
    121,289
    
    
    
    (7
    )Heavy oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    27,724
    
    
    
    27,728
    
    
    
    0Natural gas (bcf)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    757
    
    
    
    852
    
    
    
    (11
    )Natural gas liquids (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    29,587
    
    
    
    32,442
    
    
    
    (9
    )Total oil equivalent (mboe)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    295,734
    
    
    
    323,463
    
    
    
    (9
    )SUMMARY OF TRUST UNIT TRADINGNYSE  PGH ($U.S.)High
    
    $
    10.52
    
    
    $
    15.00
    
    
    
    
    
    
    $
    10.54
    
    
    $
    21.90Low
    
    $
    8.81
    
    
    $
    6.84
    
    
    
    
    
    
    $
    4.51
    
    
    $
    6.84Close
    
    $
    9.63
    
    
    $
    7.62
    
    
    
    
    
    
    $
    9.63
    
    
    $
    7.62TSX  PGF.UN ($Cdn)High
    
    $
    11.39
    
    
    $
    15.98
    
    
    
    
    
    
    $
    12.33
    
    
    $
    21.56Low
    
    $
    9.40
    
    
    $
    8.55
    
    
    
    
    
    
    $
    5.84
    
    
    $
    8.55Close
    
    $
    10.15
    
    
    $
    9.35
    
    
    
    
    
    
    $
    10.15
    
    
    $
    9.35
 
 (1)
    
    Includes $157.5 million current portion of long term debt.
 Note regarding currency: all figures contained within this report are quoted in Canadian dollars unless otherwise indicated.
 3




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Managements Discussion & Analysis
  Frequently Recurring Terms
   Advisory Regarding Forward-Looking Statements
 Private
Securities Litigation Reform Act of 1995
   4




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www.sedar.com www.sec.gov
   Critical Accounting Estimates
      5




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Non-GAAP Financial Measures
     Non-GAAP Operational Measures
   Currency
  6




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OVERVIEW
 Three months ended
    
    Twelve months endedDec 31, 2009
    
    
    Sept 30, 2009

        
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Production (boe/d)
    
    
    77,529
    
    
    
    78,135
    
    
    
    83,373
    
    
    
    79,518
    
    
    
    81,991Net capital expenditures ($000s)
    
    
    46,215
    
    
    
    44,047
    
    
    
    125,876
    
    
    
    207,451
    
    
    
    401,928Netback ($/boe)
    
    
    26.63
    
    
    
    24.72
    
    
    
    26.23
    
    
    
    25.38
    
    
    
    34.78Cash flows from operating activities ($000s)
    
    
    149,933
    
    
    
    162,915
    
    
    
    154,807
    
    
    
    551,350
    
    
    
    912,516Net income ($000s)
    
    
    50,523
    
    
    
    78,290
    
    
    
    148,688
    
    
    
    84,853
    
    
    
    395,850Included in net income:Realized gain (loss) on commodity risk management
($000s)
    
    
    27,855
    
    
    
    43,406
    
    
    
    21,021
    
    
    
    171,147
    
    
    
    (194,342
    )Unrealized gain (loss) on commodity risk
management ($000s)
    
    
    (40,101
    )
    
    
    (5,609
    )
    
    
    292,249
    
    
    
    (173,726
    )
    
    
    249,899Unrealized foreign exchange gain (loss) on foreign
denominated debt ($000s)
    
    
    17,660
    
    
    
    89,960
    
    
    
    (127,207
    )
    
    
    148,295
    
    
    
    (172,626
    )
     RESULTS OF OPERATIONS
  Production
  7




---



##### Table of Contents



Daily Production
 Three months ended
    
    Twelve months endedDec 31,
    
    % of
    
    Sept 30,
    
    % of
    
    Dec 31,
    
    % of
    
    Dec 31,
    
    % of
    
    Dec 31,
    
    % of2009
    
    total
    
    2009
    
    total
    
    2008
    
    total
    
    2009
    
    total
    
    2008
    
    totalLight crude oil (bbls)
    
    
    21,948
    
    
    
    28
    
    
    
    22,930
    
    
    
    29
    
    
    
    24,236
    
    
    
    29
    
    
    
    22,841
    
    
    
    29
    
    
    
    24,416
    
    
    
    30Heavy oil (bbls)
    
    
    7,235
    
    
    
    9
    
    
    
    7,480
    
    
    
    10
    
    
    
    8,217
    
    
    
    10
    
    
    
    7,551
    
    
    
    9
    
    
    
    8,122
    
    
    
    10Natural gas (mcf)
    
    
    232,682
    
    
    
    50
    
    
    
    232,444
    
    
    
    50
    
    
    
    241,709
    
    
    
    48
    
    
    
    237,217
    
    
    
    50
    
    
    
    240,825
    
    
    
    49Natural gas liquids (bbls)
    
    
    9,564
    
    
    
    13
    
    
    
    8,984
    
    
    
    11
    
    
    
    10,634
    
    
    
    13
    
    
    
    9,590
    
    
    
    12
    
    
    
    9,315
    
    
    
    11Total boe per day
    
    
    77,529
    
    
    
    
    
    
    
    78,135
    
    
    
    
    
    
    
    83,373
    
    
    
    
    
    
    
    79,518
    
    
    
    
    
    
    
    81,991
     8




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##### Table of Contents



Capital Expenditures
 Three months ended
    
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Drilling, completions and facilities
    
    
    40.2
    
    
    
    30.8
    
    
    
    82.6
    
    
    
    146.2
    
    
    
    276.5Drilling Royalty Credits
    
    
    (5.1
    )
    
    
    (4.2
    )
    
    
    
    
    
    
    (9.3
    )
    
    
    Net drilling, completions and facilities
    
    
    35.1
    
    
    
    26.6
    
    
    
    82.6
    
    
    
    136.9
    
    
    
    276.5Seismic
acquisitions(1)
    
    
    0.2
    
    
    
    
    
    
    
    0.5
    
    
    
    4.5
    
    
    
    7.6Maintenance capital
    
    
    8.8
    
    
    
    13.3
    
    
    
    26.2
    
    
    
    48.5
    
    
    
    57.5Land purchases(2)
    
    
    0.5
    
    
    
    0.2
    
    
    
    2.3
    
    
    
    2.9
    
    
    
    26.7Net development capital
    
    
    44.6
    
    
    
    40.1
    
    
    
    111.6
    
    
    
    192.8
    
    
    
    368.3Lindbergh Project
    
    
    0.3
    
    
    
    1.8
    
    
    
    10.4
    
    
    
    9.4
    
    
    
    20.0Development capital
    
    
    44.9
    
    
    
    41.9
    
    
    
    122.0
    
    
    
    202.2
    
    
    
    388.3Other capital
    
    
    1.3
    
    
    
    2.1
    
    
    
    3.8
    
    
    
    5.2
    
    
    
    13.6Total net capital expenditures
    
    
    46.2
    
    
    
    44.0
    
    
    
    125.8
    
    
    
    207.4
    
    
    
    401.9Business acquisitions
    
    
    
    
    
    
    
    
    
    
    0.2
    
    
    
    
    
    
    
    90.4Property acquisitions
    
    
    25.3
    
    
    
    (0.1
    )
    
    
    0.2
    
    
    
    35.7
    
    
    
    35.9Proceeds on property dispositions
    
    
    (34.2
    )
    
    
    0.4
    
    
    
    (20.4
    )
    
    
    (41.9
    )
    
    
    (17.4
    )Net capital expenditures and acquisitions
    
    
    37.3
    
    
    
    44.3
    
    
    
    105.8
    
    
    
    201.2
    
    
    
    510.8
 (1) Seismic acquisitions are net of seismic sales revenue.(2) Prior period restated to conform to presentation in the current period.
   Drilling, Completions,
    
    
    
    
    
    
    
    
    
    Seismic($ millions)
    
    Facilities
    
    Drilling Credits
    
    Maintenance
    
    Acquisitions
    
    TotalConventional Gas Properties
    
    
    56.2
    
    
    
    (6.6
    )
    
    
    8.9
    
    
    
    2.3
    
    
    
    60.8Light Oil Properties
    
    
    36.5
    
    
    
    (0.7
    )
    
    
    26.2
    
    
    
    2.0
    
    
    
    64.0Shallow/Unconventional Gas
    
    
    29.6
    
    
    
    (1.5
    )
    
    
    3.6
    
    
    
    0.1
    
    
    
    31.8Heavy Oil Properties
    
    
    14.3
    
    
    
    (0.5
    )
    
    
    4.0
    
    
    
    0.1
    
    
    
    17.9SOEP
    
    
    9.6
    
    
    
    
    
    
    
    5.8
    
    
    
    
    
    
    
    15.4Lindbergh
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9.4Land
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.9Development Capital
    
    
    146.2
    
    
    
    (9.3
    )
    
    
    48.5
    
    
    
    4.5
    
    
    
    202.2
   Reserves
   9




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##### Table of Contents



Acquisitions and Dispositions
    Pricing and Commodity Risk Management
     Volume
    
    ReferenceRemaining term
    
    (bbl/d)
    
    Point
    
    Price per bblFinancial:Jan 1, 2010 - Dec 31, 2010
    
    
    12,500
    
    
    WTI (1)
    
    
    
    $
    82.09
    CdnJan 1, 2011 - Dec 31, 2011
    
    
    500
    
    
    WTI (1)
    
    
    
    $
    82.44
    Cdn
 (1)
    
    Associated Cdn $/U.S. $ foreign exchange rate has been fixed
  Volume
    
    ReferenceRemaining term
    
    (mmbtu/d)
    
    Point
    
    Price per mmbtuFinancial:Jan 1, 2010 - Dec 31, 2010
    
    
    97,151
    
    
    AECO
    
    
    
    $
    6.10
    CdnJan 1, 2010 - Dec 31, 2010
    
    
    5,000
    
    
    Chicago MI (1)
    
        
    
    $
    6.78
    CdnJan 1, 2011 - Dec 31, 2011
    
    
    33,174
    
    
    AECO
    
    
    
    $
    5.77
    CdnJan 1, 2011 - Dec 31, 2011
    
    
    5,000
    
    
    Chicago MI (1)
    
    
    
    $
    6.78
    Cdn
 (1)
    
    Associated Cdn $/U.S. $ foreign exchange rate has been fixed
  Volume
    
    ReferenceRemaining term
    
    (mwh)
    
    Point
    
    Price per mwhFinancial:Jan 1, 2010 - Dec 31, 2010
    
    
    20
    
    
    AESO
    
    
    
    $
    47.66
    Cdn
   10




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##### Table of Contents



Average Realized Prices
 Three months ended
    
    Twelve months ended(Cdn$)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Light crude oil (per bbl)
    
    
    74.37
    
    
    
    69.28
    
    
    
    60.76
    
    
    
    63.94
    
    
    
    98.20after realized commodity risk management
    
    
    75.79
    
    
    
    74.40
    
    
    
    65.87
    
    
    
    72.36
    
    
    
    77.78Heavy oil (per bbl)
    
    
    62.16
    
    
    
    59.21
    
    
    
    42.20
    
    
    
    52.72
    
    
    
    75.77Natural gas (per mcf)
    
    
    4.28
    
    
    
    2.82
    
    
    
    6.97
    
    
    
    3.97
    
    
    
    8.32after realized commodity risk management
    
    
    5.45
    
    
    
    4.34
    
    
    
    7.40
    
    
    
    5.14
    
    
    
    8.19Natural gas liquids (per bbl)
    
    
    54.52
    
    
    
    41.86
    
    
    
    43.87
    
    
    
    42.12
    
    
    
    70.67Total per boe
    
    
    46.44
    
    
    
    39.18
    
    
    
    47.60
    
    
    
    40.29
    
    
    
    69.24after realized commodity risk management
    
    
    50.35
    
    
    
    45.22
    
    
    
    50.34
    
    
    
    46.19
    
    
    
    62.76Other production income
    
    
    0.02
    
    
    
    0.03
    
    
    
    0.78
    
    
    
    0.08
    
    
    
    1.19Total oil and gas sales per boe
    
    
    50.37
    
    
    
    45.25
    
    
    
    51.12
    
    
    
    46.27
    
    
    
    63.95Benchmark pricesWTI oil (U.S.$  per bbl)
    
    
    76.19
    
    
    
    68.30
    
    
    
    58.73
    
    
    
    61.80
    
    
    
    99.65AECO spot gas (Cdn$  per mmbtu)
    
    
    4.23
    
    
    
    3.03
    
    
    
    6.78
    
    
    
    4.14
    
    
    
    8.12NYMEX gas (U.S.$  per mmbtu)
    
    
    4.17
    
    
    
    3.39
    
    
    
    6.94
    
    
    
    3.99
    
    
    
    9.04Currency (U.S.$/Cdn$)
    
    
    0.95
    
    
    
    0.91
    
    
    
    0.83
    
    
    
    0.88
    
    
    
    0.94
  Commodity Risk Management Gains (Losses)
 Three months ended
    
    Twelve months endedRealized
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Light crude oil ($ millions)
    
    
    2.9
    
    
    
    10.8
    
    
    
    11.4
    
    
    
    70.2
    
    
    
    (182.5
    )Light crude oil ($  per bbl)
    
    
    1.42
    
    
    
    5.12
    
    
    
    5.11
    
    
    
    8.42
    
    
    
    (20.42
    )Natural gas ($ millions)
    
    
    25.0
    
    
    
    32.6
    
    
    
    9.6
    
    
    
    101.0
    
    
    
    (11.8
    )Natural gas ($  per mcf)
    
    
    1.17
    
    
    
    1.52
    
    
    
    0.43
    
    
    
    1.17
    
    
    
    (0.13
    )Combined ($ millions)
    
    
    27.9
    
    
    
    43.4
    
    
    
    21.0
    
    
    
    171.1
    
    
    
    (194.3
    )Combined ($  per boe)
    
    
    3.91
    
    
    
    6.04
    
    
    
    2.74
    
    
    
    5.90
    
    
    
    (6.48
    )UnrealizedTotal unrealized risk management assets (liabilities)at period end ($ millions)
    
    
    (9.0
    )
    
    
    31.1
    
    
    
    164.7
    
    
    
    (9.0
    )
    
    
    164.7Less: Unrealized risk management assets (liabilities)at beginning of period ($ millions)
    
    
    31.1
    
    
    
    36.7
    
    
    
    (127.6
    )
    
    
    164.7
    
    
    
    (85.2
    )Unrealized (loss) gain on risk management contracts
    
    
    (40.1
    )
    
    
    (5.6
    )
    
    
    292.3
    
    
    
    (173.7
    )
    
    
    249.9
   11




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##### Table of Contents



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
    
    2009
    
    total
    
    2009
    
    total
    
    2008
    
    total
    
    2009
    
    total
    
    2008
    
    totalLight crude oil
    
    
    153.0
    
    
    
    43
    
    
    
    157.0
    
    
    
    48
    
    
    
    146.9
    
    
    
    37
    
    
    
    603.2
    
    
    
    45
    
    
    
    695.1
    
    
    
    36Natural gas
    
    
    116.8
    
    
    
    33
    
    
    
    92.7
    
    
    
    28
    
    
    
    164.5
    
    
    
    42
    
    
    
    444.8
    
    
    
    33
    
    
    
    722.1
    
    
    
    38Natural gas liquids
    
    
    47.9
    
    
    
    13
    
    
    
    34.6
    
    
    
    11
    
    
    
    42.9
    
    
    
    11
    
    
    
    147.4
    
    
    
    11
    
    
    
    240.9
    
    
    
    12Heavy oil
    
    
    41.4
    
    
    
    11
    
    
    
    40.7
    
    
    
    13
    
    
    
    31.9
    
    
    
    8
    
    
    
    145.3
    
    
    
    11
    
    
    
    225.3
    
    
    
    12Brokered sales/sulphur
    
    
    0.2
    
    
    
    
    
    
    
    0.3
    
    
    
    
    
    
    
    5.9
    
    
    
    2
    
    
    
    2.5
    
    
    
    
    
    
    
    35.6
    
    
    
    2Total oil and gas sales
    
    
    359.3
    
    
    
    
    
    
    
    325.3
    
    
    
    
    
    
    
    392.1
    
    
    
    
    
    
    
    1,343.2
    
    
    
    
    
    
    
    1,919.0
 Oil and Gas Sales  Price and Volume Analysis
  ($ millions)
    
    Light oil
    
    Natural gas
    
    NGLs
    
    Heavy oil
    
    Other (1)
    
    TotalYear ended Dec 31, 2008
    
    
    695.1
    
    
    
    722.1
    
    
    
    240.9
    
    
    
    225.3
    
    
    
    35.6
    
    
    
    1,919.0Effect of change in product prices
    
    
    (285.7
    )
    
    
    (377.2
    )
    
    
    (99.9
    )
    
    
    (63.5
    )
    
    
    
    
    
    
    (826.3
    )Effect of change in sales volumes
    
    
    (58.8
    )
    
    
    (13.0
    )
    
    
    6.4
    
    
    
    (16.5
    )
    
    
    
    
    
    
    (81.9
    )Effect of change in realized commodity
risk management activities
    
    
    252.7
    
    
    
    112.8
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    365.5Other
    
    
    (0.1
    )
    
    
    0.1
    
    
    
    
    
    
    
    
    
    
    
    (33.1
    )
    
    
    (33.1
    )Year ended Dec 31, 2009
    
    
    603.2
    
    
    
    444.8
    
    
    
    147.4
    
    
    
    145.3
    
    
    
    2.5
    
    
    
    1,343.2(1) Primarily sulphur sales
 Processing and Other Income
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Processing & other income
    
    
    2.5
    
    
    
    3.4
    
    
    
    2.3
    
    
    
    15.5
    
    
    
    15.5$  per boe
    
    
    0.35
    
    
    
    0.48
    
    
    
    0.31
    
    
    
    0.54
    
    
    
    0.52
   Royalty Expense
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Royalty expense
    
    
    71.0
    
    
    
    49.7
    
    
    
    80.7
    
    
    
    207.6
    
    
    
    434.0$  per boe
    
    
    9.95
    
    
    
    6.91
    
    
    
    10.51
    
    
    
    7.15
    
    
    
    14.46Royalties as a percent of sales
    
    
    19.7
    %
    
    
    15.3
    %
    
    
    20.6
    %
    
    
    15.5
    %
    
    
    22.6
    %Royalties as a percent of sales
excluding realized risk
management contracts
    
    
    21.4
    %
    
    
    17.6
    %
    
    
    21.7
    %
    
    
    17.7
    %
    
    
    20.5
    %
 12




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##### Table of Contents



Operating Expenses
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Operating expenses
    
    
    92.4
    
    
    
    92.8
    
    
    
    104.1
    
    
    
    381.2
    
    
    
    418.5$  per boe
    
    
    12.95
    
    
    
    12.91
    
    
    
    13.57
    
    
    
    13.13
    
    
    
    13.95
   Net Operating Expenses
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Net operating expenses
    
    
    89.9
    
    
    
    89.4
    
    
    
    101.8
    
    
    
    365.7
    
    
    
    403.0$  per boe
    
    
    12.59
    
    
    
    12.43
    
    
    
    13.27
    
    
    
    12.59
    
    
    
    13.43
  Transportation Costs
 Three months ended
    
    Twelve months ended($ millions)
    
Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Light oil transportation
    
    
    1.2
    
    
    
    1.6
    
    
    
    0.4
    
    
    
    4.7
    
    
    
    3.4$  per bbl
    
    
    0.58
    
    
    
    0.78
    
    
    
    0.19
    
    
    
    0.56
    
    
    
    0.38Natural gas transportation
    
    
    2.9
    
    
    
    2.2
    
    
    
    2.3
    
    
    
    8.8
    
    
    
    9.1$  per mcf
    
    
    0.14
    
    
    
    0.10
    
    
    
    0.10
    
    
    
    0.10
    
    
    
    0.10
  13




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##### Table of Contents



Amortization of Injectants for Miscible Floods
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Purchased and capitalized
    
    
    4.9
    
    
    
    1.7
    
    
    
    5.4
    
    
    
    13.3
    
    
    
    21.0Amortization
    
    
    4.4
    
    
    
    4.8
    
    
    
    5.9
    
    
    
    20.0
    
    
    
    25.9
   Operating Netbacks
    14




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##### Table of Contents



Three months ended
    
    Twelve months endedCombined Netbacks ($ per boe)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Oil & gas sales
    
    
    50.37
    
    
    
    45.25
    
    
    
    51.12
    
    
    
    46.27
    
    
    
    63.95Processing and other income
    
    
    0.35
    
    
    
    0.48
    
    
    
    0.31
    
    
    
    0.54
    
    
    
    0.52Royalties
    
    
    (9.95
    )
    
    
    (6.91
    )
    
    
    (10.51
    )
    
    
    (7.15
    )
    
    
    (14.46
    )Operating expenses
    
    
    (12.95
    )
    
    
    (12.91
    )
    
    
    (13.57
    )
    
    
    (13.13
    )
    
    
    (13.95
    )Transportation costs
    
    
    (0.57
    )
    
    
    (0.52
    )
    
    
    (0.35
    )
    
    
    (0.46
    )
    
    
    (0.42
    )Amortization of injectants
    
    
    (0.62
    )
    
    
    (0.67
    )
    
    
    (0.77
    )
    
    
    (0.69
    )
    
    
    (0.86
    )Operating netback
    
    
    26.63
    
    
    
    24.72
    
    
    
    26.23
    
    
    
    25.38
    
    
    
    34.78Three months ended
    
    Twelve months endedLight Crude Netbacks ($ per bbl)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Sales price (after commodity risk
management)
    
    
    75.79
    
    
    
    74.40
    
    
    
    65.87
    
    
    
    72.36
    
    
    
    77.78Other production income
    
    
    0.23
    
    
    
    0.43
    
    
    
    (0.02
    )
    
    
    0.32
    
    
    
    0.19Oil & gas sales
    
    
    76.02
    
    
    
    74.83
    
    
    
    65.85
    
    
    
    72.68
    
    
    
    77.97Processing and other income
    
    
    0.46
    
    
    
    0.34
    
    
    
    0.06
    
    
    
    0.71
    
    
    
    0.62Royalties(1)
    
    
    (17.35
    )
    
    
    (15.94
    )
    
    
    (14.02
    )
    
    
    (13.65
    )
    
    
    (16.73
    )Operating expenses(2)
    
    
    (17.36
    )
    
    
    (15.76
    )
    
    
    (21.47
    )
    
    
    (16.28
    )
    
    
    (17.03
    )Transportation costs
    
    
    (0.58
    )
    
    
    (0.78
    )
    
    
    (0.19
    )
    
    
    (0.56
    )
    
    
    (0.38
    )Amortization of injectants
    
    
    (2.19
    )
    
    
    (2.29
    )
    
    
    (2.64
    )
    
    
    (2.40
    )
    
    
    (2.90
    )Operating netback
    
    
    39.00
    
    
    
    40.40
    
    
    
    27.59
    
    
    
    40.50
    
    
    
    41.55Three months ended
    
    Twelve months endedHeavy Oil Netbacks ($ per bbl)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Oil & gas sales
    
    
    62.16
    
    
    
    59.21
    
    
    
    42.20
    
    
    
    52.72
    
    
    
    75.77Processing and other income
    
    
    (0.84
    )
    
    
    1.05
    
    
    
    0.29
    
    
    
    0.53
    
    
    
    0.32Royalties(1) (3)
    
    
    (12.81
    )
    
    
    (6.74
    )
    
    
    (1.95
    )
    
    
    (8.91
    )
    
    
    (10.54
    )Operating expenses(1) (2)
    
    
    (12.31
    )
    
    
    (14.18
    )
    
    
    (18.85
    )
    
    
    (14.35
    )
    
    
    (14.02
    )Operating netback
    
    
    36.20
    
    
    
    39.34
    
    
    
    21.69
    
    
    
    29.99
    
    
    
    51.53Three months ended
    
    Twelve months endedNatural Gas Netbacks ($ per mcf)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Sales price
(after commodity risk management)
    
    
    5.45
    
    
    
    4.34
    
    
    
    7.40
    
    
    
    5.14
    
    
    
    8.19Other production income
    
    
    (0.01
    )
    
    
    (0.03
    )
    
    
    0.27
    
    
    
    
    
    
    
    0.39Oil & gas sales
    
    
    5.44
    
    
    
    4.31
    
    
    
    7.67
    
    
    
    5.14
    
    
    
    8.58Processing and other income
    
    
    0.10
    
    
    
    0.09
    
    
    
    0.09
    
    
    
    0.09
    
    
    
    0.10Royalties(1) (4)
    
    
    (0.58
    )
    
    
    (0.12
    )
    
    
    (1.62
    )
    
    
    (0.31
    )
    
    
    (1.88
    )Operating expenses(2)
    
    
    (1.83
    )
    
    
    (1.87
    )
    
    
    (1.37
    )
    
    
    (1.89
    )
    
    
    (2.02
    )Transportation costs
    
    
    (0.14
    )
    
    
    (0.10
    )
    
    
    (0.10
    )
    
    
    (0.10
    )
    
    
    (0.10
    )Operating netback
    
    
    2.99
    
    
    
    2.31
    
    
    
    4.67
    
    
    
    2.93
    
    
    
    4.68Three months ended
    
    Twelve months endedNGLs Netbacks ($ per bbl)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Oil & gas sales
    
    
    54.52
    
    
    
    41.87
    
    
    
    43.87
    
    
    
    42.12
    
    
    
    70.67Royalties(1)
    
    
    (17.06
    )
    
    
    (10.70
    )
    
    
    (12.27
    )
    
    
    (12.08
    )
    
    
    (25.74
    )Operating expenses(2)
    
    
    (11.34
    )
    
    
    (11.91
    )
    
    
    (11.71
    )
    
    
    (11.99
    )
    
    
    (13.58
    )Operating netback
    
    
    26.12
    
    
    
    19.26
    
    
    
    19.89
    
    
    
    18.05
    
    
    
    31.35
 
 (1)
    
    Royalty expense in 2009 are lower compared to 2008, a result of lower commodity prices and the implementation of The Alberta Royalty Framework on January 1, 2009.(2)
    
    Prior period restated to conform to presentation in the current period.(3)
    
    Heavy oil royalties in the fourth quarter includes an unfavorable crown royalty adjustment at Tangleflags.(4)
    
    Gas royalties in the fourth quarter increased due to volumes at SOEP being back on production which has a higher associated royalty rate.
 Interest Expense
 Three months ended
    
    Twelve months ended($ millions)
    

    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Interest Expense
    
    
    18.3
    
    
    
    19.4
    
    
    
    22.6
    
    
    
    80.3
    
    
    
    76.3
  15




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##### Table of Contents



General and Administrative Expenses
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Cash G&A expense
    
    
    14.7
    
    
    
    11.2
    
    
    
    13.7
    
    
    
    54.1
    
    
    
    48.9$  per boe
    
    
    2.06
    
    
    
    1.56
    
    
    
    1.79
    
    
    
    1.86
    
    
    
    1.63Non-cash G&A expense
    
    
    (0.6
    )
    
    
    2.5
    
    
    
    3.5
    
    
    
    8.1
    
    
    
    10.0$  per boe
    
    
    (0.08
    )
    
    
    0.35
    
    
    
    0.45
    
    
    
    0.28
    
    
    
    0.33Total G&A
    
    
    14.1
    
    
    
    13.7
    
    
    
    17.2
    
    
    
    62.2
    
    
    
    58.9$  per boe
    
    
    1.98
    
    
    
    1.91
    
    
    
    2.24
    
    
    
    2.14
    
    
    
    1.96
    Management Fees
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    Sept 30, 2009
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Management Fee
    
    
    
    
    
    
    
    
    
    
    (2.0
    )
    
    
    2.8
    
    
    
    7.0$  per boe
    
    
    
    
    
    
    
    
    
    
    (0.26
    )
    
    
    0.10
    
    
    
    0.23
   Related Party Transactions
   Other Expenses
   16




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##### Table of Contents



Taxes
  Bill C-52 Budget Implementation Act 2007
    Income Tax Act
  Future Income Taxes
  17




---



##### Table of Contents



Foreign Currency Gains & Losses
  th
  Depletion, Depreciation and Accretion
 Three months ended
    
    Twelve months ended($ millions)
    
    Dec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Depletion and depreciation
    
    
    144.3
    
    
    
    147.2
    
    
    
    157.6
    
    
    
    591.4
    
    
    
    609.3$  per boe
    
    
    20.23
    
    
    
    20.48
    
    
    
    20.55
    
    
    
    20.38
    
    
    
    20.31Accretion
    
    
    7.1
    
    
    
    7.0
    
    
    
    7.3
    
    
    
    27.7
    
    
    
    28.1$  per boe
    
    
    1.00
    
    
    
    0.97
    
    
    
    0.95
    
    
    
    0.95
    
    
    
    0.93
   Ceiling Test
  18




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##### Table of Contents



Asset Retirement Obligations
   Remediation Trust Funds and Remediation and Abandonment Expense
     19




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##### Table of Contents



Climate Change Programs
  Goodwill
   Working Capital
   20




---



##### Table of Contents



Financial Resources and Liquidity
 ($ thousands)
    
    Dec 31,
    
    Dec 31,As at:
    
    2009
    
    2008
    
    ChangeTerm credit facilities
    
    $
    60,000
    
    
    $
    372,000
    
    
    $
    (312,000
    )Senior unsecured notes(1)
    
    
    847,599
    
    
    
    1,152,503
    
    
    
    (304,904
    )Total long term debt
    
    
    907,599
    
    
    
    1,524,503
    
    
    
    (616,904
    )Working capital deficit
    
    
    59,461
    
    
    
    70,159
    
    
    
    (10,698
    )Current portion of long term debt
    
    
    157,546
    
    
    
    
    
    
    
    157,546Working capital deficiency
    
    
    217,007
    
    
    
    70,159
    
    
    
    146,848Total debt excluding convertible debentures
    
    $
    1,124,606
    
    
    $
    1,594,662
    
    
    $
    (470,056
    )Convertible debentures
    
    
    74,828
    
    
    
    74,915
    
    
    
    (87
    )Total debt including convertible debentures
    
    $
    1,199,434
    
    
    $
    1,669,577
    
    
    $
    (470,143
    )
 Dec 31,
    
    Dec 31,Years ended
    
    2009
    
    2008
    
    ChangeNet income
    
    $
    84,853
    
    
    $
    395,850
    
    
    $
    (310,997
    )Add:Interest expense
    
    $
    80,274
    
    
    $
    76,304
    
    
    
    3,970Future tax reduction
    
    $
    (142,945
    )
    
    $
    (71,925
    )
    
    
    (71,020
    )Depletion, depreciation, amortization and accretion
    
    $
    619,032
    
    
    $
    637,377
    
    
    
    (18,345
    )Other non-cash (income) expenses
    
    $
    44,482
    
    
    $
    (26,864
    )
    
    
    71,346EBITDA
    
    $
    685,696
    
    
    $
    1,010,742
    
    
    $
    (325,046
    )Total debt excluding convertible debentures to EBITDA
    
    
    1.6
    
    
    
    1.6
    
    
    
    Total debt including convertible debentures to EBITDA
    
    
    1.7
    
    
    
    1.7
    
    
    
    Total Capitalization excluding convertible debentures(2)
    
    $
    3,860,346
    
    
    $
    4,188,308
    
    
    $
    (327,962
    )Total Capitalization including convertible debentures
    
    $
    3,935,174
    
    
    $
    4,263,223
    
    
    $
    (328,049
    )Total debt excluding convertible debentures as a percentage of total capitalization
    
    
    29.1
    %
    
    
    38.1
    %
    
    
    (9.0
    %)Total debt including convertible debentures as a percentage of total capitalization
    
    
    30.5
    %
    
    
    39.2
    %
    
    
    (8.7
    %)
 (1)
    
    Non-current portion of long term debt.(2)
    
    Total capitalization includes total debt plus Unitholders
Equity. (Total debt excludes working
capital deficit but includes the current portion of long term debt).
  21




---



##### Table of Contents



1.
    
    Total senior debt must not exceed three times EBITDA for the last four fiscal
quarters;2.
    
    Total debt must not exceed 3.5 times EBITDA for the last four fiscal quarters;3.
    
    Total senior debt must be less than 50 percent of total book capitalization;4.
    
    EBITDA must not be less than four times interest expense.
        22




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##### Table of Contents



Financial Instruments
  Cash Flow and Distributions
  ($ thousands, except per trust unit amounts and ratios)
    
    Three months ended
    
    
    Twelve months endedDec 31, 2009
    
    
    Sept 30, 2009
    
    
    Dec 31, 2008
    
    
    Dec 31, 2009
    
    
    Dec 31, 2008Cash flow from operating activities
    
    
    149,933
    
    
    
    162,915
    
    
    
    154,807
    
    
    
    551,350
    
    
    
    912,516Net income
    
    
    50,523
    
    
    
    78,290
    
    
    
    148,688
    
    
    
    84,853
    
    
    
    395,850Distributions declared
    
    
    60,880
    
    
    
    72,235
    
    
    
    144,663
    
    
    
    287,853
    
    
    
    651,015Distributions declared per trust unit
    
    
    0.21
    
    
    
    0.27
    
    
    
    0.57
    
    
    
    1.08
    
    
    
    2.59Excess of cash flow from operating
activities over distributions declared
    
    
    89,053
    
    
    
    90,680
    
    
    
    10,144
    
    
    
    263,497
    
    
    
    261,501Per trust unit
    
    
    0.32
    
    
    
    0.35
    
    
    
    0.04
    
    
    
    1.00
    
    
    
    1.05(Shortfall) Surplus of net income (loss) over
distributions declared
    
    
    (10,357
    )
    
    
    6,055
    
    
    
    4,025
    
    
    
    (203,000
    )
    
    
    (255,165
    )Per trust unit
    
    
    (0.04
    )
    
    
    0.02
    
    
    
    0.02
    
    
    
    (0.77
    )
    
    
    (1.02
    )Ratio of distributions declared
over cash flow from operating activities
    
    
    41
    %
    
    
    44
    %
    
    
    93
    %
    
    
    52
    %
    
    
    71
    %
   23




---



##### Table of Contents



th
 Taxability of Distributions
  th
 24




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##### Table of Contents



Commitments and Contractual Obligations
 ($ thousands)
    
    2010
    
    
    2011
    
    
    2012
    
    
    2013
    
    
    2014
    
    
    thereafter
    
    
    TotalLong term debt (1)
    
    
    157,650
    
    
    
    60,000
    
    
    
    
    
    
    
    52,550
    
    
    
    
    
    
    
    814,404
    
    
    
    1,084,604Interest payments on
long term debt (2)
    
    
    58,080
    
    
    
    55,489
    
    
    
    55,489
    
    
    
    53,573
    
    
    
    52,614
    
    
    
    149,368
    
    
    
    424,613Convertible debentures (3)(4)
    
    
    
    
    
    
    79,599
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    79,599Other (5)
    
    
    12,935
    
    
    
    12,695
    
    
    
    12,489
    
    
    
    12,359
    
    
    
    12,141
    
    
    
    35,383
    
    
    
    98,002228,665
    
    
    
    207,783
    
    
    
    67,978
    
    
    
    118,482
    
    
    
    64,755
    
    
    
    999,155
    
    
    
    1,686,818Purchase obligationsPipeline transportation
    
    
    28,194
    
    
    
    26,298
    
    
    
    22,510
    
    
    
    16,479
    
    
    
    14,936
    
    
    
    12,344
    
    
    
    120,761CO2 purchases (6)
    
    
    3,728
    
    
    
    3,290
    
    
    
    2,972
    
    
    
    2,988
    
    
    
    3,005
    
    
    
    3,885
    
    
    
    19,86831,922
    
    
    
    29,588
    
    
    
    25,482
    
    
    
    19,467
    
    
    
    17,941
    
    
    
    16,229
    
    
    
    140,629Remediation trust
fund payments
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    11,250
    
    
    
    12,500260,837
    
    
    
    237,621
    
    
    
    93,710
    
    
    
    138,199
    
    
    
    82,946
    
    
    
    1,026,634
    
    
    
    1,839,947
 (1)
    
    The debt repayment includes the principal owing at maturity on foreign denominated fixed
rate debt. (see Note 9 of the financial statements)(2)
    
    Interest payments relate to the interest payable on the fixed rate debt. Foreign
denominated debt is translated using the year-end exchange rate.(3)
    
    The convertible debentures were redeemed in January 2010 and repaid with amounts borrowed
under the revolving credit facility. The revolving credit facility is currently scheduled to be
repaid in 2011, assuming it is not renewed (see Note 9 of the financial statements).(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.
 25




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##### Table of Contents



Summary of Trust Unit Trading Data
 ValueHigh
    
    Low
    
    Close
    
    Volume (000s)
    
    ($ millions)TSX  PGF.UN ($ Cdn)2009
    
    1st quarter
    
    
    12.33
    
    
    
    5.84
    
    
    
    7.10
    
    
    
    30,564
    
    
    
    252.62nd quarter
    
    
    9.81
    
    
    
    6.71
    
    
    
    9.18
    
    
    
    26,934
    
    
    
    233.83rd quarter
    
    
    11.33
    
    
    
    7.49
    
    
    
    11.33
    
    
    
    28,766
    
    
    
    269.04th quarter
    
    
    11.39
    
    
    
    9.40
    
    
    
    10.15
    
    
    
    42,483
    
    
    
    439.2Year
    
    
    12.33
    
    
    
    5.84
    
    
    
    10.15
    
    
    
    128,747
    
    
    
    1,194.62008
    
    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
    
    
    
    2,095.7NYSE  PGH ($ U.S.)2009
    
    1st quarter
    
    
    10.11
    
    
    
    4.51
    
    
    
    5.58
    
    
    
    28,538
    
    
    
    195.82nd quarter
    
    
    9.00
    
    
    
    5.30
    
    
    
    7.90
    
    
    
    27,305
    
    
    
    205.83rd quarter
    
    
    10.54
    
    
    
    6.43
    
    
    
    10.51
    
    
    
    23,914
    
    
    
    203.14th quarter
    
    
    10.52
    
    
    
    8.81
    
    
    
    9.63
    
    
    
    29,823
    
    
    
    290.7Year
    
    
    10.54
    
    
    
    4.51
    
    
    
    9.63
    
    
    
    109,580
    
    
    
    895.42008
    
    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
    
    
    
    1,509.1
 26




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Summary of Quarterly Results
  2009
    
    Q1
    
    Q2
    
    Q3
    
    Q4Oil and gas sales ($ thousands)
    
    
    322,973
    
    
    
    335,634
    
    
    
    325,264
    
    
    
    359,296Net income/(loss) ($ thousands)
    
    
    (54,232
    )
    
    
    10,272
    
    
    
    78,290
    
    
    
    50,523Net income/(loss) per trust unit ($)
    
    
    (0.21
    )
    
    
    0.04
    
    
    
    0.30
    
    
    
    0.18Net income/(loss) per trust unit  diluted ($)
    
    
    (0.21
    )
    
    
    0.04
    
    
    
    0.30
    
    
    
    0.18Cash flow from operating activities ($ thousands)
    
    
    94,386
    
    
    
    144,116
    
    
    
    162,915
    
    
    
    149,933Distributions declared ($ thousands)
    
    
    77,212
    
    
    
    77,526
    
    
    
    72,235
    
    
    
    60,880Distributions declared per trust unit ($)
    
    
    0.30
    
    
    
    0.30
    
    
    
    0.27
    
    
    
    0.21Daily production (boe)
    
    
    80,284
    
    
    
    82,171
    
    
    
    78,135
    
    
    
    77,529Total production (mboe)
    
    
    7,226
    
    
    
    7,478
    
    
    
    7,188
    
    
    
    7,133Average realized price ($  per boe)
    
    
    44.57
    
    
    
    44.74
    
    
    
    45.22
    
    
    
    50.35Operating netback ($  per boe)
    
    
    23.87
    
    
    
    26.28
    
    
    
    24.72
    
    
    
    26.63
 2008
    
    Q1
    
    Q2
    
    Q3
    
    Q4Oil and gas sales ($ thousands)
    
    
    457,606
    
    
    
    550,623
    
    
    
    518,662
    
    
    
    392,158Net income/(loss) ($ thousands)
    
    
    (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 ($ thousands)
    
    
    216,238
    
    
    
    267,874
    
    
    
    273,597
    
    
    
    154,807Distributions declared ($ thousands)
    
    
    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)
    
    
    33.62
    
    
    
    42.15
    
    
    
    37.48
    
    
    
    26.23
  Selected Annual Information
  Twelve months ended December 31($ thousands)
    
    2009
    
    
2008
    

    
    2007Oil and gas sales
    
    
    1,343,167
    
    
    
    1,919,049
    
    
    
    1,722,038Net income
    
    
    84,853
    
    
    
    395,850
    
    
    
    359,652Net income per trust unit ($)
    
    
    0.32
    
    
    
    1.58
    
    
    
    1.47Net income per trust unit  diluted ($)
    
    
    0.32
    
    
    
    1.58
    
    
    
    1.46Distributions declared per trust unit ($)
    
    
    1.08
    
    
    
    2.59
    
    
    
    2.88Total assets
    
    
    4,693,604
    
    
    
    5,317,341
    
    
    
    5,234,251Long term debt(1)
    
    
    982,427
    
    
    
    1,599,418
    
    
    
    1,278,266Trust unitholders equity
    
    
    2,795,201
    
    
    
    2,663,805
    
    
    
    2,756,220Number of trust units outstanding at year end (thousands)
    
    
    289,835
    
    
    
    256,076
    
    
    
    246,846
 (1)
    
    Includes long term debt and convertible debentures.
  27




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Business Risks
  
 
 
 
 
 
 
 
 
 
 
 
 28




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##### Table of Contents




 
 
 
 
 
 
 
 
 
 
 
 
 
  Subsequent Events
  29




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##### Table of Contents



Outlook
        Current Global Economic Conditions
   International Financial Reporting Standards (IFRS)
  30




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IFRS Project Plan
  
    
    Diagnostic  This phase involves performing a high-level review of the major
differences between Canadian GAAP and IFRS and to identify information technology and
business processes that may be impacted by the transition to IFRS.Status  The diagnostic analysis was completed in mid-2008.
    
    Design and planning  The results of the diagnostic were ranked according to
complexity, time to complete and potential impact on the financial position and results of
operations. A detailed plan was developed in order to address the issues identified and
ranked in the diagnostic phase. The planning is updated and progress is reported to the
Audit Committee on a regular basis.Status  Pengrowth completed the initial design and planning in mid-2009. The
planning is updated and progress is reported to the Audit Committee of the board of
Directors on a regular basis.
    
    Solution development  In this phase, items identified in the diagnostic phase
are addressed according to the priority assigned. This phase involves detailed analysis
of the applicable IFRS standard in relation to current practice and development of
alternative policy choices. In addition, certain potential differences are further
investigated to assess whether there may be broader impact to Pengrowths debt agreements,
compensation arrangements or management reporting systems. The conclusion of the solution
development phase will require the Audit Committee of the Board of Directors to review and
approve significant accounting policy choices as recommended by the IFRS Steering Committee.Status  Solution development began in late 2008 for classification of exploration
and evaluation expenditures, depletion, cash generating units and impairment of capital
assets, share based payments, business combinations, financial instruments, trust
unit-holders equity and initial adoption of IFRS. Pengrowth is currently engaged in the
analysis and interpretation of provisions (including ARO), income taxes and risk sharing
arrangements (farm-outs, asset swaps, etc).
    
    Implementation  Involves implementing all of the changes approved in the
solution development phase and may include changes to accounting policies, information
systems, business processes, modification to agreements and training of staff impacted by
the conversion.Status  Implementation for information technology changes began in 2009. Training
for the IFRS Steering Committee members commenced in 2008. Internal education of the Audit
Committee and key financial and accounting personnel began in the fourth quarter of 2009.
Detailed implementation meetings involving internal personnel directly affected by IFRS
also began in the fourth quarter of 2009. Continued training and implementation meetings
are expected throughout 2010.
  First-Time Adoption of IFRS
  31




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##### Table of Contents




    
    Business Combinations  IFRS 1 would allow Pengrowth to adopt the IFRS policies
for business combinations on a prospective basis rather than retrospectively restating all
prior business combinations. The IFRS policies for business combinations are converged
with the new CICA Handbook section 1582 that are effective for Pengrowth on January 1,
2011; however, early adoption under Canadian GAAP is permitted.
    
    Property, Plant and Equipment (PP&E)  IFRS 1 provides the option to value
 PP&E  at  deemed cost rather that retrospective restatement upon the
adoption of IFRS. Currently, Pengrowth accumulates all oil and gas assets into one cost
center. Under IFRS, Pengrowths oil and gas assets must be divided into smaller cost
centers. Pengrowth may choose to allocate the net book value of the full cost oil and
gas assets as the deemed cost of the new cost centers on the basis of Pengrowth`s reserve
volumes or reserve values at the adoption date. Alternatively,
Pengrowth could elect to record PP&E at fair value  on
the date of transition. Under either
alternative, historical cost accounting would continue under IFRS.
 IFRS differences
  
    
    Reclassification of Exploration and Evaluations (E&E) expenditures  Upon
transition to IFRS, Pengrowth will reclassify  E&E expenditures that are currently
included in the PP&E balance on the Consolidated Balance Sheet. This will be comprised of
the book value of Pengrowths unproven properties that are currently excluded from
Depletion (see note 6 to the audited annual financial statements). E&E assets will not be
depleted but must be assessed for impairment when there are indicators for possible
impairment, such as allowing the mineral rights lease to expire or a decision to no longer
pursue exploration and evaluation of a specific E&E asset.
    
    Impairment of PP&E assets  Impairment of PP&E is currently assessed at a
consolidated level. Under IFRS, impairment of PP&E must be assessed at a more detailed
level. Impairment calculations will be performed at the Cash Generating Unit level, using
the greater of fair value less costs to sell or the value in use. This may result in more
frequent impairments of assets under IFRS.
    
    Calculation of Depletion Expense  Pengrowth currently calculates depletion of
oil and gas assets on a consolidated basis based on total production and total proved reserves.
Under IFRS, depletion will be calculated at a more detailed level and
at least at the level of cash generating unit. In addition, under IFRS Pengrowth may use
either total proven reserves or total proven plus probable reserves for the depletion
calculation. The significance of the change in depletion is not known and is primarily
dependant on the possible changes to the reserve base used in the calculation of
depletion.
    
    Trust Unit-Holders Equity  It is uncertain if Pengrowths trust units would
qualify for classification as equity under IFRS due to specific features of the trust
indenture, including the redemption provisions. If
unable to qualify for classification as equity, Pengrowth trust units would be classified
as liabilities on the balance sheet.
    
    Provisions In January 2010, the International Accounting Standards Board
(IASB) released a re-exposure draft for certain aspects of the standards for provisions.
A final new standard for ARO and other provisions is expected to be released in the
second half of 2010. Under current IFRS standards, the net present value of the Asset
Retirement Obligations (ARO) as reported balance sheet may be calculated differently
despite the estimated future expenditures being unchanged. It is unclear if the discount
rate used would be based on a credit adjusted rate, as it currently is, or based on a risk
free rate. A change in the discount rate would materially change the amount recorded on
the balance sheet. In addition, if Pengrowth allocated Canadian GAAP net book value to
the IFRS cost centers, any revision to ARO would be recorded directly in equity.
    
    Income Tax  In November 2009 the IASB withdrew an exposure draft on Income
Taxes. Current IFRS income tax requirements are fundamentally consistent with current
practice. Any changes to Income Tax reporting are expected to be
predominantly caused by changes in the
book value of assets and changes in tax rates applied, not due to the change in
 32




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Income Tax accounting methodology. Revisions to Income Tax accounting standards are expected to be
re-exposed by the IASB in the second half of 2010.
  
    
    Internal controls over financial reporting  As the review of Pengrowths
accounting policies is completed, an assessment will be made to determine changes required
for internal controls over financial reporting. For example, additional controls will be
implemented for the IFRS 1 changes and preparation of comparative information. This will
be an ongoing process in 2010 to ensure that  changes in accounting policies include
the appropriate additional controls and procedures for future IFRS reporting requirements.
    
    Disclosure controls and procedures  Throughout the transition process,
Pengrowth will be assessing stakeholders information requirements and will ensure that
adequate and timely information is provided so that  stakeholders are kept apprised.
    
    IT Systems  Pengrowth has completed most of the system modifications required
for IFRS reporting. Pengrowths IT systems did not require significant modifications in
order to track PP&E and E&E at a more detailed level for financial reporting. We are also
currently implementing solutions to allow Pengrowth to account for certain transactions
and prepare Canadian GAAP and IFRS financial statements in 2010. Additional systems
modifications may be required.
  Recent Accounting Pronouncements
    Disclosure Controls and Procedures
  33




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Internal Control Over Financial Reporting
     34




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APPENDIX C




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##### Table of Contents



(signed)
Derek W. Evans
    
    (signed) Christopher G.
WebsterPresident and Chief Executive Officer
    
    Chief Financial Officer
  38




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KPMG LLP
 39




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##### Table of Contents



KPMG LLP
 
 40




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##### Table of Contents



PENGROWTH ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
(Stated in thousands of dollars)
 As at
    
    
    As atDecember 31
    
    
    December 312009
    
    
    2008ASSETSCURRENT ASSETSAccounts receivable
    
    $
    182,342
    
    
    $
    197,131Due from Pengrowth Management Limited
    
    
    
    
    
    
    623Fair value of risk management contracts (Note 20)
    
    
    14,001
    
    
    
    122,841Future income taxes (Note 11)
    
    
    969
    
    
    
    197,312
    
    
    
    320,595FAIR VALUE OF RISK MANAGEMENT CONTRACTS (Note 20)
    
    
    
    
    
    
    41,851OTHER ASSETS (Note 5)
    
    
    46,027
    
    
    
    42,618PROPERTY, PLANT AND EQUIPMENT (Note 6)
    
    
    3,789,369
    
    
    
    4,251,381GOODWILL
    
    
    660,896
    
    
    
    660,896TOTAL ASSETS
    
    $
    4,693,604
    
    
    $
    5,317,341LIABILITIES AND UNITHOLDERS EQUITYCURRENT LIABILITIESBank indebtedness
    
    $
    11,563
    
    
    $
    2,631Accounts payable and accrued liabilities
    
    
    185,337
    
    
    
    260,828Distributions payable to unitholders
    
    
    40,590
    
    
    
    87,142Fair value of risk management contracts (Note 20)
    
    
    17,555
    
    
    
    2,706Future income taxes (Note 11)
    
    
    
    
    
    
    34,964Contract liabilities (Note 7)
    
    
    1,728
    
    
    
    2,483Current portion of long-term debt (Note 9)
    
    
    157,546
    
    
    
    414,319
    
    
    
    390,754FAIR VALUE OF RISK MANAGEMENT CONTRACTS (Note 20)
    
    
    23,269
    
    
    
    16,021CONTRACT LIABILITIES (Note 7)
    
    
    7,952
    
    
    
    9,680CONVERTIBLE DEBENTURES (Note 8)
    
    
    74,828
    
    
    
    74,915LONG TERM DEBT (Note 9)
    
    
    907,599
    
    
    
    1,524,503ASSET RETIREMENT OBLIGATIONS (Note 10)
    
    
    288,796
    
    
    
    344,345FUTURE INCOME TAXES (Note 11)
    
    
    181,640
    
    
    
    293,318TRUST UNITHOLDERS EQUITYTrust unitholders capital (Note 12)
    
    
    4,920,945
    
    
    
    4,588,587Equity portion of convertible debentures (Note 8)
    
    
    160
    
    
    
    160Contributed surplus (Note 12)
    
    
    18,617
    
    
    
    16,579Deficit (Note 14)
    
    
    (2,144,521
    )
    
    
    (1,941,521
    )2,795,201
    
    
    
    2,663,805COMMITMENTS (Note 21)CONTINGENCIES (Note 22)SUBSEQUENT EVENTS (Note 23)TOTAL LIABILITIES AND UNITHOLDERS EQUITY
    
    $
    4,693,604
    
    
    $
    5,317,341
  (signed)
Thomas A. Cumming
    
    (signed) Wayne K. FooDirector
    
    Director
 41




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##### Table of Contents



PENGROWTH ENERGY TRUST
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
(Stated in thousands of dollars, except per trust unit amounts)
 Year endedDecember 312009
    
    
    2008REVENUESOil and gas sales
    
    $
    1,343,167
    
    
    $
    1,919,049Unrealized (loss) gain on commodity risk management (Note 20)
    
    
    (173,726
    )
    
    
    249,899Processing and other income
    
    
    15,540
    
    
    
    15,525Royalties, net of incentives
    
    
    (207,563
    )
    
    
    (433,970
    )NET REVENUE
    
    
    977,418
    
    
    
    1,750,503EXPENSESOperating
    
    
    381,194
    
    
    
    418,497Transportation
    
    
    13,467
    
    
    
    12,519Amortization of injectants for miscible floods
    
    
    19,989
    
    
    
    25,876Interest on long term debt
    
    
    80,274
    
    
    
    76,304General and administrative
    
    
    62,195
    
    
    
    58,937Management fee (Note 17)
    
    
    2,793
    
    
    
    6,950Foreign exchange (gain) loss (Note 15)
    
    
    (149,722
    )
    
    
    189,172Depletion, depreciation and amortization
    
    
    591,355
    
    
    
    609,326Accretion (Note 10)
    
    
    27,677
    
    
    
    28,051Other expenses (income)
    
    
    6,288
    
    
    
    9461,035,510
    
    
    
    1,426,578(LOSS) INCOME BEFORE TAXES
    
    
    (58,092
    )
    
    
    323,925Future income tax reduction (Note 11)
    
    
    (142,945
    )
    
    
    (71,925
    )NET INCOME AND COMPREHENSIVE INCOME
    
    $
    84,853
    
    
    $
    395,850Deficit, beginning of year
    
    
    (1,941,521
    )
    
    
    (1,686,356
    )Distributions declared
    
    
    (287,853
    )
    
    
    (651,015
    )DEFICIT, END OF YEAR
    
    $
    (2,144,521
    )
    
    $
    (1,941,521
    )NET INCOME PER TRUST UNIT (Note 18)Basic
    
    $
    0.32
    
    
    $
    1.58Diluted
    
    $
    0.32
    
    
    $
    1.58
  42




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PENGROWTH ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOW
(Stated in thousands of dollars)
 Year endedDecember 312009
    
    
    2008CASH PROVIDED BY (USED FOR):OPERATINGNet income and comprehensive income
    
    $
    84,853
    
    
    $
    395,850Depletion, depreciation and accretion
    
    
    619,032
    
    
    
    637,377Future income tax reduction (Note 11)
    
    
    (142,945
    )
    
    
    (71,925
    )Contract liability amortization
    
    
    (2,483
    )
    
    
    (4,664
    )Amortization of injectants
    
    
    19,989
    
    
    
    25,876Purchase of injectants
    
    
    (13,298
    )
    
    
    (21,009
    )Expenditures on remediation (Note 10)
    
    
    (18,042
    )
    
    
    (32,691
    )Unrealized foreign exchange (gain) loss (Note 15)
    
    
    (149,233
    )
    
    
    197,159Unrealized loss (gain) on commodity risk management (Note 20)
    
    
    173,726
    
    
    
    (249,899
    )Trust unit based compensation (Note 13)
    
    
    8,125
    
    
    
    9,998Other items
    
    
    4,248
    
    
    
    (1,104
    )Changes in non-cash operating working capital (Note 16)
    
    
    (32,622
    )
    
    
    27,548551,350
    
    
    
    912,516FINANCINGDistributions paid (Note 14)
    
    
    (334,405
    )
    
    
    (674,993
    )Bank indebtedness
    
    
    8,932
    
    
    
    2,631Repayment of Accrete bank debt
    
    
    
    
    
    
    (16,289
    )Change in long term debt, net
    
    
    (312,000
    )
    
    
    148,064Proceeds from issue of trust units
    
    
    321,605
    
    
    
    63,499(315,868
    )
    
    
    (477,088
    )INVESTINGBusiness acquisition
    
    
    
    
    
    
    (1,128
    )Expenditures on property, plant and equipment
    
    
    (207,451
    )
    
    
    (401,928
    )Other property acquisitions
    
    
    (35,655
    )
    
    
    (35,938
    )Proceeds on property dispositions
    
    
    41,885
    
    
    
    17,361Other investments
    
    
    852
    
    
    
    (5,000
    )Change in remediation trust funds
    
    
    (7,656
    )
    
    
    (9,013
    )Change in non-cash investing working capital (Note 16)
    
    
    (27,457
    )
    
    
    (1,799
    )(235,482
    )
    
    
    (437,445
    )CHANGE IN CASH AND TERM DEPOSITS
    
    
    
    
    
    
    (2,017
    )CASH AND TERM DEPOSITS AT BEGINNING OF YEAR
    
    
    
    
    
    
    2,017CASH AND TERM DEPOSITS AT END OF YEAR
    
    $
    
    
    
    $
    
  43




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PENGROWTH ENERGY TRUST
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2009 AND 2008  (Tabular amounts are stated in thousands of dollars except per trust unit amounts and as otherwise stated)
 1. STRUCTURE OF THE TRUST
      2. SIGNIFICANT ACCOUNTING POLICIES
 Basis of Presentation
   44




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Joint Interest Operations
  Property, Plant and Equipment
      Goodwill
  Injectant Costs
  45




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##### Table of Contents



Asset Retirement Obligations
   Income Taxes
  Trust Unit Compensation Plans
   Financial Instruments
    46




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##### Table of Contents



Foreign Currency
  Equity Investment
  Measurement Uncertainty
   Net Income per Trust Unit
  Revenue Recognition
  Cash and Term Deposits
  Comparative Figures
 47




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##### Table of Contents



3. CHANGE IN ACCOUNTING POLICIES
    4. ACQUISITIONS
 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
  48




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##### Table of Contents



5. OTHER ASSETS
 2009
    
    
    2008Remediation trust funds
    
    $
    34,837
    
    
    $
    27,122Equity investment in Monterey Exploration Ltd.
    
    
    5,039
    
    
    
    9,872Other investments
    
    
    6,151
    
    
    
    5,624$
    46,027
    
    
    $
    42,618
 Remediation Trust Funds
    Remediation Trust Funds
    
    2009
    
    
    2008Opening balance
    
    $
    27,122
    
    
    $
    18,094Contributions to Judy Creek Remediation Trust Fund
    
    
    635
    
    
    
    816Contributions to SOEP Environmental Restoration Fund
    
    
    7,579
    
    
    
    8,485Remediation funded by Judy Creek Remediation Trust Fund
    
    
    (558
    )
    
    
    (288
    )Change in remediation trust funds
    
    
    7,656
    
    
    
    9,013Unrealized gain on held for trading investment (1)
    
    
    59
    
    
    
    15Closing balance
    
    $
    34,837
    
    
    $
    27,122
 (1)
    
    SOEP remediation trust fund has been designated as held for trading
 Equity Investment in Monterey Exploration Ltd. (Monterey)
  49




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##### Table of Contents



Other Investments
  6. PROPERTY, PLANT AND EQUIPMENT
 2009
    
    
    2008Property, plant and equipment, at cost
    
    $
    7,272,408
    
    
    $
    7,136,374Accumulated depletion, depreciation and amortization
    
    
    (3,498,764
    )
    
    
    (2,907,409
    )Net book value of property, plant and equipment
    
    
    3,773,644
    
    
    
    4,228,965Net book value of deferred injectant costs
    
    
    15,725
    
    
    
    22,416Net book value of property, plant and equipment and deferred injectants
    
    $
    3,789,369
    
    
    $
    4,251,381
    Foreign
    
    
    Edmonton LightWTI Oil
    
    
    Exchange Rate
    
    
    Crude Oil
    
    
        AECO GasYear
    
    (U.S.$/bbl)
    
    
    (U.S.$/Cdn$)
    
    
    (Cdn$/bbl)
    
    
    (Cdn$/mmbtu)2010
    
    $
    80.00
    
    
    
    0.950
    
    
    $
    83.26
    
    
    $
    5.962011
    
    $
    83.00
    
    
    
    0.950
    
    
    $
    86.42
    
    
    $
    6.792012
    
    $
    86.00
    
    
    
    0.950
    
    
    $
    89.58
    
    
    $
    6.892013
    
    $
    89.00
    
    
    
    0.950
    
    
    $
    92.74
    
    
    $
    6.952014
    
    $
    92.00
    
    
    
    0.950
    
    
    $
    95.90
    
    
    $
    7.052015
    
    $
    93.84
    
    
    
    0.950
    
    
    $
    97.84
    
    
    $
    7.162016
    
    $
    95.72
    
    
    
    0.950
    
    
    $
    99.81
    
    
    $
    7.422017
    
    $
    97.64
    
    
    
    0.950
    
    
    $
    101.83
    
    
    $
    7.952018
    
    $
    99.59
    
    
    
    0.950
    
    
    $
    103.88
    
    
    $
    8.522019
    
    $
    101.58
    
    
    
    0.950
    
    
    $
    105.98
    
    
    $
    8.69Thereafter
    
    + 2.0 percent/yr
    
    
    
    0.950
    
    
    + 2.0 percent/yr
        

    + 2.0 percent/yr
 7. CONTRACT LIABILITIES
  50




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##### Table of Contents



2009
    
    
    2008Fixed price commodity contract
    
    $
    
    
    
    $
    956Firm transportation contracts
    
    
    9,680
    
    
    
    11,207Total contract liabilities
    
    
    9,680
    
    
    
    12,163Less current portion
    
    
    (1,728
    )
    
    
    (2,483
    )Non-current portion
    
    $
    7,952
    
    
    $
    9,680
  8. CONVERTIBLE DEBENTURES
    9. LONG TERM DEBT
 2009
    
    
    2008U.S. dollar denominated senior unsecured notes:150 million at 4.93 percent due April 2010
    
    $
    157,546
    
    
    $
    182,18050 million at 5.47 percent due April 2013
    
    
    52,417
    
    
    
    60,727400 million at 6.35 percent due July 2017
    
    
    418,530
    
    
    
    485,080265 million at 6.98 percent due August 2018
    
    
    277,138
    
    
    
    321,231$
    905,631
    
    
    $
    1,049,218U.K. Pound Sterling denominated 50 million unsecured
notes at 5.46 percent due December 2015
    
    
    84,514
    
    
    
    88,285Canadian dollar 15 million senior unsecured
notes at 6.61 percent due August 2018
    
    
    15,000
    
    
    
    15,000Canadian dollar revolving credit facility borrowings
    
    
    60,000
    
    
    
    372,000Total long term debt
    
    $
    1,065,145
    
    
    $
    1,524,503Current portion of long term debt due April 2010
    
    
    (157,546
    )
    
    
    Non-current portion of long term debt
    
    $
    907,599
    
    
    $
    1,524,503
 Credit Facilities
    51




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##### Table of Contents



Term Notes
         10. ASSET RETIREMENT OBLIGATIONS
   52




---



##### Table of Contents



2009
    
    
    2008ARO, beginning of year
    
    $
    344,345
    
    
    $
    352,171Increase (decrease) in liabilities during the year related to:Acquisitions
    
    
    365
    
    
    
    3,414Dispositions
    
    
    (2,195
    )
    
    
    (5,663
    )Additions
    
    
    3,146
    
    
    
    3,618Revisions (1)
    
    
    (66,500
    )
    
    
    (4,555
    )Accretion expense
    
    
    27,677
    
    
    
    28,051Liabilities settled in the year
    
    
    (18,042
    )
    
    
    (32,691
    )ARO, end of year
    
    $
    288,796
    
    
    $
    344,345
   Expenditures on ARO
    
    2009
    
    
    2008Expenditures on ARO not covered by the trust funds
    
    $
    17,484
    
    
    $
    32,403Expenditures on ARO covered by the trust funds (Note 5)
    
    
    558
    
    
    
    288$
    18,042
    
    
    $
    32,691
 11. INCOME TAXES
   2009
    
    
    2008(Loss) income before taxes
    
    $
    (58,092
    )
    
    $
    323,925Combined federal and provincial tax rate
    
    
    29.50
    %
    
    
    29.50
    %Expected income tax (reduction) expense
    
    
    (17,137
    )
    
    
    95,558Net income of the Trust (1)
    
    
    (98,851
    )
    
    
    (200,998
    )Foreign exchange (gain) loss (2)
    
    
    (21,956
    )
    
    
    24,783Effect of change in corporate tax rate
    
    
    5,968
    
    
    
    430Other including stock based compensation (3)
    
    
    (4,799
    )
    
    
    1,859Change in valuation allowance
    
    
    (6,170
    )
    
    
    6,443Future income tax reduction
    
    $
    (142,945
    )
    
    $
    (71,925
    )
 
 
 
   53




---



##### Table of Contents



2009
    
    
    2008Future income tax assets:Asset retirement obligation
    
    $
    68,890
    
    
    $
    84,090Non-capital losses
    
    
    135,263
    
    
    
    117,987Unrealized commodity loss
    
    
    7,312
    
    
    
    Capital losses
    
    
    273
    
    
    
    Foreign exchange loss
    
    
    
    
    
    
    6,443Contract liabilities
    
    
    2,551
    
    
    
    3,292214,289
    
    
    
    211,812Less: Valuation allowance
    
    
    (273
    )
    
    
    (6,443
    )214,016
    
    
    
    205,369Future income tax liabilities:Property, plant and equipment and other assets
    
    
    (382,285
    )(1)
    
    
    (491,170
    )Unrealized commodity gain
    
    
    
    
    
    
    (42,481
    )Foreign exchange gain
    
    
    (12,402
    )
    
    
    Net future tax liability
    
    $
    (180,671
    )
    
    $
    (328,282
    )
 
  12. TRUST UNITS
   2009

    
    
    2008Number of
    
    
    
    
    
    
    Number ofTrust Units Issued
    
    Trust Units
    
    
    Amount
    
    
    Trust Units
    
    
    AmountBalance, beginning of year
    
    
    256,075,997
    
    
    $
    4,588,587
    
    
    
    246,846,420
    
    
    $
    4,432,737Issued on redemption of Deferred Entitlement Units
(DEUs) (non-cash)
    
    
    416,043
    
    
    
    5,741
    
    
    
    238,633
    
    
    
    2,484Issued for cash on exercise of trust unit options and
rights
    
    
    299,684
    
    
    
    1,918
    
    
    
    290,363
    
    
    
    4,274Issued for cash under Distribution Reinvestment Plan
(DRIP)
    
    
    3,026,166
    
    
    
    26,319
    
    
    
    3,727,256
    
    
    
    59,423Issued for the Accrete business combination
    
    
    
    
    
    
    
    
    
    
    4,973,325
    
    
    
    89,253Issued for cash under At The Market (ATM) Plan
    
    
    1,169,900
    
    
    
    10,723
    
    
    
    
    
    
    
    Issued for cash on equity issue
    
    
    28,847,000
    
    
    
    300,009
    
    
    
    
    
    
    
    Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    346
    
    
    
    
    
    
    
    614Issue costs net of tax
    
    
    
    
    
    
    (12,698
    )
    
    
    
    
    
    
    (198
    )Balance, end of year
    
    
    289,834,790
    
    
    $
    4,920,945
    
    
    
    256,075,997
    
    
    $
    4,588,587
  Redemption Rights
  54




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##### Table of Contents



Distribution Reinvestment Plan
  At The Market Distribution
  Contributed Surplus
 2009
    
    
    2008Balance, beginning of year
    
    $
    16,579
    
    
    $
    9,679Trust unit rights incentive plan (non-cash expensed)
    
    
    2,953
    
    
    
    2,348Deferred entitlement trust units (non-cash expensed)
    
    
    5,172
    
    
    
    7,650Trust unit rights incentive plan (non-cash exercised)
    
    
    (346
    )
    
    
    (614
    )Deferred entitlement trust units (non-cash exercised)
    
    
    (5,741
    )
    
    
    (2,484
    )Balance, end of year
    
    $
    18,617
    
    
    $
    16,579
 13. TRUST UNIT BASED COMPENSATION PLANS
  Long Term Incentive Program
   55




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##### Table of Contents



2009
    
    
    2008Number
    
    
    Weighted
    
    
    Number
    
    
    WeightedDEUs
    
    of DEUs
    
    
    average price
    
    
    of DEUs
    
    
    average priceOutstanding, beginning of year
    
    
    1,270,750
    
    
    $
    19.38
    
    
    
    868,042
    
    
    $
    20.13Granted
    
    
    1,174,601
    
    
    $
    6.55
    
    
    
    578,833
    
    
    $
    17.88Forfeited
    
    
    (120,637
    )
    
    $
    12.63
    
    
    
    (158,532
    )
    
    $
    19.54Exercised
    
    
    (297,184
    )
    
    $
    20.57
    
    
    
    (202,020
    )
    
    $
    18.51Deemed DRIP (1)
    
    
    263,939
    
    
    $
    14.05
    
    
    
    184,427
    
    
    $
    19.70Outstanding, end of year
    
    
    2,291,469
    
    
    $
    12.38
    
    
    
    1,270,750
    
    
    $
    19.38
 (1)
    
    Weighted average deemed DRIP price is based on the average of the original grant
prices.
 Trust Unit Rights Incentive Plan
   2009
    
    
    2008Number
    
    
    Weighted
    
    
    Number
    
    
    WeightedTrust Unit Rights
    
    of rights
    
    
    average price
    
    
    of rights
    
    
    average priceOutstanding, beginning of year
    
    
    3,292,622
    
    
    $
    16.78
    
    
    
    2,250,056
    
    
    $
    17.39Granted (1)
    
    
    2,958,378
    
    
    $
    6.63
    
    
    
    1,703,892
    
    
    $
    17.96Forfeited
    
    
    (495,718
    )
    
    $
    12.25
    
    
    
    (397,469
    )
    
    $
    17.49Exercised
    
    
    (299,684
    )
    
    $
    6.40
    
    
    
    (263,857
    )
    
    $
    14.55Outstanding, end of year
    
    
    5,455,598
    
    
    $
    12.23
    
    
    
    3,292,622
    
    
    $
    16.78Exercisable, end of year
    
    
    3,087,494
    
    
    $
    14.95
    
    
    
    1,950,375
    
    
    $
    16.52
 (1)
    
    Weighted average exercise price of rights granted are based on the exercise
price at the date of grant.
  56




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##### Table of Contents



Rights Outstanding
    
    
    
    
    
    
    Rights ExercisableWeighted averageremaining
    
    
    Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    contractual life
    
    
    average
    
    
    Number
    
    
    averageRange of exercise prices
    
    outstanding
    
    
    (years)
    
    
    exercise price
    
    
    exercisable
    
    
    exercise price$6.00 to $8.99
    
    
    2,122,141
    
    
    
    4.2
    
    
    $
    6.12
    
    
    
    522,804
    
    
    $
    6.13$9.00 to $12.99
    
    
    620,943
    
    
    
    3.3
    
    
    $
    10.32
    
    
    
    321,898
    
    
    $
    11.15$13.00 to $18.99
    
    
    2,341,899
    
    
    
    2.8
    
    
    $
    17.13
    
    
    
    1,881,380
    
    
    $
    17.19$19.00 to $22.99
    
    
    370,615
    
    
    
    1.3
    
    
    $
    19.41
    
    
    
    361,412
    
    
    $
    19.41$6.00 to $22.99
    
    
    5,455,598
    
    
    
    3.3
    
    
    $
    12.23
    
    
    
    3,087,494
    
    
    $
    14.95
   Trust Unit Option Plan
  Employee Savings Plans
  Trust Unit Margin Purchase Plan
   14. DEFICIT
 57




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##### Table of Contents



2009
    
    
    2008Accumulated earnings
    
    $
    2,156,041
    
    
    $
    2,071,188Accumulated distributions declared
    
    
    (4,300,562
    )
    
    
    (4,012,709
    )$
    (2,144,521
    )
    
    $
    (1,941,521
    )
  Distributions Paid
  15. FOREIGN EXCHANGE (GAIN) LOSS
 2009
    
    
    2008Unrealized foreign exchange (gain) loss on
translation of U.S. dollar denominated debt
    
    $
    (144,455
    )
    
    $
    181,856Unrealized foreign exchange gain on translation
of U.K. pound sterling denominated debt
    
    
    (3,840
    )
    
    
    (9,230
    )(148,295
    )
    
    
    172,626Unrealized (gain) loss on foreign exchange risk
management contracts
    
    
    (938
    )
    
    
    24,533(149,233
    )
    
    
    197,159Realized foreign exchange gain
    
    
    (489
    )
    
    
    (7,987
    )$
    (149,722
    )
    
    $
    189,172
 16. OTHER CASH FLOW DISCLOSURES
 Change in Non-Cash Operating Working Capital
 Cash provided by (used for):
    
    2009
    
    
    2008Accounts receivable
    
    $
    15,284
    
    
    $
    9,452Accounts payable and accrued liabilities
    
    
    (48,529
    )
    
    
    23,536Due from Pengrowth Management Limited
    
    
    623
    
    
    
    108Net working capital on acquisition
    
    
    
    
    
    
    (5,548
    )$
    (32,622
    )
    
    $
    27,548
 Change in Non-Cash Investing Working Capital
 Cash provided by (used for):
    
    2009
    
    
    2008Accounts receivable
    
    $
    (495
    )
    
    $
    Accounts payable and capital accruals
    
    
    (26,962
    )
    
    
    (1,799
    )$
    (27,457
    )
    
    $
    (1,799
    )
 Cash Interest Payments
 58




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##### Table of Contents



2009
    
    
    2008Interest on long-term debt
    
    $
    85,566
    
    
    $
    66,267
 17. RELATED PARTY TRANSACTIONS
   18. AMOUNTS PER TRUST UNIT
  2009
    
    
    2008Weighted
average number of trust units  basic
    
    
    264,121,262
    
    
    
    250,182,464Dilutive effect of trust unit options, trust unit rights and DEUs
    
    
    1,779,172
    
    
    
    333,531Weighted
average number of trust units  diluted
    
    
    265,900,434
    
    
    
    250,515,995
  19. CAPITAL DISCLOSURES
     59




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As at:
    
    December 31, 2009
    
    
    December 31, 2008Term credit facilities
    
    $
    60,000
    
    
    $
    372,000Senior unsecured notes(1)
    
    
    847,599
    
    
    
    1,152,503Working capital deficiency
    
    
    217,007
    
    
    
    70,159Convertible debentures
    
    
    74,828
    
    
    
    74,915Total debt including convertible debentures
    
    $
    1,199,434
    
    
    $
    1,669,577
 (1)
    
    Non-current portion of long term debt
 20. FINANCIAL INSTRUMENTS
   RISK MANAGEMENT OVERVIEW
   MARKET RISK
  60




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Commodity Price Risk
   Crude Oil:Remaining term
    
    Volume (bbl/d)
    
    
    Reference Point
    
    
    Price per bblFinancial:Jan 1, 2010 - Dec 31, 2010
    
    
    12,500
    
    
    WTI (1)
    
    $82.09 CdnJan 1, 2011 - Dec 31, 2011
    
    
    500
    
    
    WTI (1)
    
    $82.44 Cdn
 (1)
    
    Associated Cdn $/U.S. $ foreign exchange rate has been fixed
 Natural Gas:Remaining term
    
    Volume (mmbtu/d)
    
    
    Reference Point
    
    
    Price per mmbtuFinancial:Jan 1, 2010 - Dec 31, 2010
    
    
    97,151
    
    
    AECO
    
    $6.10 CdnJan 1, 2010 - Dec 31, 2010
    
    
    5,000
    
    
    Chicago MI (1)
    
    $6.78 CdnJan 1, 2011 - Dec 31, 2011
    
    
    33,174
    
    
    AECO
    
    $5.77 CdnJan 1, 2011 - Dec 31, 2011
    
    
    5,000
    
    
    Chicago MI (1)
    
    $6.78 Cdn
 (1)
    
    Associated Cdn $/U.S. $ foreign exchange rate has been fixed
 Power:Remaining term
    
    Volume (mwh)
    
    
    Reference Point
    
    
    Price per mwhFinancial:Jan 1, 2010 - Dec 31, 2010
    
    
    20
    
    
    AESO
    
    $47.66 Cdn
   Commodity Risk Management Contracts
    
    2009
    
    
    2008Current portion of unrealized risk management assets
    
    $
    14,001
    
    
    $
    122,841Non-current portion of unrealized risk management assets
    
    
    
    
    
    
    41,851Current portion of unrealized risk management liabilities
    
    
    (16,661
    )
    
    
    Non-current portion of unrealized risk management liabilities
    
    
    (6,374
    )
    
    
    Total unrealized risk management (liabilities) assets at year end
    
    $
    (9,034
    )
    
    $
    164,692
 2009
    
    
    2008Total unrealized risk management (liabilities) assets at year end
    
    $
    (9,034
    )
    
    $
    164,692Less: Unrealized risk management assets (liabilities) at beginning of year
    
    
    164,692
    
    
    
    (85,207
    )Unrealized (loss) gain on risk management contracts for the year
    
    $
    (173,726
    )
    
    $
    249,899
 Commodity Price Sensitivity
 61




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Foreign Exchange Risk
  
  Foreign Exchange Risk Management Contracts
    
    2009
    
    
    2008Current portion of unrealized risk management liabilities
    
    $
    (894
    )
    
    $
    (2,706
    )Non-current portion of unrealized risk management liabilities
    
    
    (16,895
    )
    
    
    (16,021
    )Total unrealized risk management liabilities at year end
    
    $
    (17,789
    )
    
    $
    (18,727
    )
 2009
    
    
    2008Total unrealized risk management liabilities at year end
    
    $
    (17,789
    )
    
    $
    (18,727
    )Less: Unrealized risk management (liabilities) assets at beginning of year
    
    
    (18,727
    )
    
    
    5,806Unrealized gain (loss) on risk management contracts for the year
    
    $
    938
    
    
    $
    (24,533
    )
 Foreign Exchange Rate Sensitivity
  Cdn $0.01 Exchange Rate ChangeForeign Exchange Sensitivity as at December 31, 2009
    
    Cdn - U.S.
    
    Cdn - U.K.Unrealized foreign exchange gain or loss on foreign denominated debt
    
    $
    8,650
    
    
    $
    500Unrealized foreign exchange risk management gain or loss
    
    
    
    
    
    
    572
 62




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##### Table of Contents



Cdn $0.01 Exchange Rate ChangeForeign Exchange Sensitivity as at December 31, 2008
    
    Cdn - U.S.
    
    Cdn - U.K.Unrealized foreign exchange gain or loss on foreign denominated debt
    
    $
    8,650
    
    
    $
    500Unrealized foreign exchange risk management gain or loss
    
    
    
    
    
    
    577
 Interest Rate Risk
  Interest Rate Sensitivity
  Equity Price Risk
  FAIR VALUE
   Fair Value Measurements Using:Quoted Prices in
    
    Significant Other
    
    SignificantActive Markets
    
    Observable Inputs
    
    UnobservableAs at December 31, 2009
    
    Carrying Amount
    
    Fair Value
    
    (Level 1)
    
    (Level 2)
    
    Inputs (Level 3)Financial AssetsRemediation trust funds
    
    $
    34,837
    
    
    $
    34,821
    
    
    $
    34,821
    
    
    $
    
    
    
    $
    Fair value of risk management contracts
    
    
    14,001
    
    
    
    14,001
    
    
    
    
    
    
    
    14,001
    
    
    
    Other Assets  investment in public company
    
    
    1,151
    
    
    
    1,151
    
    
    
    1,151
    
    
    
    
    
    
    
    Financial LiabilitiesU.S. dollar denominated senior unsecured notes
    
    
    905,631
    
    
    
    963,136
    
    
    
    
    
    
    
    963,136
    
    
    
    Cdn dollar senior unsecured notes
    
    
    15,000
    
    
    
    15,164
    
    
    
    
    
    
    
    15,164
    
    
    
    U.K. Pound Sterling denominated unsecured notes
    
    
    84,514
    
    
    
    89,724
    
    
    
    
    
    
    
    89,724
    
    
    
    Convertible debentures
    
    
    74,828
    
    
    
    76,423
    
    
    
    76,423
    
    
    
    
    
    
    
    Fair value of risk management contracts
    
    
    40,824
    
    
    
    40,824
    
    
    
    
    
    
    
    40,824
    
    
    
    Fair Value Measurements Using:Quoted Prices in
    
    Significant Other
    
    SignificantActive Markets
    
    Observable Inputs
    
    UnobservableAs at December 31, 2008
    
    Carrying Amount
    
    Fair Value
    
    (Level 1)
    
    (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 public company
    
    
    624
    
    
    
    624
    
    
    
    624
    
    
    
    
    
    
    
    Financial LiabilitiesU.S. dollar denominated senior unsecured notes
    
    
    1,049,218
    
    
    
    1,213,723
    
    
    
    
    
    
    
    1,213,723
    
    
    
    Cdn dollar senior unsecured notes
    
    
    15,000
    
    
    
    16,075
    
    
    
    
    
    
    
    16,075
    
    
    
    U.K. Pound Sterling denominated unsecured notes
    
    
    88,285
    
    
    
    95,495
    
    
    
    
    
    
    
    95,495
    
    
    
    Convertible debentures
    
    
    74,915
    
    
    
    68,014
    
    
    
    68,014
    
    
    
    
    
    
    
    Fair value of risk management contracts
    
    
    18,727
    
    
    
    18,727
    
    
    
    
    
    
    
    18,727
    
    
    
    
 Level 1 Fair Value Measurements
  63




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Level 2 Fair Value Measurements
   CREDIT RISK
  .
  LIQUIDITY RISK
   64




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Carrying
    
    
    Contractual
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    More than 5As at December 31, 2009
    
    Amount
    
    
    Cash Flows
    
    
    Within 1 year
    
    
    1-2 years
    
    
    2-5 years
    
    
    yearsCdn dollar revolving credit facility(1)
    
    $
    60,000
    
    
    $
    60,892
    
    
    $
    613
    
    
    $
    60,279
    
    
    $
    
    
    
    $
    Cdn dollar senior unsecured notes(1)
    
    
    15,000
    
    
    
    23,571
    
    
    
    992
    
    
    
    992
    
    
    
    2,977
    
    
    
    18,610U.S. dollar
denominated senior unsecured
notes(1)
    
    
    748,085
    
    
    
    1,131,180
    
    
    
    49,009
    
    
    
    49,009
    
    
    
    194,858
    
    
    
    838,304U.K. Pound Sterling denominated unsecured notes(1)
    
    
    84,514
    
    
    
    112,384
    
    
    
    4,637
    
    
    
    4,637
    
    
    
    13,923
    
    
    
    89,187Convertible debentures(1) (2)
    
    
    74,828
    
    
    
    79,599
    
    
    
    
    
    
    
    79,599
    
    
    
    
    
    
    
    Remediation trust fund payments
    
    
    
    
    
    
    12,500
    
    
    
    250
    
    
    
    250
    
    
    
    750
    
    
    
    11,250Commodity risk management contracts
    
    
    6,374
    
    
    
    6,517
    
    
    
    
    
    
    
    6,517
    
    
    
    
    
    
    
    Foreign exchange risk management contracts
    
    
    16,895
    
    
    
    180
    
    
    
    30
    
    
    
    30
    
    
    
    90
    
    
    
    30
 (1)
    
    Contractual cash flows include future interest payments calculated at period end exchange
rates and interest rates(2)
    
    Convertible debentures were redeemed on January 14, 2010 using proceeds from the revolving credit facility
(Note 23). The repayment of the convertible debentures has been shown in the above table as due in 1-2 years
with the revolving credit facility.
 Carrying
    
    
    Contractual
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    More than 5As at December 31, 2008
    
    Amount
    
    
    Cash Flows
    
    
    Within 1 year
    
    
    1-2 years
    
    
    2-5 years
    
    
    yearsCdn dollar revolving credit facility(1)
    
    $
    372,000
    
    
    $
    393,919
    
    
    $
    8,630
    
    
    $
    8,630
    
    
    $
    376,659
    
    
    $
    Cdn dollar senior unsecured notes(1)
    
    
    15,000
    
    
    
    24,556
    
    
    
    992
    
    
    
    992
    
    
    
    2,975
    
    
    
    19,597U.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
    
    
    
    98,051Convertible 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
    
    
    18,727
    
    
    
    210
    
    
    
    30
    
    
    
    30
    
    
    
    90
    
    
    
    60
 (1)
    
    Contractual cash flows include future interest payments calculated at period end exchange
rates and interest rates
 21. COMMITMENTS
 2010
    
    
    2011
    
    
    2012
    
    
    2013
    
    
    2014
    
    
    Thereafter
    
    
    TotalOperating leases
    
    $
    12,935
    
    
    $
    12,695
    
    
    $
    12,489
    
    
    $
    12,359
    
    
    $
    12,141
    
    
    $
    35,383
    
    
    $
    98,002
  22. CONTINGENCIES
  23. SUBSEQUENT EVENTS
    65




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24.
    
    RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING
PRINCIPLESThe significant differences between Canadian generally accepted accounting principles
(Canadian GAAP) which, in most respects, conforms to United States generally accepted
accounting principles (U.S. GAAP), as they apply to Pengrowth, are as follows:
 (a)
    
    As required quarterly  under U.S. GAAP, the carrying value of petroleum and natural gas
properties and related facilities, net of future  income taxes, is limited to
the present value of after tax future net revenue from proven reserves, discounted at ten
percent (based on the average of the prices on the first day of each
month  for the year ended December 31,
2009, and prior to December 31, 2009 based on commodity prices in effect on the date of
the impairment test), plus the lower of cost and fair value of unproven properties. At
December 31, 2009, the application of the full cost ceiling test under U.S. GAAP did not
result in a write-down of capitalized costs. At December 31, 2008, the application of the
full cost ceiling test under U.S. GAAP resulted in a before-tax write-down of capitalized
costs of $1,529.9 million (total write-downs prior to
December 31, 2008  $492.6 million).Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount
of the write-down under U.S. GAAP, the charge for depletion will differ in subsequent
years. In addition, under U.S. GAAP depletion is calculated based on constant dollar
reserves as opposed to escalated dollar reserves required under Canadian GAAP. As such,
the depletion rate under U.S. GAAP differs from Canadian GAAP. The effect of ceiling
test impairments and a different depletion rate under U.S. GAAP has reduced the 2009
depletion charge by $189.4 million (2008  $24.7 million). Depletion on a per unit of
production under U.S. GAAP was $13.53 per BOE (2008  $20.21).(b)
    
    Other comprehensive income under U.S. GAAP differs from that presented under Canadian
GAAP as a result of designating a cash flow hedge at different dates under U.S. GAAP as
compared to Canadian GAAP. Effective January 1, 2007, Pengrowth ceased to designate its
foreign exchange swaps as a cash flow hedge of the U.K. term debt. The amount deferred in
accumulated other comprehensive income pertaining to this hedging relationship when the
hedge was de-designated of $2.4 million is being amortized to income over the life of the
foreign exchange swap under U.S. GAAP.(c)
    
    Under U.S. GAAP, securities which are subject to mandatory redemption requirements
or whose redemption is outside the control of the issuer must be classified outside of
permanent equity and are to be recorded at their redemption amount at each balance sheet
date with changes in redemption amount being charged to the deficit. The amount charged
to the deficit representing the change in the redemption amount between balance sheet
dates for the periods presented must also be disclosed. Furthermore, the balance sheet
disclosure of trust unitholders capital would not be permitted and trust unitholders
capital would be reclassified to mezzanine equity, a liability.The trust units are redeemable at the option of the holder at a redemption price equal to
the lesser of 95% of the average closing price of the trust units for the 10 trading days
after the trust units have been surrendered for redemption and the closing price on the
date the trust units have been surrendered for redemption. However, the total amount
payable by the Trust in cash in any one calendar month is limited to a maximum of
$25,000. Redemptions in excess of the cash limit must be satisfied by way of a
distribution in specie of a pro rata share of royalty units and other
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assets, excluding facilities, pipelines or other assets associated with oil and gas
production, which are held by the Trust at the time the trust units are to be redeemed.
As a result of the significant limitation on the cash amount payable by the Trust in
respect of redemptions, and that any royalty units issued would have similar
characteristics of the trust units and be convertible back into trust units, the trust
units have not been classified as redeemable equity for the purposes of U.S. GAAP.(d)
    
    Under U.S. GAAP, an entity that is subject to income tax in multiple jurisdictions is
required to disclose income tax expense in each jurisdiction. Pengrowth is subject to tax
at the federal and provincial level. The portion of the income tax reduction  at the
federal level for the year ended December 31, 2009 is $42.0 million (2008  $319.5
million). The portion of income tax reduction  at the provincial level is $23.4
million (2008  $173.8 million).(e)
    
    Additional disclosures required under U.S. GAAP with respect to Pengrowths equity
incentive plans is provided below.The intrinsic value of the DEUs, trust unit rights and trust unit options
exercised was as follows:
 2009
    
    2008Number
    
    Intrinsic
    
    Number
    
    IntrinsicExercised
    
    Value
    
    Exercised
    
    ValueDEUs
    
    
    297,184
    
    
    $
    3,121
    
    
    
    202,020
    
    
    $
    4,511Trust Unit Rights
    
    
    299,684
    
    
    
    867
    
    
    
    263,857
    
    
    
    1,271Trust Unit Options
    
    
    
    
    
    
    
    
    
    
    26,506
    
    
    
    64Total
    
    
    596,868
    
    
    $
    3,988
    
    
    
    492,383
    
    
    $
    5,846
 The following table summarizes information about trust unit options, trust unit rights
and DEUs vested and expected to vest:
 Trust UnitAt December 31, 2009
    
    Rights
    
    
    DEUsNumber vested and expected to vest
    
    
    5,218,787
    
    
    
    1,570,348Weighted average exercise price per unit (1)
    
    $
    12.39
    
    
    $
    Aggregate intrinsic value (2)
    
    $
    8,238
    
    
    $
    15,939Weighted average remaining life (years)
    
    
    3.3
    
    
    
    1.4
 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
    
    
    
    3.2
    
    
    
    1.4
 
 (1)
    
    No proceeds are received upon exercise of DEUs.(2)
    
    Based on December 31 closing trust unit price. The following table summarizes information about trust unit options and trust
unit rights outstanding:
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Trust UnitAt December 31, 2009
    
    Rights
    
    
    DEUsNumber exercisable
    
    
    3,087,494
    
    
    
    Weighted average exercise price per unit (2)
    
    $
    14.95
    
    
    $
    Aggregate intrinsic value (3)
    
    $
    2,217
    
    
    $
    Weighted average remaining life (years)
    
    
    2.7
    
    
    
    
 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
    
    
    
    2.7
    
    
    
    
 
 (1)
    
    DEUs exercisable at December 31, 2008 were granted to employees on
long-term leave on the vesting date. DEUs will be exercised upon return from
long-term leave or termination from the plan. No DEUs were exercisable at December
31, 2009.(2)
    
    No proceeds are received upon exercise of DEUs.(3)
    
    Based on December 31 closing price. (f)
    
    Under Canadian GAAP, the convertible debentures are classified as debt with a
portion, representing the estimated fair value of the conversion feature at the date of
issue, being allocated to equity. In addition, under Canadian GAAP a non-cash interest
expense or income representing the effective yield of the debt component is recorded in
the consolidated statements of income with a corresponding credit or debit to the
convertible debenture liability balance to accrete the balance to the principal due on
maturity as a result of the portion allocated to equity.Under U.S. GAAP, the convertible debentures, in their entirety, are classified as debt.
The non-cash interest expense recorded under Canadian GAAP related to the equity portion
of the debenture would not be recorded under U.S. GAAP.(g)
    
    The following table summarizes the unrecognized tax benefits under U.S. GAAP:
 2009
    
    
    2008Balance, January 1
    
    $
    21,239
    
    
    $
    17,810Additions (decreases) based on tax positions in the year
    
    
    (1,260
    )
    
    
    3,859Decrease due to change in tax rates
    
    
    (691
    )
    
    
    (430
    )Balance, December 31
    
    $
    19,288
    
    
    $
    21,239
 The following table summarizes open taxation years at December 31, 2009 by
jurisdiction:
 Jurisdiction
    
    YearsFederal
    
    2004 - 2008Alberta,
British Columbia, Saskatchewan, and Nova Scotia
    
    2004 - 2008
 The 2004 tax examination by federal authorities is currently in progress.Interest and penalties related to uncertain tax positions, which are included in income
tax expense, were not material for the years ended December 31, 2009 and
2008.Unrecognized tax benefits are classified as current or long-term liabilities under U.S.
GAAP as opposed to future income tax liabilities. It is anticipated that no amount
of the current or prior year unrecognized tax benefit will be realized
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in the next year. The unrecognized tax
benefit, if recognized, would have a favourable impact on Pengrowths effective income
tax rate in future periods.(h)
    
    Fair Value MeasurementsThe framework for measuring fair value when an entity is required to use a fair
value measure for recognition or disclosure purposes under U.S. GAAP is consistent
with the framework under Canadian GAAP, except that Canadian GAAP only requires
disclosure of the fair value hierarchy for items  normally measured at fair value. In
addition, under Canadian GAAP the framework only applies to financial assets and
liabilities measured at fair value as at December 31, 2009 while under U.S. GAAP the
framework applies to all financial assets and liabilities and non-financial assets
and liabilities measured at fair value or for which fair value is disclosed for
December 31, 2009 and only for financial assets and liabilities as of December 31,
2008. Pengrowths disclosure under Canadian GAAP includes assets and liabilities
measured at fair value and for which fair value is disclosed, consistent with U.S.
GAAP. Please see Note 20 to the audited annual financial statements for fair value
disclosures as of December 31, 2009 and 2008.(i)
    
    Under U.S. GAAP, unrealized gains or losses on commodity risk management would be
included with oil and gas sales.(j)
    
    Effective January 1, 2009, Pengrowth adopted new disclosure standards under U.S.
GAAP with respect to derivatives and hedging. These new disclosure standards are similar
to Canadian GAAP (see note 20). The following are additional disclosures required
under U.S. GAAP with respect to Pengrowths derivatives.Pengrowth has not designated any outstanding risk management contracts as hedges for
accounting purposes and therefore records these contracts on the balance sheet at
their fair value and recognizes changes in fair value on the statement of income
(loss) as unrealized commodity risk management contracts. The effect on cash flows
will be recognized separately only upon realization of the contracts, which could
vary significantly from the unrealized amount recorded due to timing and prices when
each contract is settled. The use of commodity contracts involves a degree of credit
risk that Pengrowth manages through its credit policies which are designed to limit
eligible counterparties to those with investment grade credit ratings or better. The
total of all risk management assets is $38.2 million (2008  $164.8 million). The
total of all risk management liabilities is $65.0 million (2008  $18.8 million).
Under Canadian and U.S. GAAP, the risk management assets and risk management
liabilities are netted by individual counterparty, thus the maximum amount of
potential loss due to credit risk is the carrying amount of the risk management
assets recorded on the balance sheet. There are no contingent features of these
contracts related to Pengrowths credit risk.(k)
    
    Other accounting policy changes under U.S. GAAP:
 (i)
    
    In June 2009, the Financial Accounting Standards Board (FASB) developed
the Accounting Standards Codification (codification) that consolidates all
authoritative accounting guidance into a single source that uses a simple, consistent
structure for organizing accounting topics. The codification does not change U.S.
GAAP but reorganizes it into a consistent structure for ease of research and
cross-reference. All other non-grandfathered non-SEC accounting
literature not included in the codification will become
non-authoritative. The codification became effective on September 15, 2009 and
implementation had no effect on Pengrowths financial position, results of operations
or cash flow.
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(ii)
    
    Effective January 1, 2009, Pengrowth adopted new U.S. GAAP standards with
respect to business combinations which require an acquirer to be identified for all
business combinations and applies the same method of accounting for business
combinations (the acquisition method) to all transactions. In addition,
transaction costs associated with acquisitions are required to be expensed. The
revised statement is effective to business combinations in years beginning on or
after December 31, 2008. There were no business combinations that occurred during
2009 therefore adoption of these standards did not create any Canadian to U.S. GAAP
differences.(iii)
    
    On December 31, 2009, Pengrowth adopted new rules and regulations issued by the SEC
with respect to reserves and reporting of reserves. The new rules impacted the
calculation of the U.S. GAAP ceiling test. Effective December 31, 2009, the ceiling
test is based on the proven reserves discounted at ten percent using the average of the
commodity prices on the first day of each month in the year rather than the year end
commodity prices.
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Consolidated Statements of Income
 The application of U.S. GAAP would have the following effect on net income as reported:(Stated in thousands of Canadian Dollars, except per trust unit amounts)
 Year ended
    
    Year endedDecember 31, 2009
    
    December 31, 2008Net income for the year, as reported
    
    $
    84,853
    
    
    $
    395,850Adjustments:Depletion and depreciation (a)
    
    
    189,371
    
    
    
    24,735Ceiling test write-down (a)
    
    
    
    
    
    
    (1,529,935
    )Amortization of discontinued hedge (b)
    
    
    272
    
    
    
    272Non-cash interest on convertible debentures (f)
    
    
    40
    
    
    
    40Future tax adjustments
    
    
    (77,553
    )
    
    
    421,369Net income (loss)  U.S. GAAP
    
    $
    196,983
    
    
    $
    (687,669
    )Other comprehensive income (loss):Amortization of discontinued hedge (b)
    
    
    (272
    )
    
    
    (272
    )Comprehensive income (loss)  U.S. GAAP
    
    $
    196,711
    
    
    $
    (687,941
    )Net Income (Loss) per trust unit  U.S. GAAPBasic
    
    $
    0.74
    
    
    $
    (2.75
    )Diluted
    
    $
    0.74
    
    
    $
    (2.75
    )
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Consolidated Balance Sheets
 The application of U.S. GAAP would have the following effect on the balance sheets as
reported:(Stated in thousands of Canadian Dollars)
 IncreaseAs at December 31, 2009
    
    As Reported
    
    (Decrease)
    
    U. S. GAAPAssetsProperty, plant and equipment (a)
    
    $
    3,789,369
    
    
    $
    (1,562,502
    )
    
    $
    2,226,867Future income taxes (d)(g)
    
    
    
    
    
    
    251,473
    
    
    
    251,473$
    (1,311,029
    )LiabilitiesConvertible debentures
    
    $
    74,828
    
    
    $
    40
    
    
    $
    74,868Future income taxes (d)(g)
    
    
    180,671
    
    
    
    (180,671
    )
    
    
    Other long term liabilities (g)
    
    
    
    
    
    
    19,288
    
    
    
    19,288Unitholders equity:Accumulated other comprehensive income
    
    $
    
    
    
    $
    1,630
    
    
    $
    1,630Trust unitholders equity (c)
    
    
    2,795,201
    
    
    
    (1,151,316
    )
    
    
    1,643,885$
    (1,311,029
    )
 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)
    
    
    
    
    
    
    183,366
    
    
    
    183,366$
    (1,568,507
    )LiabilitiesConvertible debentures
    
    $
    74,915
    
    
    $
    80
    
    
    $
    74,995Future income taxes (d)
    
    
    328,282
    
    
    
    (328,282
    )
    
    
    Other long term liabilities (d)
    
    
    
    
    
    
    21,239
    
    
    
    21,239Unitholders equity:Accumulated other comprehensive income
    
    $
    
    
    
    $
    1,902
    
    
    $
    1,902Trust unitholders equity (c)
    
    
    2,663,805
    
    
    
    (1,263,446
    )
    
    
    1,400,359$
    (1,568,507
    )
 72




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Additional disclosures required under U.S. GAAP
 The components of accounts receivable are as follows:
 As at
    
    As atDecember 31, 2009
    
    December 31, 2008Trade
    
    $
    159,309
    
    
    $
    159,274Prepaid
    
    
    23,033
    
    
    
    37,857$
    182,342
    
    
    $
    197,131
  As at
    
    As atDecember 31, 2009
    
    December 31, 2008Accounts payable
    
    $
    50,998
    
    
    $
    94,799Accrued liabilities
    
    
    134,339
    
    
    
    166,029$
    185,337
    
    
    $
    260,828
 73




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APPENDIX D
 SUPPLEMENTAL
UNAUDITED DISCLOSURES ABOUT OIL
AND GAS PRODUCING ACTIVITIES REQUIRED UNDER UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES




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




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##### Table of Contents



COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
  2009
    
    
    2008Property acquisition costsProved
    
    $
    24,653
    
    
    $
    182,401Unproved
    
    
    11,002
    
    
    
    Exploration costs
    
    
    13,915
    
    
    
    22,012Development costs
    
    
    123,104
    
    
    
    365,304Injectants costs
    
    
    13,298
    
    
    
    21,009$
    185,972
    
    
    $
    590,726




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CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
  2009
    
    
    2008Oil and gas properties
    
    $
    7,211,347
    
    
    $
    7,079,703Less accumulated depletion, depreciation and amortization
    
    
    (5,027,476
    )
    
    
    (4,635,531
    )Net capitalized costs
    
    $
    2,183,871
    
    
    $
    2,444,172Unproved oil and gas properties
    
    $
    420,354
    
    
    $
    484,426Proven oil and gas properties
    
    
    1,763,517
    
    
    
    1,959,746Net capitalized costs
    
    $
    2,183,871
    
    
    $
    2,444,172




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##### Table of Contents



OIL AND GAS RESERVE INFORMATION
  Net
Proved Developed and Undeveloped Reserves After Royalties
 Crude Oil
    
    
    Naturaland NGLs
    
    
    GasMMbbls
    
    
    BcfEnd 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
    
    
    
    
    
    
    (1.0
    )Discoveries and extensions
    
    
    1.3
    
    
    
    12.3Production
    
    
    (12.3
    )
    
    
    (71.5
    )End of year 2008
    
    
    106.7
    
    
    
    524.9Revisions of previous estimates (including infill drilling & improved recovery)
    
    
    0.4
    
    
    
    (36.6
    )Purchase of reserves in place
    
    
    0.8
    
    
    
    1.1Sale of reserves in place
    
    
    (0.5
    )
    
    
    (7.8
    )Discoveries and extensions
    
    
    1.3
    
    
    
    6.7Production
    
    
    (11.2
    )
    
    
    (72.9
    )End of year 2009
    
    
    97.5
    
    
    
    415.4Net Proved Developed Reserves After RoyaltyEnd of year 2007
    
    
    93.0
    
    
    
    474.9End of year 2008
    
    
    87.9
    
    
    
    474.4End of year 2009
    
    
    81.7
    
    
    
    394.0
 
 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 the
average of the commodity prices on the first day of each month for the year ended December 31,
2009. Prior to December 31, 2009 reserves are based on the commodity prices in effect on the
last day of the year.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.




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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
  2009
    
    
    2008Future cash inflows
    
    $
    8,561
    
    
    $
    8,843Future costsFuture production and development costs
    
    
    (5,164
    )
    
    
    (5,409
    )Future income taxes
    
    
    (623
    )
    
    
    (635
    )Future net cash flows
    
    
    2,774
    
    
    
    2,799Deduct: 10% annual discount factor
    
    
    (1,039
    )
    
    
    (1,012
    )Standardized measure of discounted future net cash flows
    
    $
    1,735
    
    
    $
    1,787




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CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS
RESERVES
  2009
    
    
    2008$MM
    
    
    $MMFuture discounted net cash flow at beginning of year
    
    
    1,787
    
    
    
    3,690Sales & transfer, net of production costs
    
    
    (737
    )
    
    
    (1,044
    )Net change in sales & transfer prices
    
    
    233
    
    
    
    (2,406
    )Development costs incurred during the period
    
    
    199
    
    
    
    362Change in future development costs
    
    
    (79
    )
    
    
    (371
    )Change due to extensions and discoveries
    
    
    30
    
    
    
    33Change due to revisions (including infill drilling & improved recovery)
    
    
    (36
    )
    
    
    111Accretion of discount
    
    
    207
    
    
    
    459Sales of reserves in place
    
    
    (19
    )
    
    
    (4
    )Purchase of reserves in place
    
    
    12
    
    
    
    56Net change in income taxes
    
    
    (18
    )
    
    
    616Changes in timing of future net cash flow and other
    
    
    156
    
    
    
    285Future discounted net cash flow at end of year
    
    
    1,735
    
    
    
    1,787
 
 Note:1.
    
    The schedules above are calculated using year-end costs, statutory tax rates and proved oil
and gas reserves and the average of the commodity prices on the first day of each month for
the year ended December 31, 2009. Prior to December 31, 2009 the schedules are based on the
commodity prices in effect on the last day of the year. 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.




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APPENDIX
E
 PENGROWTH ENERGY TRUST CODE OF BUSINESS CONDUCT AND ETHICS
DATED NOVEMBER 11, 2009




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November 11, 2009




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##### Table of Contents



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




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##### Table of Contents



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




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Compliance with the Law
      Page 2




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Health, Safety and the Environment
     
 Public Reporting
  Page 3




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




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Private Business
   
 Payments
    Page 5




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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




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Directorships
  
 Government Relations
  
 Confidential Information
   
 Company Information
    Page 7




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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




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




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




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Acknowledgement
   personal
 
 Exceptions and Changes
    Page 11




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Appendix A
 Complaint
Procedures
For Accounting, Financial Reporting and Auditing Matters and
Violations of the Code of Business Conduct and Ethics
    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




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
    
    fraud or deliberate error in the preparation, evaluation, review or audit of any financial
statement of Pengrowth;
    
    fraud or deliberate error in the recording and maintaining of financial records of Pengrowth;
    
    deficiencies in or non-compliance with Pengrowths internal accounting controls;
    
    misrepresentation or false statement to or by a director, officer, employee or external accountant
regarding a matter contained in the financial records, financial reports or audit reports of
Pengrowth; or
    
    deviation from full and fair reporting of Pengrowths financial condition.
 Treatment of Complaints
 
    
    Grant Thornton LLP shall inform (i) the chairman of the Audit Committee of all complaints and
concerns provided to it in respect of Accounting Matters; and (ii) the chairman of the Corporate
Governance Committee of all complaints provided to it in respect of Conduct Matters.
    
    Upon receipt of a complaint or concern, the chairman of the Audit Committee or chairman of the
Corporate Governance Committee, as the case may be, will (i) determine whether or not the complaint
actually pertains to 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




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




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Appendix B
Awareness Statement on Code of Business Conduct and Ethics
 To be completed by all directors, officers, employees, consultants and contractors
of Pengrowth Energy Trust and its subsidiaries (Pengrowth)
  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