##### 



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, 2007       Commission File Number: 1-31253
 PENGROWTH ENERGY TRUST
  Alberta, Canada
 1311
    
    None(Primary Standard Industrial 
Classification Code Number)
    
    (I.R.S. Employer
Identification Number)
 Suite 2100, 222 Third Avenue S.W.
Calgary, Alberta Canada T2P 0B4
(403) 233-0224
 CT Corporation System
111-8 th Avenue, New York, New York 10011
(212) 894-8940
 
  Brad D. Markel 
Bennett Jones LLP 
4500 Bankers Hall East 
855 
2ndStreet SW 
Calgary, Alberta T2P 4K7 Canada
(403) 298-3100
    
    Edwin S. Maynard
Paul, Weiss, Rifkind, Wharton & Garrison
LLP
1285 Avenue of the Americas
New York, New York 10019-6064 USA
(212) 373-3000
 Securities registered or to be registered pursuant to Section 12(b) of the Act.
 Title of each class
    
    Name of each exchange on which registeredTrust Units
    
    New York Stock Exchange
 Securities registered or to be registered pursuant to Section 12(g) of the Act.
 None
 (Title of Class)
 Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
 None
 (Title of Class)
  þ þ
    o þ
  þ o




---



##### 



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




---



##### 



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




---



##### 



SIGNATURES
  Date: March 19, 2008
    PENGROWTH ENERGY TRUST
by its Administrator
PENGROWTH CORPORATIONBy:
    /s/ James S. KinnearJames S. KinnearChairman, President and
Chief Executive Officer




---



##### 



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




---



##### 



PENGROWTH ENERGY TRUST
 ANNUAL INFORMATION FORM
For the year ended December 31, 2007
 March
19, 2008




---



##### 



TABLE OF CONTENTS
 GLOSSARY OF TERMS AND ABBREVIATIONS
    
    
    1Corporate
    
    
    1Engineering
    
    
    2Abbreviations
    
    
    3CONVERSION
    
    
    4PRESENTATION OF OUR FINANCIAL INFORMATION
    
    
    5PRESENTATION OF OUR RESERVE INFORMATION
    
    
    5FORWARD-LOOKING STATEMENTS
    
    
    5PENGROWTH ENERGY TRUST
    
    
    7Introduction
    
    
    7The Trust
    
    
    7The Corporation
    
    
    7The Trusts Subsidiaries
    
    
    7The Corporations Subsidiaries
    
    
    8The Manager
    
    
    8Intercorporate Relationships
    
    
    8Business Strategy and Strengths
    
    
    9SIFT Legislation Considerations
    
    
    11GENERAL DEVELOPMENT OF PENGROWTH ENERGY TRUST
    
    
    12Recent Developments
    
    
    12Historical Developments
    
    
    16Trends
    
    
    19PENGROWTH MANAGEMENT LIMITED
    
    
    20Business
    
    
    20Management Agreement
    
    
    20Bonus Pool
    
    
    21Management Agreement Second Term
    
    
    22PENGROWTH  OPERATIONAL INFORMATION
    
    
    23Principle Properties
    
    
    23Light Oil Properties
    
    
    24Heavy Oil Properties
    
    
    27Conventional Gas Properties
    
    
    28Shallow Gas Properties
    
    
    31Offshore Gas Properties
    
    
    33Statement of Oil and Gas Reserves and Reserves Data
    
    
    35Additional Information Relating to Reserves Data
    
    
    45Future Development Costs
    
    
    47Finding, Development and Acquisition Costs
    
    
    47Future Development Capital
    
    
    48Other Oil and Gas Information
    
    
    49Additional Information Concerning Abandonment & Reclamation Costs
    
    
    50Costs Incurred
    
    
    51Exploration and Development Activities
    
    
    51Production Estimates
    
    
    51Production History (Netback)
    
    
    52Replacement of Properties
    
    
    52TRUST UNITS
    
    
    53The Trust Indenture
    
    
    53The Trustee
    
    
    54Stock Exchange Listings
    
    
    54Ownership Restrictions
    
    
    54Redemption Right
    
    
    54




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



Risk Factors Business
Risks
  - 6 -




---



##### 



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




---



##### 



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




---



##### 



Business Strategy and Strengths
 2
  - 9 -




---



##### 



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




---



##### 



Income Tax Considerations Risk Factors  SIFT Legislation is expected to materially and
adversely affect the Trust, the Unitholders and the value of the Trust Units
  SIFT Legislation Considerations
     - 11 -




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



U.S. DRIP
  Changes to Tax Legislation Affecting Pengrowth and its Unitholders and Debentureholders
 Certain Canadian Federal
Income Tax Considerations Risk Factors  The SIFT Legislation is expected to materially and
adversely affect the Trust, the Unitholders and the value of the Trust Units
  Greenhouse Gas Emissions
  Borrowing
  - 15 -




---



##### 



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




---



##### 



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




---



##### 



- 18 -




---



##### 



Trends
    Managements Discussion and Analysis  Outlook
 - 19 -




---



##### 



PENGROWTH MANAGEMENT LIMITED
 Business
  Management Agreement
   
    
    two distinct three-year terms with a declining fee structure in the second three year term;
    
    a base fee determined on a sliding scale:
 o
    
    in the first three year contract term:
 §
    
    two percent of the first $200 million of Income; and§
    
    one percent of the balance of Income over $200 million; and
 o
    
    in the second three year contract term:
 §
    
    1.5 percent of the first $200 million of Income; and§
    
    0.5 percent of the balance of Income over $200 million.
 For these purposes, Income means the aggregate of net production revenue of the
Corporation and any other income earned from permitted investments of the Trust
(excluding interest on cash or near-cash deposits or similar investments).
 
    
    a performance based fee based on total returns received by Unitholders which
essentially compensates the Manager for total annual returns which average in excess of
eight percent per annum over a three year period;
    
    a ceiling on total fees payable determined in reference to a percentage of the fees
paid under the previous management agreement: 80 percent each year in the first three
year contract term and 60 percent each year in the second three year contract term and
subject to a further ceiling essentially equivalent to $12 million annually during the
second three year contract term;
 - 20 -




---



##### 



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




---



##### 



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




---



##### 



PENGROWTH  OPERATIONAL INFORMATION
  Principle Properties
   Summary of Company Interest
at December 31, 2007 (1)  (Forecast Prices and Costs)
 P+PValueReserve
    
    Before TaxP+P
    
    Remaining
    
    Life
    
    at 10%
    
    2007 Oil
    
    2007 Gas
    
    2007 NGL
    
    2007 TotalReserves(3)
    
    Reserve Life
    
    Index
    
    Discount
    
    Production
    
    Production
    
    Production
    
    ProductionField
    
    (Mboe)
    
    (years)
    
    (years)
    
    ($MM)
    
    (bblpd)
    
    (MMcfd)
    
    (bblpd)
    
    (boepd)(3)Light OilJudy Creek
    
    
    40,447
    
    
    
    50
    
    
    
    13.3
    
    
    
    797.9
    
    
    
    7,359
    
    
    
    4.1
    
    
    
    1,529
    
    
    
    9,564Weyburn
    
    
    21,966
    
    
    
    44
    
    
    
    21.1
    
    
    
    345.0
    
    
    
    2,779
    
    
    
    
    
    
    
    
    
    
    
    2,779Swan Hills
    
    
    17,593
    
    
    
    50
    
    
    
    20.1
    
    
    
    255.1
    
    
    
    1,968
    
    
    
    1.5
    
    
    
    280
    
    
    
    2,505Carson Creek
    
    
    15,194
    
    
    
    34
    
    
    
    11.9
    
    
    
    311.6
    
    
    
    2,031
    
    
    
    3.8
    
    
    
    505
    
    
    
    3,169Fenn Big Valley
    
    
    5,998
    
    
    
    28
    
    
    
    8.8
    
    
    
    104.5
    
    
    
    632
    
    
    
    6.1
    
    
    
    54
    
    
    
    1,703Deer Mountain
    
    
    5,264
    
    
    
    45
    
    
    
    19.7
    
    
    
    101.4
    
    
    
    543
    
    
    
    0.1
    
    
    
    60
    
    
    
    618Other(2)
    
    
    35,143
    
    
    
    
    
    
    
    9.8
    
    
    
    883.8
    
    
    
    8,908
    
    
    
    9.8
    
    
    
    708
    
    
    
    11,256Sub-Total
    
    
    141,605
    
    
    
    
    
    
    
    13.1
    
    
    
    2,799.3
    
    
    
    24,220
    
    
    
    25.4
    
    
    
    3,136
    
    
    
    31,594Heavy OilJenner
    
    
    7,728
    
    
    
    23
    
    
    
    7.2
    
    
    
    155.1
    
    
    
    2,890
    
    
    
    1.5
    
    
    
    4
    
    
    
    3,144Bodo
    
    
    7,658
    
    
    
    41
    
    
    
    12.6
    
    
    
    107.9
    
    
    
    1,439
    
    
    
    2.5
    
    
    
    
    
    
    
    1,862Tangleflags
    
    
    5,321
    
    
    
    25
    
    
    
    7.3
    
    
    
    56.2
    
    
    
    1,910
    
    
    
    0.2
    
    
    
    
    
    
    
    1,951Other(2)
    
    
    5,060
    
    
    
    
    
    
    
    8.6
    
    
    
    61.9
    
    
    
    970
    
    
    
    5.6
    
    
    
    
    
    
    
    1,902Sub-Total
    
    
    25,767
    
    
    
    
    
    
    
    8.6
    
    
    
    381.1
    
    
    
    7,209
    
    
    
    9.9
    
    
    
    4
    
    
    
    8,859Conventional GasOlds
    
    
    26,615
    
    
    
    48
    
    
    
    16.4
    
    
    
    293.1
    
    
    
    12
    
    
    
    25.0
    
    
    
    769
    
    
    
    4,952Harmattan
    
    
    10,857
    
    
    
    36
    
    
    
    7.9
    
    
    
    178.8
    
    
    
    346
    
    
    
    10.3
    
    
    
    932
    
    
    
    2,993Dunvegan
    
    
    6,204
    
    
    
    40
    
    
    
    10.4
    
    
    
    85.0
    
    
    
    35
    
    
    
    8.1
    
    
    
    444
    
    
    
    1,835Quirk Creek
    
    
    5,134
    
    
    
    38
    
    
    
    10.5
    
    
    
    77.9
    
    
    
    
    
    
    
    3.6
    
    
    
    214
    
    
    
    820Kaybob
    
    
    4,078
    
    
    
    38
    
    
    
    13.7
    
    
    
    45.6
    
    
    
    
    
    
    
    4.2
    
    
    
    37
    
    
    
    736McLeod River
    
    
    3,688
    
    
    
    41
    
    
    
    7.1
    
    
    
    61.1
    
    
    
    7
    
    
    
    6.4
    
    
    
    250
    
    
    
    1,316Blackstone
    
    
    3,588
    
    
    
    24
    
    
    
    10.3
    
    
    
    49.4
    
    
    
    
    
    
    
    6.1
    
    
    
    
    
    
    
    1,025Carson Creek
    
    
    2,958
    
    
    
    39
    
    
    
    5.2
    
    
    
    50.6
    
    
    
    
    
    
    
    6.2
    
    
    
    397
    
    
    
    1,430Other(2)
    
    
    18,788
    
    
    
    
    
    
    
    7.3
    
    
    
    309.1
    
    
    
    523
    
    
    
    43.7
    
    
    
    1,332
    
    
    
    9,137Sub-Total
    
    
    81,910
    
    
    
    
    
    
    
    9.7
    
    
    
    1,150.6
    
    
    
    923
    
    
    
    113.7
    
    
    
    4,375
    
    
    
    24,242Shallow GasThree Hills/Twining
    
    
    13,704
    
    
    
    50
    
    
    
    10.2
    
    
    
    218.2
    
    
    
    537
    
    
    
    17.7
    
    
    
    447
    
    
    
    3,939Coal Bed Methane
    
    
    9,312
    
    
    
    41
    
    
    
    11.3
    
    
    
    123.9
    
    
    
    1
    
    
    
    6.2
    
    
    
    6
    
    
    
    1,032Monogram
    
    
    8,044
    
    
    
    32
    
    
    
    8.9
    
    
    
    127.0
    
    
    
    
    
    
    
    12.1
    
    
    
    
    
    
    
    2,015Jenner
    
    
    7,435
    
    
    
    33
    
    
    
    9.4
    
    
    
    90.7
    
    
    
    4
    
    
    
    11.5
    
    
    
    2
    
    
    
    1,922Lethbridge
    
    
    3,685
    
    
    
    50
    
    
    
    7.6
    
    
    
    51.2
    
    
    
    
    
    
    
    7.2
    
    
    
    
    
    
    
    1,193Other(2)
    
    
    16,728
    
    
    
    
    
    
    
    10.0
    
    
    
    247.5
    
    
    
    600
    
    
    
    30.2
    
    
    
    18
    
    
    
    5,713
 - 23 -




---



##### 



P+PValueReserve
    
    Before TaxP+P
    
    Remaining
    
    Life
    
    at 10%
    
    2007 Oil
    
    2007 Gas
    
    2007 NGL
    
    2007 TotalReserves(3)
    
    Reserve Life
    
    Index
    
    Discount
    
    Production
    
    Production
    
    Production
    
    ProductionField
    
    (Mboe)
    
    (years)
    
    (years)
    
    ($MM)
    
    (bblpd)
    
    (MMcfd)
    
    (bblpd)
    
    (boepd)(3)Sub-Total
    
    
    58,908
    
    
    
    
    
    
    
    9.9
    
    
    
    858.4
    
    
    
    1,142
    
    
    
    84.8
    
    
    
    533
    
    
    
    15,813Offshore GasSable Island
    
    
    11,731
    
    
    
    9
    
    
    
    4.3
    
    
    
    266.6
    
    
    
    
    
    
    
    33.2
    
    
    
    1,362
    
    
    
    6,895Sub-Total
    
    
    11,731
    
    
    
    
    
    
    
    4.3
    
    
    
    266.6
    
    
    
    
    
    
    
    33.2
    
    
    
    1,362
    
    
    
    6,895Total
    
    
    319,921
    
    
    
    
    
    
    
    10.4
    
    
    
    5,455.9
    
    
    
    33,495
    
    
    
    267.0
    
    
    
    9,409
    
    
    
    87,401
 Notes:
 (1)
    
    The estimates of reserves and future net revenue for individual properties may not reflect
the same confidence level as estimates of reserves and future net revenue for all properties,
due to the effects of aggregation.
 (2)
    
    Other includes Pengrowths Working Interests and Royalty Interests in approximately 100
other properties.
 (3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 Light Oil Properties
 Judy Creek
  2007 Development Activity
  Carbon Dioxide (CO 2 ) Pilot
  - 24 -




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



2008 Development Activity
  - 34 -




---



##### 



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




---



##### 




    
    SIFT tax starting January 2011 at 26.5 percent (and 25 percent in 2012 and
thereafter) and corporate taxes as currently expected;
    
    Annual general and administration expenses at the current level;
    
    Interest expense at the current level;
    
    Inclusion of tax pools and deductions at the trust level as well as at the operating
entity level;
    
    Royalties paid to the Trust in the amount of the operating income;
    
    Distributions to Unitholders; and
    
    Any such other additional deductions and adjustments as is and would be consistent
with the manner in which Pengrowth files and would file future tax
returns. See Canadian Income Tax
Considerations.
   - 36 -




---



##### 



Reserves Data (Forecast Prices and Costs)
 Summary of Oil and Gas Reserves
as of December 31, 2007
(Forecast Prices and Costs)
 Light and Medium Oil




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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2007
(Constant Prices and Costs)
 Future NetCapital
    
    
    
    
    
    Future Net
    
    
    
    
    
    RevenueOperating
    
    Development
    
    Abandonment
    
    Revenue Before
    
    
    
    
    
    After IncomeRevenue
    
    Royalties(1)
    
    Costs
    
    Costs
    
    Costs(2)
    
    Income Taxes
    
    Income Tax
    
    TaxesReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    15,186
    
    
    
    2,526
    
    
    
    4,131
    
    
    
    526
    
    
    
    164
    
    
    
    7,839
    
    
    
    1,435
    
    
    
    6,404Total Proved Plus

Probable Reserves
    
    
    20,154
    
    
    
    3,402
    
    
    
    5,175
    
    
    
    758
    
    
    
    170
    
    
    
    10,649
    
    
    
    2,422
    
    
    
    8,227
 Notes:(1)
    
    Royalties payable to the provinces of Alberta, British Columbia, Saskatchewan and Nova
Scotia. Does not include the impact of the proposed royalty regime announced by the
Government of Alberta on October 25, 2007, to become effective on January 1, 2009. Based on
the interpretations by GLJ of the proposed royalty changes and based on the January 2008
commodity price assumptions of GLJ, it is anticipated that the new royalty regime will result
in a 12 to 18 percent increase in the total royalties paid to all parties by Pengrowth as
compared to the current royalty structure.(2)
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See
"Pengrowth  Operational Information  Additional Information Concerning Abandonment &
Reclamation Costs.
 Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2007
(Constant Prices and Costs)
 Future Net RevenueBefore Income Taxes(discounted at 10%/yr)
    
    Unit Value(3)Reserves Category
    
    Production Group
    
    ($MM)
    
    ($/boe)
    
    ($/Mcf)Total Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products) (1)
    
    
    2,755
    
    
    
    29.58
    
    
    
    4.93Heavy Oil (including solution gas and other by-products)(1)
    
    
    241
    
    
    
    14.19
    
    
    
    2.37Natural Gas (including by-products but excluding solution gas from oil wells) (2)
    
    
    1,500
    
    
    
    18.11
    
    
    
    3.02Non-conventional Oil & Gas Activities
    
    
    89
    
    
    
    13.16
    
    
    
    2.19Total
    
    
    4,585
    
    
    
    22.96
    
    
    
    3.83Total Proved Plus

Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products)(1)
    
    
    3,340
    
    
    
    27.11
    
    
    
    4.52Heavy Oil (including solution gas and other by-products) (1)
    
    
    291
    
    
    
    13.42
    
    
    
    2.24Natural Gas (including by-products but excluding solution gas from oil wells) (2)
    
    
    1,873
    
    
    
    17.14
    
    
    
    2.86Non-conventional Oil & Gas Activities
    
    
    114
    
    
    
    11.75
    
    
    
    1.96Total
    
    
    5,619
    
    
    
    21.29
    
    
    
    3.55
 Notes:(1)
    
    NGLs associated with the production of solution gas are included as a by-product.(2)
    
    NGLs associated with the production of natural gas are included as a by-product.(3)
    
    Unit values are based on Pengrowths Net reserves.
 - 42 -




---



##### 



Pricing Assumptions
 Forecast Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)WTI
    
    Edmonton
    
    Cromer
    
    HardistyCushing
    
    Par Price
    
    Medium
    
    Heavy 120
    
    AECO Gas
    
    
    
    
    
    Pentanes
    
    Inflation
    
    ExchangeOklahoma
    
    400API
    
    29.30API
    
    API
    
    Price
    
    Propane
    
    Butane
    
    Plus
    
    Rates(2)
    
    Rate(3)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/MMbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    (%/Year)
    
    ($US/Cdn)2007(4)
    
    72.24
    
    77.02
    
    66.30
    
    44.37
    
    6.65
    
    46.85
    
    58.35
    
    77.33
    
    
    
    
    
    
    2008
    
    92.00
    
    91.10
    
    79.26
    
    54.02
    
    6.75
    
    58.30
    
    72.88
    
    92.92
    
    
    2.0
    
    
    
    1.002009
    
    88.00
    
    87.10
    
    75.78
    
    51.61
    
    7.55
    
    55.74
    
    69.68
    
    88.84
    
    
    2.0
    
    
    
    1.002010
    
    84.00
    
    83.10
    
    72.30
    
    49.19
    
    7.60
    
    53.18
    
    66.48
    
    84.76
    
    
    2.0
    
    
    
    1.002011
    
    82.00
    
    81.10
    
    70.56
    
    47.98
    
    7.60
    
    51.90
    
    64.88
    
    82.72
    
    
    2.0
    
    
    
    1.002012
    
    82.00
    
    81.10
    
    70.56
    
    47.98
    
    7.60
    
    51.90
    
    64.88
    
    82.72
    
    
    2.0
    
    
    
    1.002013
    
    82.00
    
    81.10
    
    70.56
    
    49.04
    
    7.60
    
    51.90
    
    64.88
    
    82.72
    
    
    2.0
    
    
    
    1.002014
    
    82.00
    
    81.10
    
    70.56
    
    50.09
    
    7.80
    
    51.90
    
    64.88
    
    82.72
    
    
    2.0
    
    
    
    1.002015
    
    82.00
    
    81.10
    
    70.56
    
    51.15
    
    7.97
    
    51.90
    
    64.88
    
    82.72
    
    
    2.0
    
    
    
    1.002016
    
    82.02
    
    81.12
    
    70.57
    
    52.21
    
    8.14
    
    51.91
    
    64.89
    
    82.74
    
    
    2.0
    
    
    
    1.002017
    
    83.66
    
    82.76
    
    72.00
    
    53.29
    
    8.31
    
    52.97
    
    66.21
    
    84.42
    
    
    2.0
    
    
    
    1.00Thereafter
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    
    2.0
    
    
    
    1.00
 Notes:(1)
    
    FOB Edmonton.(2)
    
    Inflation rates for forecasting prices and costs.(3)
    
    The exchange rates used to generate the benchmark reference prices in this table.(4)
    
    Actual average prices for 2007.
 Constant Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)WTI
    
    Edmonton
    
    Cromer
    
    LLB CrudeCushing
    
    Par Price
    
    Medium
    
    Oil at
    
    AECO Gas
    
    
    
    
    
    
    
    
    
    Pentanes
    
    ExchangeOklahoma
    
    40oAPI
    
    29.3oAPI
    
    Hardisty
    
    Price
    
    Propane
    
    Butane
    
    Plus
    
    Rate(2)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/MMbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($US/Cdn)December 31, 2007
    
    
    95.92
    
    
    
    93.39
    
    
    
    74.26
    
    
    
    53.74
    
    
    
    6.63
    
    
    
    59.77
    
    
    
    74.71
    
    
    
    94.24
    
    
    
    1.012
 Notes:(1)
    
    FOB Edmonton.(2)
    
    The exchange rate used to generate the benchmark reference prices in this table.
 - 43 -




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



Acquisitions and Divestitures
    Future Development Capital
  - 48 -




---



##### 



2007 Finding, Development and Acquisition Costs
Company Interest Reserves
 Proved plusProved
    
    ProbableFD&A Costs Excluding Future Development CapitalExploration and Development Capital Expenditures ($thousands)
    
    $
    283,100
    
    
    $
    283,100Exploration and Development Reserve Additions including Revisions (Mboe)
    
    
    17,830
    
    
    
    17,376Finding and Development Cost ($/boe)
    
    $
    15.88
    
    
    $
    16.29Net Acquisition Capital ($thousands)
    
    $
    577,100
    
    
    $
    577,100Net Acquisition Reserve Additions (Mboe)
    
    
    29,364
    
    
    
    36,673Net Acquisition Cost ($/boe)
    
    $
    19.65
    
    
    $
    15.74Total Capital Expenditures including Net Acquisitions ($thousands)
    
    $
    860,200
    
    
    $
    860,200Reserve Additions including Net Acquisitions (Mboe)
    
    
    47,194
    
    
    
    54,049Finding Development and Acquisition Cost ($/boe)
    
    $
    18.23
    
    
    $
    15.92FD&A Costs Including Future Development CapitalExploration and Development Capital Expenditures ($thousands)
    
    $
    283,100
    
    
    $
    283,100Exploration and Development Change in FDC ($thousands)
    
    $
    8,000
    
    
    $
    20,000Exploration and Development Capital including Change in FDC ($thousands)
    
    $
    291,100
    
    
    $
    303,100Exploration and Development Reserve Additions including Revisions (Mboe)
    
    
    17,830
    
    
    
    17,376Finding and Development Cost ($/boe)
    
    $
    16.33
    
    
    $
    17.44Net Acquisition Capital ($thousands)
    
    $
    577,100
    
    
    $
    577,100Net Acquisition FDC ($thousands)
    
    $
    115,000
    
    
    $
    145,000Net Acquisition Capital including FDC ($thousands)
    
    $
    692,100
    
    
    $
    722,100Net Acquisition Reserve Additions (Mboe)
    
    
    29,364
    
    
    
    36,673Net Acquisition Cost ($/boe)
    
    $
    23.57
    
    
    $
    19.69Total Capital Expenditures including Net Acquisitions ($thousands)
    
    $
    860,200
    
    
    $
    860,200Total Change in FDC ($thousands)
    
    $
    123,000
    
    
    $
    165,000Total Capital including Change in FDC ($thousands)
    
    $
    983,300
    
    
    $
    1,025,300Reserve Additions including Net Acquisitions (Mboe)
    
    
    47,194
    
    
    
    54,049Finding Development and Acquisition Cost including FDC ($/boe)
    
    $
    20.83
    
    
    $
    18.97
 Note:(1)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one barrel of oil.
 Other Oil and Gas Information
 Oil and Gas Wells
  Producing
    
    Non-ProducingGross
    
    Net
    
    Gross
    
    NetCrude Oil WellsAlberta
    
    
    2,346
    
    
    
    1,473
    
    
    
    473
    
    
    
    277British Columbia
    
    
    151
    
    
    
    105
    
    
    
    47
    
    
    
    43Saskatchewan
    
    
    1,134
    
    
    
    279
    
    
    
    187
    
    
    
    81Nova Scotia
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Natural Gas WellsAlberta
    
    
    5,515
    
    
    
    2,827
    
    
    
    571
    
    
    
    322British Columbia
    
    
    124
    
    
    
    77
    
    
    
    25
    
    
    
    27Saskatchewan
    
    
    51
    
    
    
    48
    
    
    
    87
    
    
    
    47Nova Scotia
    
    
    19
    
    
    
    1
    
    
    
    
    
    
    
    Other(1)Alberta
    
    
    250
    
    
    
    217
    
    
    
    165
    
    
    
    115British Columbia
    
    
    
    
    
    
    
    
    
    
    50
    
    
    
    46Saskatchewan
    
    
    14
    
    
    
    10
    
    
    
    22
    
    
    
    19Total
    
    
    9,604
    
    
    
    5,038
    
    
    
    1,627
    
    
    
    976
 - 49 -




---



##### 



Note:(1)
    
    Pengrowth cannot classify these wells as either oil or gas.
 Properties with No Attributed Reserves
  Unproved Properties
as at December 31, 2007
 Net Area May ExpireLocation
    
    Gross Acres
    
    Net Acres
    
    During 2008Alberta
    
    
    1,095,994
    
    
    
    754,253
    
    
    
    129,887British Columbia
    
    
    255,172
    
    
    
    116,763
    
    
    
    13,847Ontario
    
    
    4,766
    
    
    
    
    
    
    
    Saskatchewan
    
    
    90,989
    
    
    
    76,335
    
    
    
    30,039Montana
    
    
    3,520
    
    
    
    3,520
    
    
    
    3,520Nova Scotia
    
    
    200,650
    
    
    
    15,957
    
    
    
    Total
    
    
    1,651,091
    
    
    
    966,828
    
    
    
    177,293
  Additional Information Concerning Abandonment & Reclamation Costs
    Asset Retirement Obligations
 2008
    
    2009
    
    2010
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment, Reclamation,
Remediation & Dismantling
    
    
    17,287
    
    
    
    18,046
    
    
    
    21,363
    
    
    
    1,958,381
    
    
    
    2,015,077Discounted at 10 percent
    
    
    16,483
    
    
    
    15,642
    
    
    
    16,834
    
    
    
    220,908
    
    
    
    269,867
  - 50 -




---



##### 



Costs Incurred
  AmountNature of Cost
    
    ($MM)Acquisition Costs(1)Proved
    
    
    823,566Unproved
    
    
    212,317Exploration Costs
    
    
    21,192Development Costs
    
    
    261,866Total
    
    
    1,318,941
 Note:(1)
    
    Based on the values assigned to property, plant and equipment in the purchase price
allocations for the CP Acquisition and for several minor property acquisitions.
 Exploration and Development Activities
  Development
    
    Exploration
    
    TotalGross
    
    Net
    
    Gross
    
    Net
    
    Gross
    
    NetWellsGas
    
    
    383
    
    
    
    130.7
    
    
    
    6
    
    
    
    2.2
    
    
    
    389
    
    
    
    132.9Oil
    
    
    84
    
    
    
    19.9
    
    
    
    6
    
    
    
    5.3
    
    
    
    90
    
    
    
    25.2Service
    
    
    15
    
    
    
    8.4
    
    
    
    
    
    
    
    
    
    
    
    15
    
    
    
    8.4Dry
    
    
    12
    
    
    
    5.6
    
    
    
    5
    
    
    
    2.6
    
    
    
    17
    
    
    
    8.2Total
    
    
    494
    
    
    
    164.6
    
    
    
    17
    
    
    
    10.1
    
    
    
    511
    
    
    
    174.7
 Production Estimates
  Estimated ProductionConstant Prices and Costs
    
    Forecast Prices and CostsTotal Proved Plus
    
    
    
    
    
    Total Proved PlusTotal Proved
    
    Probable
    
    Total Proved
    
    ProbableLight and Medium Crude Oil
(bblpd)
    
    
    24,933
    
    
    
    26,169
    
    
    
    24,933
    
    
    
    26,169Heavy Oil (bblpd)
    
    
    6,485
    
    
    
    6,711
    
    
    
    6,485
    
    
    
    6,711Natural Gas (Mcfpd)
    
    
    245,006
    
    
    
    255,631
    
    
    
    245,007
    
    
    
    255,631Natural Gas Liquids (bblpd)
    
    
    8,250
    
    
    
    8,526
    
    
    
    8,250
    
    
    
    8,526
 - 51 -




---



##### 



Production History (Netback)
  Quarter EndedMarch 31,
    
    June 30,
    
    September 30,
    
    December 31,2007
    
    2007
    
    2007
    
    2007Light Crude OilAverage Daily Oil Production(1) (bblpd)
    
    
    27,461
    
    
    
    27,083
    
    
    
    24,903
    
    
    
    25,892Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    67.24
    
    
    
    71.81
    
    
    
    75.10
    
    
    
    73.69Processing and other income ($/bbl)
    
    
    0.39
    
    
    
    0.42
    
    
    
    0.90
    
    
    
    0.69Royalties ($/bbl)
    
    
    (9.88
    )
    
    
    (11.90
    )
    
    
    (10.65
    )
    
    
    (13.86
    )Amortization of injectants ($/bbl)
    
    
    (3.84
    )
    
    
    (3.51
    )
    
    
    (3.69
    )
    
    
    (3.14
    )Production Costs(2)($/bbl)
    
    
    (13.31
    )
    
    
    (15.11
    )
    
    
    (16.93
    )
    
    
    (15.69
    )Operating Netback ($/bbl)
    
    
    40.60
    
    
    
    41.71
    
    
    
    44.73
    
    
    
    41.69Heavy OilAverage Daily Oil Production(1) (bblpd)
    
    
    6,773
    
    
    
    7,254
    
    
    
    7,205
    
    
    
    7,434Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    41.54
    
    
    
    43.52
    
    
    
    47.30
    
    
    
    45.47Processing and other income ($/bbl)
    
    
    0.18
    
    
    
    0.18
    
    
    
    0.50
    
    
    
    0.19Royalties ($/bbl)
    
    
    (5.23
    )
    
    
    (5.33
    )
    
    
    (6.90
    )
    
    
    (5.91
    )Production Costs(2)($/bbl)
    
    
    (13.15
    )
    
    
    (15.37
    )
    
    
    (9.43
    )
    
    
    (12.92
    )Operating Netback ($/bbl)
    
    
    23.34
    
    
    
    23.00
    
    
    
    31.47
    
    
    
    26.83NGLsAverage Daily NGL Production(1) (bblpd)
    
    
    9,918
    
    
    
    8,519
    
    
    
    9,883
    
    
    
    9,319Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    49.67
    
    
    
    56.42
    
    
    
    61.69
    
    
    
    67.64Royalties ($/bbl)
    
    
    (14.05
    )
    
    
    (17.53
    )
    
    
    (18.82
    )
    
    
    (23.61
    )Production Costs(2)($/bbl)
    
    
    (12.02
    )
    
    
    (13.57
    )
    
    
    (10.96
    )
    
    
    (14.29
    )Operating Netback ($/bbl)
    
    
    23.60
    
    
    
    25.32
    
    
    
    31.91
    
    
    
    29.74Natural GasAverage Daily Gas Production(1) (Mcfpd)
    
    
    275,495
    
    
    
    280,667
    
    
    
    261,976
    
    
    
    250,117Sales Price (net of hedging gains/losses) ($/Mcf)
    
    
    7.91
    
    
    
    7.61
    
    
    
    6.67
    
    
    
    6.90Processing and other income ($/Mcf)
    
    
    0.15
    
    
    
    0.16
    
    
    
    0.19
    
    
    
    0.18Royalties ($/Mcf)
    
    
    (1.67
    )
    
    
    (1.47
    )
    
    
    (0.92
    )
    
    
    (1.22
    )Production Costs(2)($/Mcf)
    
    
    (2.10
    )
    
    
    (2.24
    )
    
    
    (1.58
    )
    
    
    (2.11
    )Operating Netback ($/Mcf)
    
    
    4.29
    
    
    
    4.06
    
    
    
    4.36
    
    
    
    3.75Barrels of Oil Equivalent Basis(3)Average Daily Production(1) (boepd)
    
    
    90,068
    
    
    
    89,633
    
    
    
    85,654
    
    
    
    84,331Sales Price (net of hedging gains/losses) ($/boe)
    
    
    53.30
    
    
    
    54.39
    
    
    
    53.34
    
    
    
    54.58Processing and other income ($/boe)
    
    
    0.58
    
    
    
    0.66
    
    
    
    0.90
    
    
    
    0.76Royalties ($/boe)
    
    
    (10.06
    )
    
    
    (10.30
    )
    
    
    (8.67
    )
    
    
    (11.01
    )Amortization of injectants ($/boe)
    
    
    (1.17
    )
    
    
    (1.06
    )
    
    
    (1.07
    )
    
    
    (0.97
    )Production Costs(2) ($/boe)
    
    
    (12.78
    )
    
    
    (14.13
    )
    
    
    (11.84
    )
    
    
    (13.80
    )Operating Netback ($/boe)
    
    
    29.87
    
    
    
    29.56
    
    
    
    32.66
    
    
    
    29.56
 Notes:(1)
    
    Before the deduction of royalties.(2)
    
    Includes transportation costs. Net of processing and other income.(3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six Mcf of
natural gas being equal to one boe.
 Replacement of Properties
  - 52 -




---



##### 



Net Asset Value (NAV) at December 31, 2007
  ($ thousands,unless otherwise indicated)Value of Total Proved Plus Probable Reserves
    
    
    5,455,881Undeveloped lands (1)
    
    
    239,893Working capital deficit (2)
    
    
    (34,423
    )Reclamation funds
    
    
    18,094Long-term debt
    
    
    (1,203,236
    )Fair value of risk management contracts (3)
    
    
    (79,401
    )Other liabilities (4)
    
    
    (87,192
    )Asset retirement obligations (5)
    
    
    (206,868
    )Net asset value
    
    
    4,102,748Units outstanding (000s)
    
    
    246,846NAV per unit
    
    $
    16.62
 Notes:(1)
    
    Pengrowths internal estimate, calculated using the average land sale prices paid in 2007 in
Alberta, Saskatchewan and British Columbia.(2)
    
    Excludes distributions payable, current portion of risk management contracts and future
income taxes.(3)
    
    Represents the total fair value of risk management contracts at December 31, 2007.(4)
    
    Other liabilities include convertible debt and non-current contract liabilities.(5)
    
    The asset retirement obligation is based on Pengrowths estimate of future site restoration
and abandonment liabilities, discounted at 10 percent, less that portion of
the asset retirement obligations costs that are included in the value of Total Proved Plus Probable Reserves.
 TRUST UNITS
 The Trust Indenture
   - 53 -




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##### 



Canadian Deposit Insurance Corporation Act
 The Trustee
    Stock Exchange Listings
  Ownership Restrictions
  Redemption Right
 in
specie
 - 54 -




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##### 



Conversion Rights
  Voting at Meetings of Unitholders
    Voting at Meetings of Corporation
  Termination of the Trust
  
    
    a vote may be held only if: (i) requested in writing by the holders of not less than
25 percent of the Trust Units and class A trust units, in the aggregate; or (ii) if the
Trust Units and the class A trust units have become ineligible for investment by RRSPs,
RRIFs, RESPs and DPSPs;
    
    the termination must be approved by extraordinary resolution of the Unitholders; and
 - 55 -




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##### 




    
    a quorum representing 5 percent of the issued and outstanding Trust Units and class
A trust units, in the aggregate, must be present or represented by proxy at the meeting
at which the vote is taken.
  Unitholder Limited Liability
  - 56 -




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##### 



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




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The Trustee
   EXCHANGEABLE SHARES
    - 58 -




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##### 



DISTRIBUTIONS
 General
  Historical Distributions
 Risk Factors"
  2007
    
    2006
    
    2005
    
    2004
    
    2003
    
    2002First Quarter
    
    $
    0.75
    
    
    $
    0.75
    
    
    $
    0.69
    
    
    $
    0.63
    
    
    $
    0.75
    
    
    $
    0.41Second Quarter
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.64
    
    
    
    0.67
    
    
    
    0.54Third Quarter
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.67
    
    
    
    0.63
    
    
    
    0.52Fourth Quarter
    
    
    0.675
    (1)
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.63
    
    
    
    0.60Total
    
    $
    2.93
    
    
    $
    3.00
    
    
    $
    2.82
    
    
    $
    2.63
    
    
    $
    2.68
    
    
    $
    2.07
 Notes:(1)
    
    On October 15, 2007, November 15, 2007 and December 15, 2007, the monthly distribution paid
to Unitholders was $0.225 per Trust Unit, representing a reduction of 10 percent from the
monthly distribution of $0.25 per Trust Unit for the first three quarters of 2007.(2)
    
    Based on actual distributions declared.
  - 59 -




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




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Revolving Credit Facility
   
    
    the ratio of Consolidated Senior Debt (as defined below) to Consolidated EBITDA (as
defined below) at the end of any fiscal quarter shall not exceed 3:1, except that upon
the completion of a Material Acquisition (as defined below), and for a period extending
to the end of the second full fiscal quarter thereafter, this limit increases to 3.5:1;
    
    the ratio of Consolidated Total Debt (as defined below) to Consolidated EBITDA at
the end of any fiscal quarter shall not exceed 3.5:1; except that upon the completion
of a Material Acquisition, and for a period extending to the end of the second full
fiscal quarter thereafter, this limit increases to 4:1; and
    
    the ratio of Consolidated Senior Debt (as defined below) to Total Capitalization (as
defined below) shall not exceed 50 percent, except that upon the completion of a
Material Acquisition, and for a period extending to the end of the second full fiscal
quarter thereafter, this limit increases to 55 percent.
  Consolidated Senior Debt:
    
    All obligations, liabilities and indebtedness that would be classified as debt on
the consolidated balance sheet of the Trust, including, without limitation, certain
items including all indebtedness for borrowed money, but excluding certain items.Consolidated Total Debt:
    
    The aggregate of Consolidated Senior Debt and Subordinated Debt.Consolidated EBITDA:
    
    The aggregate of the last four quarters net income from operations plus the sum of:   income taxes;   interest expense;   all provisions for federal, provincial or other income and capital taxes;   depreciation, depletion and amortization expense; and   other non-cash amounts.Material Acquisition:
    
    An acquisition or series of acquisitions which increases the consolidated tangible
assets of Pengrowth by more than 5 percent.Subordinated Debt:
    
    Debt which, by its terms, is subordinated to the obligations to the lenders under
the Credit Facility.
 - 61 -




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##### 



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




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##### 



Convertible Debentures
 General Development of Pengrowth Energy
Trust  Recent Developments  Changes to Tax Legislation Affecting Pengrowth and its Unitholders
and its Debentureholders
   
    
    the Trust is required to punctually pay or cause to be paid all principal, premium
and interest amounts as prescribed by the Debenture Indenture, as amended;
    
    the Trust is required to pay the trustee under the Debenture Indenture reasonable
remuneration for its services as trustee and repay on demand all monies which have been
paid by the trustee in execution of its obligations thereunder;
    
    the Trust is required to provide the trustee under the Debenture Indenture with
notification immediately upon obtaining knowledge of any Event of Default;
    
    the Trust is required to carry on its business in a proper, efficient and
business-like manner and in accordance with good business practices;
    
    the Trust is required to deliver to the trustee under the Debenture Indenture,
within 120 days of the end of each calendar year, an officers certificate as to
compliance with the terms and conditions of the Debenture Indenture; and
    
    the Trust is prohibited from issuing additional debentures, which are convertible at
the option of the holder into Trust Units of equal ranking to the Debentures if the
principal amount of all issued and outstanding convertible debentures of the Trust
would exceed 25 percent of the Trusts total market capitalization after the issuance
of such additional debentures.
 
 - 63 -




---



##### 



CERTAIN CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
 Taxation of the Trust
 SIFT Legislation
      - 64 -




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



Depreciation
  Valuation of Our Properties
  Section 754 Election
   - 72 -




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



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




---



##### 



British Columbia
   Saskatchewan
   Nova Scotia
  Environmental Regulation
   - 78 -




---



##### 



- 79 -




---



##### 



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




---



##### 




    
    the level of consumer demand;
    
    the price and availability of alternative fuels;
    
    the proximity to, and capacity of, transportation facilities;
    
    the effect of worldwide energy conservation measures; and
    
    government regulation.
  Distributions may be reduced during periods in which the Corporation makes capital expenditures
using cash flow, which could also negatively affect the market price of the Trust Units.
   Actual reserves will vary from reserve estimates, and those variations could be material, and
negatively affect the market price of the Trust Units and distributions to our Unitholders.
  
    
    historical production from the area compared with production rates from similar
producing areas;
    
    the assumed effect of government regulation;
    
    assumptions about future commodity prices, exchange rates, production and
development costs, capital expenditures, abandonment costs, environmental liabilities,
and applicable royalty regimes;
    
    initial production rates;
    
    production decline rates;
    
    ultimate recovery of reserves;
 - 81 -




---



##### 



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




---



##### 



We may be unable to successfully compete with other companies in our industry, which could
negatively affect the market price of the Trust Units and distributions to our Unitholders.
  Incorrect assessments of value at the time of acquisitions could adversely affect the value of our
Trust Units and distributions to our Unitholders.
  Our indebtedness may limit the amount of distributions that we are able to pay our Unitholders, and
if we default on our debts, the net proceeds of any foreclosure sale would be allocated to the
repayment of our lenders, note holders and other creditors and only the remainder, if any, would be
available for distribution to our Unitholders.
 Distributions  Restrictions on
Distributions
 We are dependent on our management and the loss of our key management and other personnel could
negatively impact our business.
  A decline in the Corporations ability to market its oil and natural gas production could have a
material adverse effect on production levels or on the price received for production, which, in
turn, could reduce distributions to our Unitholders and affect the market price of the Trust Units.
 - 83 -




---



##### 



The operation of a significant portion of our properties is largely dependent on the ability of
third party operators, and harm to their business could cause delays and additional expenses in our
receiving revenues, which could negatively affect the market price of the Trust Units and
distributions to our Unitholders.
   Our distributions could be adversely affected by unforeseen title defects, which could reduce
distributions to our Unitholders.
  Fluctuations in foreign currency exchange rates could adversely affect our business, and adversely
affect the market price of the Trust Units as well as distributions to our Unitholders.
   Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of
the Corporation. If the oil and natural gas reserves associated with the Corporations resource
properties are
 - 84 -




---



##### 



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




---



##### 



Changes in Canadian legislation could adversely affect the value of our Trust Units.
  If the Trust ceases to qualify as a mutual fund trust it would adversely affect the value of our
Trust Units.
   
    
    The Trust Units would cease to be a qualified investment for trusts governed by
RRSPs, RRIFs, RESPs and DPSPs, as defined in the Tax Act. Where, at the end of a
month, a RRSP, RRIF, RESP or DPSP holds Trust Units that ceased to be a qualified
investment, the RRSP, RRIF, RESP or DPSP, as the case may be, must, in respect of that
month, pay a tax under Part XI.1 of the Tax Act equal to 1 percent of the fair market
value of the Trust Units at the time such Trust Units were acquired by the RRSP, RRIF,
RESP or DPSP. In addition, trusts governed by a RRSP or a RRIF which hold Trust Units
that are not qualified investments will be subject to tax on the income attributable to
the Trust Units while they are non-qualified investments, including the full capital
gains, if any, realized on the disposition of such Trust Units. Where a trust governed
by a RRSP or a RRIF acquires Trust Units that are not qualified investments, the value
of the investment will be included in the income of the annuitant for the year of the
acquisition. Trusts governed by RESPs which hold Trust Units that are not qualified
investments can have their registration revoked by the Canada Revenue Agency.
    
    The Trust would be required to pay a tax under Part XII.2 of the Tax Act. The
payment of Part XII.2 tax by the Trust may have adverse income tax consequences for
certain Unitholders, including non-resident persons and residents of Canada who are
exempt from Part I tax.
    
    The Trust would not be entitled to use the capital gains refund mechanism otherwise
available for mutual fund trusts.
    
    The Trust Units would constitute taxable Canadian property for the purposes of the
Tax Act, potentially subjecting non-residents of Canada to tax pursuant to the Tax Act
on the disposition (or deemed disposition) of such Trust Units.
 The ability of investors resident in the United States to enforce civil remedies may be negatively
affected for a number of reasons.
 Securities Act of 1933
 - 86 -




---



##### 



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




---



##### 



You may be required to pay taxes even if you do not receive any cash distributions.
  Unitholders who are United States persons face certain income tax risks.
  
    
    We have elected under applicable United States Treasury Regulations to be treated as
a partnership for United States federal income tax purposes. Section 7704 of the
Internal Revenue Code of 1986, as amended (the Code) provides that publicly-traded
partnerships such as the Trust will, as a general rule, be taxed as corporations. We
will not be treated as a corporation for U.S. federal income tax purposes only if
90 percent or more of its gross income consists of qualifying income. Although we
expect to satisfy the 90 percent requirement at all times, if we fail to satisfy this
requirement, we will be treated as a foreign corporation. Such conversion will be
taxable unless a certain filing is made.
    
    If we were treated as a foreign corporation, we could be a passive foreign
investment company or PFIC. If we were considered a PFIC, United States holders of
Trust Units could be subject to substantially increased United States tax liability,
including an interest charge upon the sale or other disposition of the United States
holders Trust Units, or upon the receipt of excess distributions from the Trust.
Certain elections may be available to a United States holder if we were classified as a
PFIC to alleviate these adverse tax consequences.
    
    We treat the Royalty between the Trust and the Corporation as a royalty interest for
all legal purposes, including United States federal income tax purposes. The Royalty
Indenture in some respects differs from more conventional net profits interests as to
which the courts and the IRS have ruled regarding the federal income tax treatment as a
royalty, and as a result the propriety of such treatment is not free from doubt. It is
possible that the IRS could contend, for example, that we should be considered to have
a working interest in the properties of the Corporation. If the IRS were successful in
making such a contention, the United States federal income tax consequences to United
States holders could be different, perhaps materially worse, than indicated in the
discussion herein, which generally assumes that the Royalty Indenture will be respected
as a royalty.
    
    Gain or loss will be recognized on a sale of Trust Units equal to the difference
between the amount realized and the United States holders tax basis for the
Trust Units sold. Gain or loss recognized by a United States holder on the sale or
exchange of Trust Units will generally be taxable as capital gain or loss, and will be
long-term capital gain or loss if such United States holders holding period of the
Trust Units exceeds one year. A portion of any amount realized on a sale or exchange
of Trust Units (which portion could be substantial) will be separately computed and
taxed as ordinary income under Section 751 of the Code to the extent attributable to
the recapture of depletion or depreciation deductions. Ordinary income attributable to
depletion deductions and depreciation recapture could exceed net taxable gain realized
upon the sale of the Trust Units and may be recognized even if there is a net taxable
loss realized on the sale of the Trust Units. Thus, a United States holder may
recognize both ordinary income and a capital loss upon a taxable disposition of
Trust Units.
 - 88 -




---



##### 



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




---



##### 



transparent entity for U.S. federal income tax purposes, which is the case inasmuch
as Pengrowth is treated as a partnership for U.S. federal income tax purposes, and
(iii) the tax treatment of the amount (or distribution) received by the U.S. Resident
Unitholder would, for U.S. federal income tax purposes, be different if Pengrowth
were not treated as fiscally transparent for U.S. federal income tax purposes. The
effect of Article IV(7)(b) of the Protocol is that the Canadian withholding tax rate
on distributions of income would be 25 percent instead of
15 percent or such lower rate otherwise available under the
Canada-U.S. Convention. Returns of
capital would still be subject to a 15 percent Canadian withholding tax and such rate
is not modified by the Protocol. The Protocol also contains measures which,
generally speaking, are designed to limit the benefits under the Canada-U.S.
Convention to treaty shopping transactions or arrangements.
 Distributions to our Unitholders may be reduced during periods in which Pengrowth makes capital
expenditures using cash flow.
  Changes in government regulations that affect the crude oil and natural gas industry could
adversely affect Pengrowth and reduce our distributions to our Unitholders.
      - 90 -




---



##### 



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




---



##### 



The limited liability of Unitholders is uncertain.
  The redemption right of Unitholders is limited.
 Description of Trust Units  Redemption Right in specie
 The industry in which Pengrowth operates exposes Pengrowth to potential liabilities that may not be
covered by insurance.
  - 92 -




---



##### 



MARKET FOR SECURITIES
  Toronto Stock Exchange
    
    New York Stock ExchangeTrust Unit Price Range
    
    
    
    
    
    Trust Unit Price RangeHigh
    
    Low
    
    Close
    
    Volume
    
    High
    
    Low
    
    Close
    
    Volume(Canadian $ per Trust Unit)
    
    (thousands)
    
    (U.S. $ per Trust Unit)
    
    (thousands)2007January
    
    
    20.55
    
    
    
    18.62
    
    
    
    19.85
    
    
    
    15,459
    
    
    
    17.41
    
    
    
    15.82
    
    
    
    16.94
    
    
    
    10,566February
    
    
    20.85
    
    
    
    19.50
    
    
    
    19.98
    
    
    
    9,312
    
    
    
    17.96
    
    
    
    16.67
    
    
    
    17.23
    
    
    
    6,983March
    
    
    20.37
    
    
    
    18.71
    
    
    
    19.45
    
    
    
    12,971
    
    
    
    17.59
    
    
    
    15.95
    
    
    
    16.87
    
    
    
    9,085April
    
    
    19.83
    
    
    
    18.82
    
    
    
    19.11
    
    
    
    9,615
    
    
    
    17.74
    
    
    
    16.45
    
    
    
    17.27
    
    
    
    7,127May
    
    
    20.62
    
    
    
    19.00
    
    
    
    19.92
    
    
    
    9,382
    
    
    
    19.05
    
    
    
    17.18
    
    
    
    18.73
    
    
    
    9,519June
    
    
    21.04
    
    
    
    19.68
    
    
    
    20.27
    
    
    
    9,351
    
    
    
    19.84
    
    
    
    18.50
    
    
    
    19.09
    
    
    
    7,021July
    
    
    20.70
    
    
    
    18.71
    
    
    
    19.51
    
    
    
    8,746
    
    
    
    19.85
    
    
    
    17.51
    
    
    
    18.30
    
    
    
    5,870August
    
    
    19.50
    
    
    
    17.40
    
    
    
    18.04
    
    
    
    7,886
    
    
    
    18.43
    
    
    
    16.25
    
    
    
    17.06
    
    
    
    6,396September
    
    
    18.78
    
    
    
    16.92
    
    
    
    18.64
    
    
    
    11,608
    
    
    
    18.87
    
    
    
    16.65
    
    
    
    18.84
    
    
    
    7,019October
    
    
    18.68
    
    
    
    17.65
    
    
    
    18.00
    
    
    
    8,144
    
    
    
    19.10
    
    
    
    17.90
    
    
    
    18.92
    
    
    
    5,681November
    
    
    18.45
    
    
    
    17.00
    
    
    
    18.11
    
    
    
    8,417
    
    
    
    19.21
    
    
    
    17.70
    
    
    
    18.13
    
    
    
    5,239December
    
    
    18.50
    
    
    
    17.31
    
    
    
    17.62
    
    
    
    6,998
    
    
    
    18.24
    
    
    
    17.30
    
    
    
    17.77
    
    
    
    3,060
  Toronto Stock ExchangeDebenture Price RangeHigh
    
    Low
    
    Close
    
    Volume(Canadian $ per Debenture)
    
    (thousands)2007January
    
    
    102.49
    
    
    
    98.51
    
    
    
    101.01
    
    
    
    1,738February
    
    
    102.25
    
    
    
    101.00
    
    
    
    101.25
    
    
    
    828March
    
    
    102.55
    
    
    
    100.00
    
    
    
    100.51
    
    
    
    767April
    
    
    102.55
    
    
    
    99.77
    
    
    
    102.00
    
    
    
    661May
    
    
    104.00
    
    
    
    100.60
    
    
    
    101.10
    
    
    
    279June
    
    
    102.50
    
    
    
    100.00
    
    
    
    100.51
    
    
    
    494July
    
    
    102.99
    
    
    
    100.03
    
    
    
    100.04
    
    
    
    327August
    
    
    100.02
    
    
    
    98.00
    
    
    
    99.50
    
    
    
    590September
    
    
    99.75
    
    
    
    98.50
    
    
    
    99.00
    
    
    
    560October
    
    
    100.80
    
    
    
    99.00
    
    
    
    99.75
    
    
    
    518November
    
    
    101.00
    
    
    
    98.50
    
    
    
    99.50
    
    
    
    633December
    
    
    102.89
    
    
    
    98.00
    
    
    
    100.00
    
    
    
    1,149.3
 - 93 -




---



##### 



DIRECTORS AND OFFICERS
  Directors and Officers of the Manager
  Name and Jurisdiction
    
    Position withof Residence
    
    Pengrowth Management
    
    Principal OccupationJames S. Kinnear
    
    President and Director (since 1982)
    
    PresidentAlberta, Canada
    
    
    
    Pengrowth Management LimitedGordon M. Anderson
    
    Vice President, Financial Services (since 2001)
    
    Vice President, Financial ServicesAlberta, Canada
    
    Vice President, Treasurer (1998-2001)
    
    Pengrowth Management LimitedTreasurer (1995-1998)Grant A. Henschel
    
    Vice President, Engineering
    
    Vice President, EngineeringAlberta, Canada
    
    
    
    Pengrowth Management LimitedLeslie F. Kende
    
    Vice President, New Ventures
    
    Vice President, New VenturesAlberta, Canada
    
    
    
    Pengrowth Management LimitedRobert M. Nicolay
    
    Vice President, Business Development
    
    Vice President, Business DevelopmentAlberta, Canada
    
    
    
    Pengrowth Management LimitedCharles V. Selby
    
    Corporate Secretary (since 1993)
    
    PresidentAlberta, Canada
    
    Treasurer
    
    Selby Professional Corporation
  Principal Holders of Shares of the Manager
  Directors and Officers of the Corporation
  - 94 -




---



##### 



Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)James S. Kinnear
    
    President, Chairman, Director and
    
    President
    
    
    5,996,238Alberta, Canada
    
    Chief Executive Office (since 1988)
    
    Pengrowth Management LimitedThomas A. Cumming(2)(4)(5)
    
    Director (since 2000)
    
    Business Consultant
    
    
    8,678Alberta, CanadaWayne K. Foo(2)(3)
    
    Director (since 2006)
    
    President
    
    
    3,843Alberta, Canada
    
    
    
    Petro Andina Resources Ind.Kirby L. Hedrick(2)(5)
    
    Director (since 2005)
    
    Business Consultant
    
    
    4,000Wyoming, United States of AmericaMichael S. Parrett(3)(4)(5)
    
    Director (since 2004)
    
    Business Consultant
    
    
    4,000Ontario, CanadaA. Terence Poole(3)(5)
    
    Director (since 2005)
    
    Business Consultant
    
    
    30,000Alberta, CanadaD. Michael G. Stewart(2)(4)
    
    Director (since 2006)
    
    Principal of the Ballinacurra
    
    
    13,370Alberta, Canada
    
    
    
    Group, Corporate DirectorNicholas C.H. Villiers
    
    Director (since 2007)
    
    Business Consultant
    
    London, EnglandJohn B. Zaozirny(3)(4)
    
    Director (since 1988)
    
    Counsel, McCarthy Tétrault
    
    
    35,100Alberta, Canada
    
    
    
    Barristers and SolicitorsGordon M. Anderson
    
    Vice President (since 2001)
    
    Vice President, Financial
    
    21,066Alberta, Canada
    
    Vice President, Treasurer (1997-2001)
    
    Services Pengrowth ManagementTreasurer (1995-1997)
    
    LimitedChief Financial Officer (1991-1998)Douglas C. Bowles
    
    Vice President and Controller
    
    Vice President and Controller
    
    11,446Alberta, Canada
    
    (since March 1, 2006)
    
    Pengrowth CorporationController (since 2005)James E.A. Causgrove
    
    Vice President, Production and
    
    Vice President, Production
    
    23,621Alberta, Canada
    
    Operations (since 2005)
    
    and Operations Pengrowth
CorporationPeter Cheung
    
    Vice President (since 2008)
    
    Vice President and Treasurer
    
    17,428Alberta, Canada
    
    Treasurer (since 2005)
    
    Pengrowth CorporationWilliam G. Christensen
    
    Vice President, Strategic Planning and
    
    Vice President, Strategic
    
    15,821Alberta, Canada
    
    Reservoir Exploitation (since 2005)
    
    Planning and Reservoir
Exploitation Pengrowth
CorporationJames M. Donihee
    
    Vice-President and Chief of Staff
    
    Vice-President and Chief of
    
    7,086Alberta, Canada
    
    (since 2007)
    
    Staff Pengrowth CorporationCharles V. Selby
    
    Vice President and Corporate Secretary
    
    President
    
    146,916Alberta, Canada
    
    (since 2005)
    
    Selby Professional CorporationCorporate Secretary (since 1993)Larry B. Strong
    
    Vice President, Geosciences (since 2005)
    
    Vice President, Geosciences
    
    37,118Alberta, Canada
    
    
    
    Pengrowth CorporationChristopher G. Webster
    
    Chief Financial Officer (since 2005)
    
    Chief Financial Officer
    
    37,065Alberta, Canada
    
    Treasurer (2000  2005)
    
    Pengrowth Corporation
 - 95 -




---



##### 



Notes:(1)
    
    As at December 31, 2007 and excluding Trust Units issuable upon the exercise of outstanding
options, rights or deferred entitlement units.(2)
    
    Member of Reserves, Operations and Environmental, Health and Safety Committee.(3)
    
    Member of Corporate Governance Committee.(4)
    
    Member of Compensation Committee.(5)
    
    Member of Audit Committee.    Corporate Cease Trade Orders or Bankruptcies
  (i)
    
    was the subject of a cease trade or similar order or an order that denied the
relevant company access to any exemption under securities legislation for a period of
more than 30 consecutive days; or(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
 - 96 -




---



##### 



(iii)
    
    within a year of that person ceasing to act in that capacity, became bankrupt,
made a proposal under any legislation relating to bankruptcy or insolvency or was
subject to or instituted any proceedings, arrangement or compromise with creditors or
had a receiver, receiver manager or trustee appointed to hold its assets.
 Personal Bankruptcies
  Penalties or Sanctions
  (i)
    
    been subject to any penalties or sanctions imposed by a court relating to
securities legislation or by a securities regulatory authority or has entered into a
settlement agreement with a securities regulatory authority, other than penalties for
late filing of insider reports; or(ii)
    
    been subject to any other penalties or sanctions imposed by a court or
regulatory body that would likely be considered important to a reasonable investor in
making an investment decision.
 AUDIT COMMITTEE
 Audit Committees
 FinanciallyName
    
    Independent
    
    Literate
    
    Relevant Education and ExperienceThomas A. Cumming
    
    Yes
    
    Yes
    
    Mr. Cumming was President and
Chief Executive Officer of the
Alberta Stock Exchange from 1988
to 1999. His career also
includes 25 years with a major
Canadian bank both nationally
and internationally. He is
currently Chairman of Albertas
Electricity Balancing Pool, and
serves as a Director of the
Alberta Capital Market
Foundation. He is also a past
president of the Calgary Chamber
of Commerce. Mr. Cumming is a
professional engineer and holds
a Bachelor of Applied Science
degree in Engineering and
Business from the University of
Toronto.Michael S. Parrett
    
    Yes
    
    Yes
    
    Mr. Parrett is currently an
independent consultant providing
advisory service to various
companies in Canada and the
United States. Mr. Parrett is
Chairman of Gabriel Resources
Limited, a member of the board
of Fording Inc. and is serving
as a Trustee for Fording
Canadian Coal Trust. He was
formerly President of Rio Algom
Limited and prior to that Chief
Financial Officer of Rio Algom
and Falconbridge Limited. Mr.
Parrett is a chartered
accountant and holds a Bachelor
of Arts in Economics from York
University.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 and Synenco Energy
Inc. Mr. Poole received a
Bachelor of Commerce degree from
Dalhousie University and holds a
Chartered Accountant
designation.
 - 97 -




---



##### 



FinanciallyName
    
    Independent
    
    Literate
    
    Relevant Education and ExperienceKirby L. Hedrick
    
    Yes
    
    Yes
    
    Mr. Hedrick has extensive
engineering and senior
management experience in the
United States and
internationally, retiring in
2000 as Executive
Vice-President, Upstream of
Phillips Petroleum. He
currently serves on the board of
directors of Noble Energy Inc.
and has recently been appointed
to the Wyoming Environmental
Quality Council. Mr. Hedrick
received a Bachelor of Science
and Mechanical Engineering
degree from the University of
Evansville, Indiana in 1975. He
completed the Stanford Executive
Program in 1997 and the Stanford
Corporate Governance Program in
2003.
 Principal Accountant Fees and Services
  2007
    
    2006Audit Fees
    
    
    1,393
    
    
    
    980Audit Related Fees
    
    
    
    
    
    Tax Fees
    
    
    163
    
    
    
    138All Other Fees
    
    
    
    
    
    Total
    
    
    1,556
    
    
    
    1,118
 Audit Fees
  Audit-Related Fees
  Tax Fees
  Pre-approval Policies and Procedures
  - 98 -




---



##### 



de minimis
 CONFLICTS OF INTEREST
   
    
    the issuance of additional Trust Units;
    
    material acquisitions and dispositions of properties;
    
    material capital expenditures;
    
    borrowing; and
    
    the payment of distributable cash.
 Insider Bids, Issuer Bids, Going Private Transactions and Related
Party Transactions.
  LEGAL PROCEEDINGS
  INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
  - 99 -




---



##### 



INTERESTS OF EXPERTS
  AUDITORS, TRANSFER AGENT AND REGISTRAR
  MATERIAL CONTRACTS
  1.
    
    Trust Indenture;2.
    
    Royalty Indenture;3.
    
    Unanimous Shareholders Agreement;4.
    
    Management Agreement;5.
    
    the Fifth Amended and Restated Credit Agreement dated June 17, 2007 between Pengrowth and a
syndicate of eleven financial institutions concerning the Credit Facility;6.
    
    the Bridge Credit Agreement dated January 22, 2007 between Pengrowth and a syndicate of ten
financial institutions entered into in conjunction with the CP Acquisition;7.
    
    the Acquisition Agreement dated November 28, 2006 in connection with the CP Acquisition;8.
    
    the Note Purchase Agreement dated July 26, 2007 concerning the 2007 U.S. Senior Notes;9
    
    the Note Purchase Agreement dated April 23, 2003 concerning the 2003 U.S. Senior Notes;10.
    
    the Note Purchase Agreement dated December 1, 2005 concerning the U.K. Senior Notes;11.
    
    the Debenture Indenture;12.
    
    the first supplemental trust indenture relating to the Debentures dated October 2, 2006; and
 - 100 -




---



##### 



12.
    
    the Distribution Agreement.
  CODE OF ETHICS
 U.S.
Securities Exchange Act of 1934 www.pengrowth.com
   OFF-BALANCE SHEET ARRANGEMENTS
  DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE
    - 101 -




---



##### 



ADDITIONAL INFORMATION
    Investor Relations
    
    Toronto Investor RelationsPengrowth Energy Trust
    
    Scotia Plaza, 40 King Street WestSuite 2100, 222  3rd Avenue S.W.
    
    Suite 3006, Box 106Calgary, Alberta T2P 0B4
    
    Toronto, Ontario M5H 3Y2Telephone: (403) 233-0224
    
    Telephone: (416) 362-1748(888) 744-1111
    
    (888) 744-1111Fax: (866) 341-3586
 www.pengrowth.com  investorrelations@pengrowth.com
 - 102 -




---



##### 



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




---



##### 



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




---



##### 



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

Doug R. Sutton, P.Eng.Vice-President
 - 2 -




---



##### 



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




---



##### 



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




---



##### 



(signed) James S. Kinnear

James S. KinnearChairman, President and Chief Executive OfficerPengrowth Corporation(signed) William G. Christensen

William G. ChristensenVice President, Strategic Planning and Reservoir ExploitationPengrowth Corporation(signed)
Kirby L. Hedrick

Kirby L. Hedrick

DirectorPengrowth Corporation(signed)
D. Michael G. Stewart

D. Michael G. StewartDirectorPengrowth Corporation
 March 19, 2008 - 2 -




---



##### 



APPENDIX C
 Audit Committee Terms of Reference




---



##### 



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




---



##### 



in camera
    Scope, Duties and Responsibilities
 Mandatory Duties
 Review Procedures
  1.
    
    Review and reassess the adequacy of the Audit Committees Terms of Reference at least
annually, submit the Terms of Reference to the Board for approval and have the document
published at least every three years in accordance with the regulations of the United States
Securities and Exchange Commission.
 2.
    
    Prior to filing or public distribution, review, discuss with management and the internal and
external auditors and recommend to the Board for approval, Pengrowths audited annual
financial statements, annual earnings press releases, annual information form, all statements
including the related managements discussion and analysis required in prospectuses and other
offering memoranda, financial statements required by regulatory authorities, all prospectuses
and all documents which may be incorporated by reference into a prospectus, including without
limitation, the annual proxy circular. Approve, on behalf of the Board, Pengrowths interim
financial statements and related managements discussion and analysis and interim earnings
press releases. This review should include discussions with management, the internal
auditors and the external auditors of significant issues regarding accounting principles,
practices and judgements. Discuss any significant changes to Pengrowths accounting
principles and any items required to be communicated by the external auditors in accordance
with Assurance and Related Services Guideline #11 (AUG-11).3.
    
    Ensure that adequate procedures are in place for the review of Pengrowths public disclosure
of financial information extracted or derived from Pengrowths financial statements, other
than the




---



##### 



- 3 - public disclosure referred to in paragraph 2 above and periodically assess the
adequacy of those procedures.4.
    
    Be responsible for reviewing the disclosure contained in Pengrowths annual information form
as required by Form 52-110F1 Audit Committee Information Required in an AIF, attached to MI
52-110. If proxies are solicited for the election or directors of the Corporation, the Audit
Committee shall be responsible for ensuring that Pengrowths information circular includes a
cross-reference to the sections in Pengrowths annual information form that contain the
information required by Form 52-110F1.
 External Auditors
 1.
    
    The Audit Committee shall advise the external auditors of their accountability to the Audit
Committee and the Board as representatives of the unitholders of the Trust to whom the
external auditors are ultimately responsible. The external auditors shall report directly to
the Audit Committee. The Audit Committee is directly responsible for overseeing the work of
the external auditors, shall review at least annually the independence and performance of the
external auditors and shall annually recommend to the Board the appointment of the external
auditors or approve any discharge of auditors when circumstances warrant. The Audit Committee
shall, on an annual basis, obtain and review a report by the external auditor describing: (i)
the external auditors internal quality-control procedures; (ii) any material issues raised by
the most recent internal quality-control review, or peer review, of the external auditors, or
by any inquiry or investigation by governmental or professional authorities, within the
preceding five years, respecting one or more independent audits carried out by the external
auditors, and any steps taken to deal with any such issues; and (iii) all relationships
between the independent auditor and Pengrowth.
  3.
    
    Pre-approve all services to be provided to Pengrowth or its subsidiary entities by
Pengrowths external auditors and all related terms of engagement.
 Other Audit Committee Responsibilities
 4.
    
    Establish procedures for: (i) the receipt, retention and treatment of complaints received by
Pengrowth regarding accounting, internal accounting controls, or auditing matters; and (ii)
the confidential and anonymous submission by employees of Pengrowth of concerns regarding
questionable accounting or auditing matters.
 5.
    
    Review and approve Pengrowths hiring policies regarding partners, employees and former
partners and employees of the present and former external auditors of Pengrowth.
 Discretionary Duties
  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.




---



##### 



- 4 - 
 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.
  Internal Auditors
 1.
    
    Review the annual audit plans of the internal auditors.
 2.
    
    Review the significant findings prepared by the internal auditors and recommendations issued
by any external party relating to internal audit issues, together with managements response.
 3.
    
    Review the adequacy of the resources of the internal auditors to ensure the objectivity and
independence of the internal audit function.
 4.
    
    Consult with management on managements appointment, replacement, reassignment or dismissal
of the internal auditors.
 5.
    
    Ensure that the internal auditors have access to the Lead Director, the Chair of the Board
and the Chief Executive Officer.
 External Auditors
 1.
    
    On an annual basis, the Audit Committee should review and discuss with the external auditors
all significant relationships they have with Pengrowth that could impair the auditors
independence.
 2.
    
    The Audit Committee shall review the external auditors audit plan  discuss scope, staffing,
locations, and reliance upon management and general audit approach.
 3.
    
    Consider the external auditors judgments about the quality and appropriateness of
Pengrowths accounting principles as applied in its financial reporting.
 4.
    
    Be responsible for the resolution of disagreements between management and the external
auditors regarding financial performance.
 5.
    
    Ensure compliance by the external auditors with the requirements set forth in National
Instrument 52-108 Auditor Oversight.
 6.
    
    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.
  Other Audit Committee Responsibilities
 1.
    
    On at least an annual basis, review with Pengrowths counsel any legal matters that could
have a significant impact on the organizations financial statements, Pengrowths compliance
with applicable laws and regulations, and inquiries received from regulators or governmental
agencies.




---



##### 



- 5 - 
 2.
    
    Annually prepare a report to unitholders as required by the United States Securities and
Exchange Commission; the report should be included in Pengrowths annual proxy statement.
 3.
    
    Ensure the preparation and filing of each annual certificate in Form 52-109F1 and each
interim certificate in Form 52-109F2 to be signed by each of the Chief Executive Officer and
Chief Financial Officer of the Corporation in accordance with the requirements set forth under
Multilateral Instrument 52-109 Certification of Disclosure in Issuers Annual and Interim
Filings, as amended from time to time (MI 52-109).
 4.
    
    In respect of annual filings only, the Audit Committee is responsible for ensuring that
management evaluates the effectiveness of Pengrowths disclosure controls and procedures as of
the end of the period covered by the annual filings and has caused Pengrowth to disclose in
the annual managements discussion and analysis its conclusions about the effectiveness of the
disclosure controls and procedures as of the end of the period covered by the annual filings
based on such evaluation. The terms annual filings, interim filings, disclosure controls
and procedures and internal control over financial reporting shall have the meanings set
forth under MI 52-109.
 5.
    
    Be responsible for monitoring any changes in Pengrowths internal control over financial
reporting and for ensuring that any change that occurred during Pengrowths most recent
interim period that has materially affected, or is reasonably likely to materially affect,
Pengrowths internal control over financial reporting is disclosed in Pengrowths most recent
annual or interim managements discussion and analysis.
 6.
    
    Review all exceptions to established policies, procedures and internal controls of Pengrowth,
which have been approved by any two officers of the Corporation.
 7.
    
    Perform any other activities consistent with this Charter, the Trust Indenture, the
Corporations by-laws, and other governing law as the Audit Committee or the Board deems
necessary or appropriate.
 8.
    
    Maintain minutes of meetings and periodically report to the Board on significant results of
the foregoing activities.
 Communication, Authority to Engage Advisors and Expenses




---



##### 



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.
 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




---



##### 



A-2 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




---



##### 



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; and (2) Is not an executive officer of the
specified person.
 B.
    
    Paragraph (e)(1)(ii)(A) of this section only creates a safe
harbor position that a person does not control a specified person. The
existence of the safe harbor does not create a presumption in any way that a
person exceeding the ownership
requirement in paragraph (e)(1)(ii)(A)(1) of this section controls or is
otherwise an affiliate of a specified person.




---



##### 



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.




---



##### 



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




---



##### 



C-2




---



##### 



APPENDIX B
 MANAGEMENTS DISCUSSION AND ANALYSIS




---



##### 








---



##### 



(thousands,
    
    
    Three Months ended December 31
    
    
    Twelve Months ended December 31except per unit amounts)
    
    
    2007
    
    
    2006
    
    % Change
    
    
    2007
    
    
    2006
    
    % ChangeINCOME STATEMENTOil and gas sales
    
    
    $
    425,249
    
    
    
    $
    350,908
    
    
    
    21
    
    
    
    $
    1,722,038
    
    
    
    $
    1,214,093
    
    
    
    42Net income
    
    
    $
    (3,665
    )
    
    
    $
    3,310
    
    
    
    (211
    )
    
    
    $
    359,652
    
    
    
    $
    262,303
    
    
    
    37Net income per trust unit
    
    
    $
    (0.01
    )
    
    
    $
    0.01
    
    
    
    (200
    )
    
    
    $
    1.47
    
    
    
    $
    1.49
    
    
    
    (1
    )CASH FLOWCash flows from
operating activities
    
    
    $
    196,325
    
    
    
    $
    91,237
    
    
    
    115
    
    
    
    $
    800,344
    
    
    
    $
    554,368
    
    
    
    44Cash flows from operating activities
per trust unit
    
    
    $
    0.80
    
    
    
    $
    0.41
    
    
    
    95
    
    
    
    $
    3.26
    
    
    
    $
    3.15
    
    
    
    3Distributions declared
    
    
    $
    166,631
    
    
    
    $
    185,651
    
    
    
    (10
    )
    
    
    $
    706,601
    
    
    
    $
    559,063
    
    
    
    26Distributions declared per trust unit
    
    
    $
    0.675
    
    
    
    $
    0.75
    
    
    
    (10
    )
    
    
    $
    2.875
    
    
    
    $
    3.00
    
    
    
    (4
    )Ratio of distributions declared
over cash flows from
operating activities
    
    
    
    85
    %
    
    
    
    203
    %
    
    
    
    
    
    
    
    88
    %
    
    
    
    101
    %Capital expenditures
    
    
    $
    95,743
    
    
    
    $
    121,781
    
    
    
    (21
    )
    
    
    $
    309,708
    
    
    
    $
    300,809
    
    
    
    3Capital expenditures per trust unit
    
    
    $
    0.39
    
    
    
    $
    0.55
    
    
    
    (29
    )
    
    
    $
    1.26
    
    
    
    $
    1.71
    
    
    
    (26
    )BALANCE SHEETWorking capital(1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (189,603
    )
    
    
    $
    (160,949
    )
    
    
    18Property, plant and equipment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    4,306,682
    
    
    
    $
    3,741,602
    
    
    
    15Long term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    1,203,236
    
    
    
    $
    604,200
    
    
    
    99Trust unitholders equity
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    2,756,220
    
    
    
    $
    3,049,677
    
    
    
    (10
    )Trust unitholders equity
per trust unit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    11.17
    
    
    
    $
    12.50
    
    
    
    (11
    )Currency (U.S.$/Cdn$)
(closing rate at period end)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1.0088
    
    
    
    
    0.8581Weighted average number
of trust units outstanding
    
    
    
    246,513
    
    
    
    
    220,734
    
    
    
    12
    
    
    
    
    245,470
    
    
    
    
    175,871
    
    
    
    40Number of trust units
outstanding at
period end
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    246,846
    
    
    
    
    244,017
    
    
    
    1
 (1)
    
    Prior year restated to conform to presentation adopted in current year




---



##### 



Three Months ended December 31
    
    
    Twelve Months ended December 312007
    
    
    2006
    
    % Change
    
    
    2007
    
    
    2006
    
    % ChangeAVERAGE DAILY PRODUCTIONCrude oil (barrels)
    
    
    
    25,892
    
    
    
    
    25,000
    
    
    
    4
    
    
    
    
    26,327
    
    
    
    
    21,821
    
    
    
    21Heavy oil (barrels)
    
    
    
    7,434
    
    
    
    
    4,695
    
    
    
    58
    
    
    
    
    7,168
    
    
    
    
    4,964
    
    
    
    44Natural gas (mcf)
    
    
    
    250,117
    
    
    
    
    234,050
    
    
    
    7
    
    
    
    
    266,980
    
    
    
    
    175,578
    
    
    
    52Natural gas liquids (barrels)
    
    
    
    9,319
    
    
    
    
    8,910
    
    
    
    5
    
    
    
    
    9,409
    
    
    
    
    6,774
    
    
    
    39Total production (boe)
    
    
    
    84,331
    
    
    
    
    77,614
    
    
    
    9
    
    
    
    
    87,401
    
    
    
    
    62,821
    
    
    
    39TOTAL PRODUCTION (mboe)
    
    
    
    7,758
    
    
    
    
    7,141
    
    
    
    9
    
    
    
    
    31,901
    
    
    
    
    22,930
    
    
    
    39PRODUCTION PROFILECrude oil
    
    
    
    31
    %
    
    
    
    32
    %
    
    
    
    
    
    
    
    30
    %
    
    
    
    35
    %Heavy oil
    
    
    
    9
    %
    
    
    
    6
    %
    
    
    
    
    
    
    
    8
    %
    
    
    
    8
    %Natural gas
    
    
    
    49
    %
    
    
    
    50
    %
    
    
    
    
    
    
    
    51
    %
    
    
    
    46
    %Natural gas liquids
    
    
    
    11
    %
    
    
    
    12
    %
    
    
    
    
    
    
    
    11
    %
    
    
    
    11
    %AVERAGE REALIZED PRICES
(after commodity risk management)Crude oil (per barrel)
    
    
    $
    73.69
    
    
    
    $
    60.35
    
    
    
    22
    
    
    
    $
    71.88
    
    
    
    $
    66.85
    
    
    
    8Heavy oil (per barrel)
    
    
    $
    45.47
    
    
    
    $
    37.61
    
    
    
    21
    
    
    
    $
    44.53
    
    
    
    $
    42.26
    
    
    
    5Natural gas (per mcf)
    
    
    $
    6.90
    
    
    
    $
    7.12
    
    
    
    (3
    )
    
    
    $
    7.29
    
    
    
    $
    7.22
    
    
    
    1Natural gas liquids (per barrel)
    
    
    $
    67.64
    
    
    
    $
    52.69
    
    
    
    28
    
    
    
    $
    58.86
    
    
    
    $
    57.11
    
    
    
    3Average realized price per boe
    
    
    $
    54.58
    
    
    
    $
    49.24
    
    
    
    11
    
    
    
    $
    53.90
    
    
    
    $
    52.88
    
    
    
    2PROVED PLUS 
PROBABLE RESERVESCrude oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    124,188
    
    
    
    
    112,388
    
    
    
    10Heavy oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    21,792
    
    
    
    
    18,336
    
    
    
    19Natural gas (bcf)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    870
    
    
    
    
    827
    
    
    
    5Natural gas liquids (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    28,994
    
    
    
    
    29,142
    
    
    
    (1
    )Total oil equivalent (mboe)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    319,921
    
    
    
    
    297,774
    
    
    
    7SUMMARY OF 
TRUST UNIT TRADINGNYSE  PGH ($U.S.)High
    
    
    $
    19.21
    
    
    
    $
    20.25
    
    
    
    
    
    
    
    $
    19.85
    
    
    
    $
    25.15Low
    
    
    $
    17.30
    
    
    
    $
    14.78
    
    
    
    
    
    
    
    $
    15.82
    
    
    
    $
    14.78Close
    
    
    $
    17.77
    
    
    
    $
    17.21
    
    
    
    
    
    
    
    $
    17.77
    
    
    
    $
    17.21TSX  PGF.UN ($Cdn)(1)High
    
    
    $
    18.68
    
    
    
    $
    22.69
    
    
    
    
    
    
    
    $
    21.04
    
    
    
    $
    26.11Low
    
    
    $
    17.00
    
    
    
    $
    16.81
    
    
    
    
    
    
    
    $
    16.92
    
    
    
    $
    16.81Close
    
    
    $
    17.62
    
    
    
    $
    19.94
    
    
    
    
    
    
    
    $
    17.62
    
    
    
    $
    19.94
 (1)
    
    July 27, 2006, Pengrowths Class A trust units and Class B trust units were
consolidated into a single class of trust units (with the exception of Class A trust units held by
residents of Canada who provided an election), the Class A trust units were delisted from the
Toronto Stock Exchange and the Class B trust units were renamed as Trust units and their trading
symbol changed to PGF.UN




---



##### 








---



##### 








---



##### 








---



##### 




    
    Oil and gas sales increased 42 percent to $1.7 billion dollars in 2007 due to higher
production volumes and higher average realized prices. In the fourth quarter, oil and gas
sales were $425 million, an increase of one percent from the third quarter and 21 percent from
the same quarter in 2006.
 
    
    Production for 2007 averaged 87,401 barrels of oil equivalent (boe) per day, a 39 percent
increase over 2006. The increase is primarily due to a full year of production from the Esprit
and Carson Creek acquisitions, and production from the CP properties after the January 22,
2007 closing. Fourth quarter production averaged 84,331 boe per day, virtually unchanged from
the third quarter and an increase of nine percent from the fourth quarter in 2006. The higher
production levels compared to the prior year reflect the CP properties acquisition and
development activities, partially offset by natural production declines and divestment
activities.
 
    
    Cash flows from operating activities in 2007 increased from the prior year by 44 percent to
$800.3 million reflecting the higher production and sales prices. Fourth quarter cash flows
from operating activities was $196.3 million, representing a decrease of 10 percent from the
third quarter and an increase of 115 percent from the fourth quarter in 2006. The decrease
from the third quarter is mainly as a result of higher operating, royalty, administrative and
interest costs incurred. The 115 percent increase in the fourth quarter of 2007 from the
fourth quarter in 2006 is primarily due to higher production volumes, higher realized prices
and the unfavourable impact on working capital in the prior year.
 
    
    Distributions declared to unitholders reached an all time high of $706.6 million, an increase
of 26 percent when compared to $559.1 million in 2006. For the full year in 2007, distribution
declared totaled $2.875 per trust unit. Distributions declared to unitholders totaled 88
percent of its cash flows from operating activities and 85 percent in the fourth quarter.
 
    
    During 2007, Pengrowth closed a U.S. $400 million offering of notes issued on a private
placement basis at an interest rate of 6.35 percent due in 2017.
 
    
    Net income increased 37 percent to $359.7 million for 2007 compared to 2006. The increase was
due to higher oil and gas sales, partly offset by higher royalties, operating expenses and
general and administrative costs. In addition to the above cash items, net income was
significantly effected by certain non-cash items including a $296.6 million increase in
depletion, depreciation and accretion expenses, and $122.3 million of unrealized commodity
risk management losses, offset by $264.6 million future tax recovery recorded in 2007 due to
the enactment of the previously announced tax on income trusts, asset dispositions during the
second half of 2007 and a reduction in the federal income tax rate.
 
    
    During 2007, Pengrowths average realized price was $53.90 per boe (after commodity risk
management) compared to an average price of $52.88 per boe in 2006. Prices for liquids were
higher year over year while there was a decrease in natural gas prices. For the fourth
quarter, average realized prices were $54.58 per boe (after commodity risk management) up two
percent from the third quarter and 11 percent from the same quarter last year. These increases
largely reflect a higher commodity price environment for oil and natural gas liquids (NGLs)
while natural gas has remained relatively stable in the fourth quarter of 2007.
 
    
    Operating netbacks (after commodity risk management) increased three percent in 2007 to
$30.40 per boe, largely driven by higher realized prices partially offset by higher operating
costs. For the fourth quarter, operating netbacks were $29.56 per boe down from the previous
quarter by nine percent and an increase of 22 percent from the fourth quarter of 2006. The
fourth quarter netbacks were lower than the third quarter largely due to higher operating
costs and royalties.




---



##### 




    
    Pengrowths development capital, excluding acquisitions, in 2007 totaled $283 million,
resulting in a finding and development cost of $17.44 per boe, including future development
costs. Including acquisitions, Pengrowth replaced 169 percent of its production on a proved
plus probable basis at a cost of $18.97 per boe, including future development costs. During
the year, Pengrowth participated in 511 gross (175 net) wells with a 97 percent success rate.
 
    
    Pengrowth completed asset sales for proceeds of $476 million ($459 million net of
adjustments) in 2007. The assets disposed were non-core assets identified following the
acquisitions of the CP properties and Esprit Trust.
     Three months ended
    
    
    
    Twelve months endedDec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Light crude oil (bbls per day)
    
    
    
    25,892
    
    
    
    
    24,903
    
    
    
    25,000
    
    
    
    
    26,327
    
    
    
    
    21,821Heavy oil (bbls per day)
    
    
    
    7,434
    
    
    
    
    7,205
    
    
    
    4,695
    
    
    
    
    7,168
    
    
    
    
    4,964Natural gas (mcf per day)
    
    
    
    250,117
    
    
    
    
    261,976
    
    
    
    234,050
    
    
    
    
    266,980
    
    
    
    
    175,578Natural gas liquids (bbls per day)
    
    
    
    9,319
    
    
    
    
    9,883
    
    
    
    8,910
    
    
    
    
    9,409
    
    
    
    
    6,774Total (boe per day)
    
    
    
    84,331
    
    
    
    
    85,654
    
    
    
    77,614
    
    
    
    
    87,401
    
    
    
    
    62,821




---



##### 



Three months ended
    
    
    
    Twelve months endedDec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Light crude oil (per bbl)
    
    
    
    82.31
    
    
    
    
    76.87
    
    
    
    60.94
    
    
    
    
    72.93
    
    
    
    
    68.83after realized commodity risk management
    
    
    
    73.69
    
    
    
    
    75.10
    
    
    
    60.35
    
    
    
    
    71.88
    
    
    
    
    66.85Heavy oil (per bbl)
    
    
    
    45.47
    
    
    
    
    47.30
    
    
    
    37.61
    
    
    
    
    44.53
    
    
    
    
    42.26Natural gas (per mcf)
    
    
    
    6.20
    
    
    
    
    5.54
    
    
    
    6.82
    
    
    
    
    6.71
    
    
    
    
    7.08after realized commodity risk management
    
    
    
    6.90
    
    
    
    
    6.67
    
    
    
    7.12
    
    
    
    
    7.29
    
    
    
    
    7.22Natural gas liquids (per bbl)
    
    
    
    67.64
    
    
    
    
    61.69
    
    
    
    52.69
    
    
    
    
    58.86
    
    
    
    
    57.11Total per boe
    
    
    
    55.16
    
    
    
    
    50.40
    
    
    
    48.52
    
    
    
    
    52.46
    
    
    
    
    53.18after realized commodity risk management
    
    
    
    54.58
    
    
    
    
    53.34
    
    
    
    49.24
    
    
    
    
    53.90
    
    
    
    
    52.88BENCHMARK PRICESWTI oil (U.S.$  per bbl)
    
    
    
    90.71
    
    
    
    
    75.25
    
    
    
    60.17
    
    
    
    
    72.12
    
    
    
    
    66.25AECO spot gas (Cdn$  per gj)
    
    
    
    5.69
    
    
    
    
    5.32
    
    
    
    6.36
    
    
    
    
    6.27
    
    
    
    
    6.70NYMEX gas (U.S.$  per mmbtu)
    
    
    
    6.97
    
    
    
    
    6.16
    
    
    
    6.56
    
    
    
    
    6.86
    
    
    
    
    7.24Currency (U.S. $/Cdn$)
    
    
    
    1.02
    
    
    
    
    0.96
    
    
    
    0.88
    
    
    
    
    0.93
    
    
    
    
    0.88




---



##### 



MANAGEMENTS DISCUSSION & ANALYSIS
  Three months ended
    
    
    Twelve months endedDec 31, 2007
    
    
    Sept 30, 2007
    
    Dec 31, 2006
    
    
    Dec 31, 2007
    
    
    Dec 31, 2006Light crude oil ($ millions)
    
    
    
    (20.5
    )
    
    
    
    (4.1
    )
    
    
    (1.4
    )
    
    
    
    (10.1
    )
    
    
    
    (15.8
    )Light crude oil ($  per bbl)
    
    
    
    (8.62
    )
    
    
    
    (1.77
    )
    
    
    (0.59
    )
    
    
    
    (1.05
    )
    
    
    
    (1.98
    )Natural gas ($ millions)
    
    
    
    16.0
    
    
    
    
    27.2
    
    
    
    6.5
    
    
    
    
    56.1
    
    
    
    
    8.8Natural gas ($  per mcf)
    
    
    
    0.70
    
    
    
    
    1.13
    
    
    
    0.30
    
    
    
    
    0.58
    
    
    
    
    0.14Combined ($ millions)
    
    
    
    (4.5
    )
    
    
    
    23.1
    
    
    
    5.1
    
    
    
    
    46.0
    
    
    
    
    (7.0
    )Combined ($  per boe)
    
    
    
    (0.58
    )
    
    
    
    2.94
    
    
    
    0.72
    
    
    
    
    1.44
    
    
    
    
    (0.30
    )
    ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec 31,
    
    
    % of
    
    
    
    Sept 30,
    
    
    % of
    
    
    Dec 31,
    
    
    % of
    
    
    
    Dec 31,
    
    
    % of
    
    
    
    Dec 31,
    
    
    % ofSales Revenue
    
    
    2007
    
    
    total
    
    
    
    2007
    
    
    total
    
    
    2006
    
    
    total
    
    
    
    2007
    
    
    total
    
    
    
    2006
    
    
    totalLight crude oil
    
    
    
    175.6
    
    
    
    41
    
    
    
    
    172.0
    
    
    
    41
    
    
    
    138.8
    
    
    
    40
    
    
    
    
    690.8
    
    
    
    40
    
    
    
    
    532.4
    
    
    
    44Natural gas
    
    
    
    158.8
    
    
    
    37
    
    
    
    
    160.8
    
    
    
    38
    
    
    
    153.3
    
    
    
    44
    
    
    
    
    710.1
    
    
    
    41
    
    
    
    
    462.4
    
    
    
    38Natural gas liquids
    
    
    
    57.9
    
    
    
    14
    
    
    
    
    56.1
    
    
    
    13
    
    
    
    43.2
    
    
    
    12
    
    
    
    
    202.1
    
    
    
    12
    
    
    
    
    141.2
    
    
    
    12Heavy oil
    
    
    
    31.1
    
    
    
    8
    
    
    
    
    31.4
    
    
    
    8
    
    
    
    16.3
    
    
    
    4
    
    
    
    
    116.5
    
    
    
    7
    
    
    
    
    76.6
    
    
    
    6Brokered sales/sulphur
    
    
    
    1.8
    
    
    
    
    
    
    
    
    0.4
    
    
    
    
    
    
    
    (0.7
    )
    
    
    
    
    
    
    
    2.5
    
    
    
    
    
    
    
    
    1.5
    
    
    
    Total oil and gas sales
    
    
    
    425.2
    
    
    
    
    
    
    
    
    420.7
    
    
    
    
    
    
    
    350.9
    
    
    
    
    
    
    
    
    1,722.0
    
    
    
    
    
    
    
    
    1,214.1
   ($ millions)
    
    
    Light oil
    
    
    Natural gas
    
    
    NGL
    
    
    Heavy oil
    
    
    Other
    
    
    TotalYear ended December 31, 2006
    
    
    
    532.4
    
    
    
    462.4
    
    
    
    141.2
    
    
    
    76.6
    
    
    
    1.5
    
    
    
    1,214.1Effect of change in product prices
    
    
    
    39.4
    
    
    
    (36.1
    )
    
    
    6.0
    
    
    
    5.9
    
    
    
    
    
    
    
    15.2Effect of change in sales volumes
    
    
    
    113.2
    
    
    
    236.2
    
    
    
    54.9
    
    
    
    34.0
    
    
    
    
    
    
    
    438.3Effect of change in realized
commodity risk management
activities
    
    
    
    5.7
    
    
    
    47.3
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    53.0Other
    
    
    
    0.1
    
    
    
    0.3
    
    
    
    
    
    
    
    
    
    
    
    1.0
    
    
    
    1.4Year ended December 31, 2007
    
    
    
    690.8
    
    
    
    710.1
    
    
    
    202.1
    
    
    
    116.5
    
    
    
    2.5
    
    
    
    1,722.0




---



##### 



Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Processing & other income
    
    
    
    4.1
    
    
    
    
    6.8
    
    
    
    6.2
    
    
    
    
    20.6
    
    
    
    
    18.8$  per boe
    
    
    
    0.53
    
    
    
    
    0.85
    
    
    
    0.86
    
    
    
    
    0.64
    
    
    
    
    0.82
    Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Royalty expense
    
    
    
    85.4
    
    
    
    
    68.3
    
    
    
    73.1
    
    
    
    
    319.3
    
    
    
    
    241.5$  per boe
    
    
    
    11.01
    
    
    
    
    8.67
    
    
    
    10.23
    
    
    
    
    10.01
    
    
    
    
    10.53Royalties as a percent of sales
    
    
    
    20.0
    %
    
    
    
    16.2
    %
    
    
    20.8
    %
    
    
    
    18.5
    %
    
    
    
    19.9
    %
    Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Operating expenses
    
    
    
    103.8
    
    
    
    
    89.6
    
    
    
    99.7
    
    
    
    
    406.5
    
    
    
    
    270.5$  per boe
    
    
    
    13.38
    
    
    
    
    11.38
    
    
    
    13.97
    
    
    
    
    12.74
    
    
    
    
    11.80




---



##### 



MANAGEMENTS DISCUSSION & ANALYSIS
   Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Net operating expenses
    
    
    
    99.7
    
    
    
    
    82.8
    
    
    
    93.5
    
    
    
    
    385.9
    
    
    
    
    251.7$  per boe
    
    
    
    12.85
    
    
    
    
    10.53
    
    
    
    13.11
    
    
    
    
    12.10
    
    
    
    
    10.98
   Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Light oil transportation
    
    
    
    1.2
    
    
    
    
    1.2
    
    
    
    0.5
    
    
    
    
    3.5
    
    
    
    
    2.0$  per bbl
    
    
    
    0.49
    
    
    
    
    0.49
    
    
    
    0.21
    
    
    
    
    0.37
    
    
    
    
    0.25Natural gas transportation
    
    
    
    2.1
    
    
    
    
    2.5
    
    
    
    1.8
    
    
    
    
    9.1
    
    
    
    
    5.6$  per mcf
    
    
    
    0.09
    
    
    
    
    0.10
    
    
    
    0.09
    
    
    
    
    0.09
    
    
    
    
    0.09
   Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Purchased and capitalized
    
    
    
    8.1
    
    
    
    
    7.4
    
    
    
    9.4
    
    
    
    
    26.1
    
    
    
    
    34.6Amortization
    
    
    
    7.5
    
    
    
    
    8.5
    
    
    
    9.3
    
    
    
    
    34.1
    
    
    
    
    34.6




---



##### 



MANAGEMENTS DISCUSSION & ANALYSIS
     Three months ended
    
    
    
    Twelve months endedCombined Netbacks ($ per boe)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Sales price
    
    
    
    54.58
    
    
    
    
    53.34
    
    
    
    49.24
    
    
    
    
    53.90
    
    
    
    
    52.88Other production income
    
    
    
    0.23
    
    
    
    
    0.05
    
    
    
    (0.09
    )
    
    
    
    0.08
    
    
    
    
    0.0654.81
    
    
    
    
    53.39
    
    
    
    49.15
    
    
    
    
    53.98
    
    
    
    
    52.94Processing and other income
    
    
    
    0.53
    
    
    
    
    0.85
    
    
    
    0.86
    
    
    
    
    0.64
    
    
    
    
    0.82Royalties
    
    
    
    (11.01
    )
    
    
    
    (8.67
    )
    
    
    (10.23
    )
    
    
    
    (10.01
    )
    
    
    
    (10.53
    )Operating expenses
    
    
    
    (13.38
    )
    
    
    
    (11.38
    )
    
    
    (13.97
    )
    
    
    
    (12.74
    )
    
    
    
    (11.80
    )Transportation costs
    
    
    
    (0.42
    )
    
    
    
    (0.46
    )
    
    
    (0.33
    )
    
    
    
    (0.40
    )
    
    
    
    (0.33
    )Amortization of injectants
    
    
    
    (0.97
    )
    
    
    
    (1.07
    )
    
    
    (1.31
    )
    
    
    
    (1.07
    )
    
    
    
    (1.51
    )Operating netback
    
    
    
    29.56
    
    
    
    
    32.66
    
    
    
    24.17
    
    
    
    
    30.40
    
    
    
    
    29.59
 Three months ended
    
    
    
    Twelve months endedLight Crude Netbacks ($ per bbl)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Sales price
    
    
    
    73.69
    
    
    
    
    75.10
    
    
    
    60.35
    
    
    
    
    71.88
    
    
    
    
    66.85Other production income
    
    
    
    0.36
    
    
    
    
    0.13
    
    
    
    (0.31
    )
    
    
    
    0.15
    
    
    
    
    0.1374.05
    
    
    
    
    75.23
    
    
    
    60.04
    
    
    
    
    72.03
    
    
    
    
    66.98Processing and other income
    
    
    
    0.33
    
    
    
    
    0.77
    
    
    
    0.64
    
    
    
    
    0.44
    
    
    
    
    0.58Royalties
    
    
    
    (13.86
    )
    
    
    
    (10.65
    )
    
    
    (11.65
    )
    
    
    
    (11.57
    )
    
    
    
    (10.63
    )Operating expenses
    
    
    
    (15.20
    )
    
    
    
    (16.44
    )
    
    
    (17.95
    )
    
    
    
    (14.85
    )
    
    
    
    (13.78
    )Transportation costs
    
    
    
    (0.49
    )
    
    
    
    (0.49
    )
    
    
    (0.21
    )
    
    
    
    (0.37
    )
    
    
    
    (0.25
    )Amortization of injectants
    
    
    
    (3.14
    )
    
    
    
    (3.69
    )
    
    
    (4.08
    )
    
    
    
    (3.54
    )
    
    
    
    (4.35
    )Operating netback
    
    
    
    41.69
    
    
    
    
    44.73
    
    
    
    26.79
    
    
    
    
    42.14
    
    
    
    
    38.55




---



##### 



MANAGEMENTS DISCUSSION & ANALYSIS
 Three months ended
    
    
    
    Twelve months endedHeavy Oil Netbacks ($ per bbl)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Sales price
    
    
    
    45.47
    
    
    
    
    47.30
    
    
    
    37.61
    
    
    
    
    44.53
    
    
    
    
    42.26Processing and other income
    
    
    
    0.19
    
    
    
    
    0.50
    
    
    
    0.80
    
    
    
    
    0.27
    
    
    
    
    0.43Royalties
    
    
    
    (5.91
    )
    
    
    
    (6.90
    )
    
    
    (5.44
    )
    
    
    
    (5.86
    )
    
    
    
    (4.53
    )Operating expenses
    
    
    
    (12.92
    )
    
    
    
    (9.43
    )
    
    
    (14.06
    )
    
    
    
    (12.71
    )
    
    
    
    (15.16
    )Operating netback
    
    
    
    26.83
    
    
    
    
    31.47
    
    
    
    18.91
    
    
    
    
    26.23
    
    
    
    
    23.00
 Three months ended
    
    
    
    Twelve months endedNatural Gas Netbacks ($ per mcf)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Sales price
    
    
    
    6.90
    
    
    
    
    6.67
    
    
    
    7.12
    
    
    
    
    7.29
    
    
    
    
    7.22Other production income
    
    
    
    0.04
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.01
    
    
    
    
    0.016.94
    
    
    
    
    6.67
    
    
    
    7.12
    
    
    
    
    7.30
    
    
    
    
    7.23Processing and other income
    
    
    
    0.14
    
    
    
    
    0.19
    
    
    
    0.20
    
    
    
    
    0.16
    
    
    
    
    0.21Royalties
    
    
    
    (1.22
    )
    
    
    
    (0.92
    )
    
    
    (1.41
    )
    
    
    
    (1.33
    )
    
    
    
    (1.54
    )Operating expenses
    
    
    
    (2.02
    )
    
    
    
    (1.48
    )
    
    
    (1.90
    )
    
    
    
    (1.92
    )
    
    
    
    (1.65
    )Transportation costs
    
    
    
    (0.09
    )
    
    
    
    (0.10
    )
    
    
    (0.09
    )
    
    
    
    (0.09
    )
    
    
    
    (0.09
    )Operating netback
    
    
    
    3.75
    
    
    
    
    4.36
    
    
    
    3.92
    
    
    
    
    4.12
    
    
    
    
    4.16
 Three months ended
    
    
    
    Twelve months endedNGLs Netbacks ($ per bbl)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Sales price
    
    
    
    67.64
    
    
    
    
    61.69
    
    
    
    52.69
    
    
    
    
    58.86
    
    
    
    
    57.11Royalties
    
    
    
    (23.61
    )
    
    
    
    (18.82
    )
    
    
    (16.61
    )
    
    
    
    (18.49
    )
    
    
    
    (20.17
    )Operating expenses
    
    
    
    (14.29
    )
    
    
    
    (10.96
    )
    
    
    (14.00
    )
    
    
    
    (12.65
    )
    
    
    
    (11.12
    )Operating netback
    
    
    
    29.74
    
    
    
    
    31.91
    
    
    
    22.08
    
    
    
    
    27.72
    
    
    
    
    25.82
  Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Interest Expense
    
    
    
    19.7
    
    
    
    
    19.6
    
    
    
    12.8
    
    
    
    
    84.3
    
    
    
    
    32.1




---



##### 



MANAGEMENTS DISCUSSION & ANALYSIS
  Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Cash G&A expense
    
    
    
    12.4
    
    
    
    
    8.3
    
    
    
    11.7
    
    
    
    
    50.5
    
    
    
    
    34.1$  per boe
    
    
    
    1.60
    
    
    
    
    1.05
    
    
    
    1.63
    
    
    
    
    1.58
    
    
    
    
    1.49Non-cash G&A expense
    
    
    
    1.8
    
    
    
    
    0.4
    
    
    
    (0.3
    )
    
    
    
    5.4
    
    
    
    
    2.5$  per boe
    
    
    
    0.22
    
    
    
    
    0.05
    
    
    
    (0.04
    )
    
    
    
    0.17
    
    
    
    
    0.11Total G&A
    
    
    
    14.2
    
    
    
    
    8.7
    
    
    
    11.4
    
    
    
    
    55.9
    
    
    
    
    36.6Total G&A ($  per boe)
    
    
    
    1.82
    
    
    
    
    1.10
    
    
    
    1.59
    
    
    
    
    1.75
    
    
    
    
    1.60
     Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Management Fee
    
    
    
    (2.2
    )
    
    
    
    2.8
    
    
    
    (0.7
    )
    
    
    
    6.8
    
    
    
    
    9.9$  per boe
    
    
    
    (0.28
    )
    
    
    
    0.36
    
    
    
    (0.09
    )
    
    
    
    0.21
    
    
    
    
    0.43




---



##### 



Bill C-52 Budget Implementation Act 2007




---



##### 



Future Income Taxes




---



##### 



Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Depletion and depreciation
    
    
    
    156.0
    
    
    
    
    157.5
    
    
    
    129.2
    
    
    
    
    639.1
    
    
    
    
    351.6$  per boe
    
    
    
    20.11
    
    
    
    
    19.99
    
    
    
    18.09
    
    
    
    
    20.03
    
    
    
    
    15.33Accretion
    
    
    
    6.5
    
    
    
    
    6.2
    
    
    
    4.9
    
    
    
    
    25.7
    
    
    
    
    16.6$  per boe
    
    
    
    0.84
    
    
    
    
    0.79
    
    
    
    0.68
    
    
    
    
    0.81
    
    
    
    
    0.72




---



##### 



Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Geological and geophysical
    
    
    
    5.0
    
    
    
    
    1.8
    
    
    
    6.1
    
    
    
    
    12.6
    
    
    
    
    8.9Drilling and completions
    
    
    
    62.1
    
    
    
    
    39.1
    
    
    
    83.6
    
    
    
    
    215.4
    
    
    
    
    217.1Plant and facilities
    
    
    
    19.0
    
    
    
    
    10.7
    
    
    
    26.6
    
    
    
    
    41.9
    
    
    
    
    56.9Land purchases
    
    
    
    2.7
    
    
    
    
    1.4
    
    
    
    5.5
    
    
    
    
    13.2
    
    
    
    
    17.9Development capital
    
    
    
    88.8
    
    
    
    
    53.0
    
    
    
    121.8
    
    
    
    
    283.1
    
    
    
    
    300.8Other capital
    
    
    
    6.9
    
    
    
    
    12.7
    
    
    
    1.0
    
    
    
    
    26.6
    
    
    
    
    2.6Total capital expenditures
    
    
    
    95.7
    
    
    
    
    65.7
    
    
    
    122.8
    
    
    
    
    309.7
    
    
    
    
    303.4Business acquisitions
    
    
    
    (0.6
    )
    
    
    
    0.4
    
    
    
    900.7
    
    
    
    
    923.1
    
    
    
    
    1,396.4Property acquisitions
    
    
    
    9.0
    
    
    
    
    
    
    
    
    0.5
    
    
    
    
    9.0
    
    
    
    
    50.3Proceeds on
property dispositions
    
    
    
    (23.7
    )
    
    
    
    (163.1
    )
    
    
    0.5
    
    
    
    
    (458.8
    )
    
    
    
    (15.2
    )Net capital expenditures and
acquisitions
    
    
    
    80.4
    
    
    
    
    (97.0
    )
    
    
    1,024.5
    
    
    
    
    783.0
    
    
    
    
    1,734.9




---



##### 








---



##### 



($ thousands)
    
    
    2007
    
    
    
    2006Term credit facilities
    
    
    
    513,998
    
    
    
    
    257,000Senior unsecured notes
    
    
    
    689,238
    
    
    
    
    347,200Working capital deficit excluding bank
indebtedness (cash and term deposits)(1)
    
    
    
    191,620
    
    
    
    
    151,575Bank indebtedness (cash and term deposits)
    
    
    
    (2,017
    )
    
    
    
    9,374Net debt excluding convertible debentures
    
    
    
    1,392,839
    
    
    
    
    765,149Convertible debentures
    
    
    
    75,030
    
    
    
    
    75,127Net debt including convertible debentures
    
    
    
    1,467,869
    
    
    
    
    840,276Trust unitholders equity
    
    
    
    2,756,220
    
    
    
    
    3,049,677Net debt excluding convertible debentures as a percentage of total book capitalization
    
    
    
    33.6
    %
    
    
    
    20.1
    %Net debt including convertible debentures as a percentage of total book capitalization
    
    
    
    34.8
    %
    
    
    
    21.6
    %Cash flow from operating activities
    
    
    
    800,344
    
    
    
    
    554,368Net debt excluding convertible debentures to cash flow from operating activities
    
    
    
    1.7
    
    
    
    
    1.4Net debt including convertible debentures to cash flow from operating activities
    
    
    
    1.8
    
    
    
    
    1.5
 (1)
    
    Prior year restated to conform to presentation adopted in current year




---



##### 



1.
    
    Total senior debt should not be greater than three times Earnings Before Income Taxes
Depreciation and Amortization (EBITDA) for the last four fiscal quarters2.
    
    Total debt should not be greater than 3.5 times EBITDA for the last four fiscal quarters3.
    
    Total senior debt should be less than 50 percent of total book capitalization4.
    
    EBITDA should not be less than four times interest expense




---



##### 



Three months ended
    
    
    
    Twelve months ended($ thousands, except per trust unit amounts
    
    
    Dec 31, 2007
    
    
    
    Sept 30, 2007
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2007
    
    
    
    Dec 31, 2006Cash flows from operating activities
    
    
    
    196,325
    
    
    
    
    217,630
    
    
    
    91,237
    
    
    
    
    800,344
    
    
    
    
    554,368Net income (loss)
    
    
    
    (3,665
    )
    
    
    
    161,492
    
    
    
    3,310
    
    
    
    
    359,652
    
    
    
    
    262,303Distributions declared
    
    
    
    166,631
    
    
    
    
    172,109
    
    
    
    185,651
    
    
    
    
    706,601
    
    
    
    
    559,063Distributions declared per trust unit
    
    
    
    0.675
    
    
    
    
    0.70
    
    
    
    0.75
    
    
    
    
    2.875
    
    
    
    
    3.00Excess (shortfall) of cash flows from
operating
activities over distributions declared
    
    
    
    29,694
    
    
    
    
    45,521
    
    
    
    (94,414
    )
    
    
    
    93,743
    
    
    
    
    (4,695
    )Per trust unit
    
    
    
    0.12
    
    
    
    
    0.19
    
    
    
    (0.43
    )
    
    
    
    0.38
    
    
    
    
    (0.03
    )Shortfall of net income over
distributions declared
    
    
    
    (170,296
    )
    
    
    
    (10,617
    )
    
    
    (182,341
    )
    
    
    
    (346,949
    )
    
    
    
    (296,760
    )Per trust unit
    
    
    
    (0.69
    )
    
    
    
    (0.04
    )
    
    
    (0.83
    )
    
    
    
    (1.41
    )
    
    
    
    (1.69
    )Ratio of distributions declared
over cash flows from operating activities
    
    
    
    85
    %
    
    
    
    79
    %
    
    
    203
    %
    
    
    
    88
    %
    
    
    
    101
    %




---



##### 



($ thousands)
    
    
    2008
    
    
    2009
    
    
    2010
    
    
    2011
    
    
    2012
    
    
    Thereafter
    
    
    TotalLong term debt (1)
    
    
    
    
    
    
    
    
    
    
    
    662,693
    
    
    
    
    
    
    
    
    
    
    
    546,574
    
    
    
    1,209,267Interest payments on long term debt (2)
    
    
    
    40,801
    
    
    
    40,801
    
    
    
    33,407
    
    
    
    33,407
    
    
    
    33,407
    
    
    
    130,760
    
    
    
    312,583Convertible debentures (3)
    
    
    
    
    
    
    
    
    
    
    
    74,700
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    74,700Interest payments on
convertible debentures (4)
    
    
    
    4,810
    
    
    
    4,810
    
    
    
    4,810
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    14,430Other (5)
    
    
    
    9,015
    
    
    
    9,232
    
    
    
    8,652
    
    
    
    8,221
    
    
    
    8,139
    
    
    
    42,028
    
    
    
    85,28754,626
    
    
    
    54,843
    
    
    
    784,262
    
    
    
    41,628
    
    
    
    41,546
    
    
    
    719,362
    
    
    
    1,696,267Purchase obligationsPipeline transportation
    
    
    
    43,595
    
    
    
    36,254
    
    
    
    19,603
    
    
    
    17,528
    
    
    
    15,796
    
    
    
    41,339
    
    
    
    174,115CO2 purchases (6)
    
    
    
    7,357
    
    
    
    3,586
    
    
    
    3,616
    
    
    
    3,196
    
    
    
    2,890
    
    
    
    9,784
    
    
    
    30,42950,952
    
    
    
    39,840
    
    
    
    23,219
    
    
    
    20,724
    
    
    
    18,686
    
    
    
    51,123
    
    
    
    204,544Remediation trust fund payments
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    11,500
    
    
    
    12,750105,828
    
    
    
    94,933
    
    
    
    807,731
    
    
    
    62,602
    
    
    
    60,482
    
    
    
    781,985
    
    
    
    1,913,561
 (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 foreign denominated fixed rate
debt using the year-end exchange rate(3)
    
    Includes repayment of convertible debentures on maturity (see Note 8 of the
financial statements), and assumes no conversion of convertible debentures to trust units(4)
    
    Includes annual interest on convertible debentures outstanding at year-end and
assumes no conversion of convertible debentures prior to maturity(5)
    
    Includes office rent and vehicle leases(6)
    
    For the Weyburn CO2 project, prices are denominated in U.S. dollars and have been
translated at the year-end exchange rate. For the Judy Creek CO2 pilot project, prices are
denominated in Canadian dollars




---



##### 



High
    
    
    Low
    
    
    Close
    
    
    Volume
    
    
    Value(000s)
    
    
    ($ millions)TSX  PGF.UN ($
Cdn)2007 1st quarter
    
    
    
    20.85
    
    
    
    18.62
    
    
    
    19.45
    
    
    
    37,742
    
    
    
    744.82nd quarter
    
    
    
    21.04
    
    
    
    18.82
    
    
    
    20.27
    
    
    
    28,348
    
    
    
    561.53rd quarter
    
    
    
    20.70
    
    
    
    16.92
    
    
    
    18.64
    
    
    
    27,970
    
    
    
    524.54th quarter
    
    
    
    18.68
    
    
    
    17.00
    
    
    
    17.62
    
    
    
    23,559
    
    
    
    423.1Year
    
    
    
    21.04
    
    
    
    16.92
    
    
    
    17.62
    
    
    
    117,619
    
    
    
    2,253.92006 1st quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2nd quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3rd quarter *
    
    
    
    26.11
    
    
    
    21.02
    
    
    
    21.94
    
    
    
    29,262
    
    
    
    708.04th quarter
    
    
    
    22.69
    
    
    
    16.81
    
    
    
    19.94
    
    
    
    75,576
    
    
    
    1,505.0Year
    
    
    
    26.11
    
    
    
    16.81
    
    
    
    19.94
    
    
    
    104,838
    
    
    
    2,213.0NYSE  PGH ($ U.S.)2007 1st quarter
    
    
    
    17.96
    
    
    
    15.82
    
    
    
    16.87
    
    
    
    26,633
    
    
    
    449.12nd quarter
    
    
    
    19.84
    
    
    
    16.45
    
    
    
    19.09
    
    
    
    23,668
    
    
    
    428.63rd quarter
    
    
    
    19.85
    
    
    
    16.25
    
    
    
    18.84
    
    
    
    19,284
    
    
    
    346.94th quarter
    
    
    
    19.21
    
    
    
    17.30
    
    
    
    17.77
    
    
    
    13,980
    
    
    
    256.4Year
    
    
    
    19.85
    
    
    
    15.82
    
    
    
    17.77
    
    
    
    83,565
    
    
    
    1,481.02006 1st quarter
    
    
    
    25.15
    
    
    
    21.50
    
    
    
    23.10
    
    
    
    13,421
    
    
    
    316.22nd quarter
    
    
    
    25.00
    
    
    
    21.85
    
    
    
    24.09
    
    
    
    14,277
    
    
    
    337.03rd quarter
    
    
    
    24.95
    
    
    
    18.90
    
    
    
    19.62
    
    
    
    27,359
    
    
    
    604.04th quarter
    
    
    
    20.25
    
    
    
    14.78
    
    
    
    17.21
    
    
    
    55,108
    
    
    
    955.6Year
    
    
    
    25.15
    
    
    
    14.78
    
    
    
    17.21
    
    
    
    110,165
    
    
    
    2,212.8TSX  PGF.A ($ Cdn)2007 1st quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2nd quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3rd quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4th quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2006 1st quarter
    
    
    
    28.96
    
    
    
    24.96
    
    
    
    26.88
    
    
    
    1,244
    
    
    
    33.82nd quarter
    
    
    
    28.50
    
    
    
    24.20
    
    
    
    26.70
    
    
    
    1,810
    
    
    
    47.63rd quarter *
    
    
    
    28.25
    
    
    
    24.95
    
    
    
    25.30
    
    
    
    4,297
    
    
    
    110.64th quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Year
    
    
    
    28.96
    
    
    
    24.20
    
    
    
    25.30
    
    
    
    7,351
    
    
    
    192.0TSX  PGF.B ($ Cdn)2007 1st quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2nd quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3rd quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4th quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2006 1st quarter
    
    
    
    24.50
    
    
    
    20.71
    
    
    
    23.32
    
    
    
    18,338
    
    
    
    420.12nd quarter
    
    
    
    26.05
    
    
    
    22.41
    
    
    
    26.05
    
    
    
    18,982
    
    
    
    459.63rd quarter *
    
    
    
    27.25
    
    
    
    24.84
    
    
    
    25.31
    
    
    
    14,226
    
    
    
    364.04th quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Year
    
    
    
    27.25
    
    
    
    20.71
    
    
    
    25.31
    
    
    
    51,546
    
    
    
    1,243.7
 *
    
    On July 27, 2006, Pengrowths Class A trust units and Class B trust units were consolidated
into a single class of trust units pursuant to which the Class A trust units were delisted
from the Toronto Stock Exchange, Class A trust units were converted into Class B trust units
(with the exception of Class A trust units held by residents of Canada who elected to retain
their Class A trust units) and the Class B trust units were renamed as trust units and their
trading symbol changed to PGF.UN




---



##### 



2007
    
    
    Q1
    
    
    Q2
    
    
    Q3
    
    
    Q4Oil and gas sales ($000s)
    
    
    
    432,108
    
    
    
    443,977
    
    
    
    420,704
    
    
    
    425,249Net income/(loss) ($000s)
    
    
    
    (69,834
    )
    
    
    271,659
    
    
    
    161,492
    
    
    
    (3,665
    )Net income/(loss) per trust unit ($)
    
    
    
    (0.29
    )
    
    
    1.11
    
    
    
    0.66
    
    
    
    (0.01
    )Net income/(loss) per trust unit  diluted ($)
    
    
    
    (0.29
    )
    
    
    1.10
    
    
    
    0.66
    
    
    
    (0.01
    )Cash flow from operating activities ($000s)
    
    
    
    136,429
    
    
    
    249,960
    
    
    
    217,630
    
    
    
    196,325Distributions declared ($000s)
    
    
    
    183,534
    
    
    
    184,327
    
    
    
    172,109
    
    
    
    166,631Distributions declared per trust unit ($)
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.70
    
    
    
    0.675Daily production (boe)
    
    
    
    90,068
    
    
    
    89,633
    
    
    
    85,654
    
    
    
    84,331Total production (mboe)
    
    
    
    8,106
    
    
    
    8,157
    
    
    
    7,880
    
    
    
    7,758Average realized price ($  per boe)
    
    
    
    53.30
    
    
    
    54.39
    
    
    
    53.34
    
    
    
    54.58Operating netback ($  per boe)
    
    
    
    29.87
    
    
    
    29.56
    
    
    
    32.66
    
    
    
    29.56
 2006
    
    
    Q1
    
    
    Q2
    
    
    Q3
    
    
    Q4Oil and gas sales ($000s)
    
    
    
    291,896
    
    
    
    283,532
    
    
    
    287,757
    
    
    
    350,908Net income ($000s)
    
    
    
    66,335
    
    
    
    110,116
    
    
    
    82,542
    
    
    
    3,310Net income per trust unit ($)
    
    
    
    0.41
    
    
    
    0.69
    
    
    
    0.51
    
    
    
    0.01Net income per trust unit  diluted ($)
    
    
    
    0.41
    
    
    
    0.68
    
    
    
    0.51
    
    
    
    0.01Cash flow from operating activities ($000s)
    
    
    
    156,360
    
    
    
    126,800
    
    
    
    179,971
    
    
    
    91,237Distributions declared ($000s)
    
    
    
    120,302
    
    
    
    120,597
    
    
    
    132,513
    
    
    
    185,651Distributions declared per trust unit ($)
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.75Daily production (boe)
    
    
    
    58,845
    
    
    
    56,325
    
    
    
    58,344
    
    
    
    77,614Total production (mboe)
    
    
    
    5,296
    
    
    
    5,126
    
    
    
    5,368
    
    
    
    7,141Average realized price ($  per boe)
    
    
    
    55.04
    
    
    
    54.91
    
    
    
    53.67
    
    
    
    49.24Operating netback ($  per boe)
    
    
    
    31.44
    
    
    
    33.94
    
    
    
    30.82
    
    
    
    24.17




---



##### 



Twelve months ended December 31($ thousands)
    
    
    2007
    
    
    
    2006
    
    
    2005Oil and gas sales
    
    
    
    1,722,038
    
    
    
    
    1,214,093
    
    
    
    1,151,510Net income
    
    
    
    359,652
    
    
    
    
    262,303
    
    
    
    326,326Net income per trust unit ($)
    
    
    
    1.47
    
    
    
    
    1.49
    
    
    
    2.08Net income per trust unit  diluted ($)
    
    
    
    1.46
    
    
    
    
    1.49
    
    
    
    2.07Distributions declared per trust unit ($)
    
    
    
    2.875
    
    
    
    
    3.00
    
    
    
    2.82Total assets (1)
    
    
    
    5,234,251
    
    
    
    
    4,690,129
    
    
    
    2,391,432Long term debt (2)
    
    
    
    1,278,266
    
    
    
    
    679,327
    
    
    
    368,089Trust unitholders equity
    
    
    
    2,756,220
    
    
    
    
    3,049,677
    
    
    
    1,475,996Number of trust units outstanding at
year-end (thousands)
    
    
    
    246,846
    
    
    
    
    244,017
    
    
    
    159,864
 (1)
    
    Prior years restated to conform to presentation adopted in the current year(2)
    
    Includes long term debt and convertible debentures
   
    
    The prices of Pengrowths products (crude oil, natural gas, and NGLs) fluctuate due to many
factors including local and global market supply and demand, weather patterns, pipeline
transportation and political stability;
    
    The marketability of our production depends in part upon the availability, proximity and
capacity of gathering systems, pipelines and processing facilities. Operational or economic
factors may result in the inability to deliver our products to market;
    
    Geological and operational risks affect the quantity and quality of reserves and the costs of
recovering those reserves. Our actual results will vary from our reserve estimates and those
variations could be material;
    
    Government royalties, income taxes, commodity taxes and other taxes, levies and fees have a
significant economic impact on Pengrowths financial results. Changes to federal and
provincial legislation including implementation of the October 31 Proposals governing such
royalties, taxes and fees could have a material impact on Pengrowths financial results and
the value of Pengrowth trust units;




---



##### 




    
    Changes to the royalty regime in Alberta were announced on October 25, 2007. The full details
required to accurately assess the impact are not known at this time but will reduce future
cash flows and reserve valuations;
    
    Oil and gas operations carry the risk of damaging the local environment in the event of
equipment or operational failure. The cost to remediate any environmental damage could be
significant;
    
    Environmental laws and regulatory initiatives impact Pengrowth financially and operationally.
We may incur substantial capital and operating expenses to comply with increasingly complex
laws and regulations covering the protection of the environment and human health and safety.
In particular, we may be required to incur significant costs to comply with future regulations
to reduce greenhouse gas and other emissions;
    
    Pengrowths oil and gas reserves will be depleted over time and our level of cash flow from
operations and the value of our trust units could be reduced if reserves and production are
not replaced. The ability to replace production depends on Pengrowths success in developing
existing reserves, acquiring new reserves and financing this development and acquisition activity within the
context of the capital markets. Additional uncertainty with new legislation may limit access to
capital or increase the cost of raising capital;
    
    Increased competition for properties will drive the cost of acquisitions up and expected
returns from the properties down;
    
    A significant portion of our properties are operated by third parties. If these operators
fail to perform their duties properly, or become insolvent, we may experience interruptions in
production and revenues from these properties or incur additional liabilities and expenses as
a result of the default of these third party operators;
    
    Increased activity within the oil and gas sector has increased the cost of goods and services
and makes it more difficult to hire and retain professional staff;
    
    Changing interest rates influence borrowing costs and the availability of capital;
    
    Failing a financial covenant may result in one or more of Pengrowths loans being in default.
In certain circumstances, being in default of one loan may result in other loans to also be in
default;
    
    Investors interest in the oil and gas sector may change over time which would affect the
availability of capital and the value of Pengrowth trust units;
    
    Inflation may result in escalating costs which could impact unitholder distributions and the
value of Pengrowth trust units;
    
    Continued uncertainty in the credit markets may restrict the availability or increase the
cost of borrowing required for future development and acquisitions;
    
    Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and
capital costs; and
    
    The value of Pengrowth trust units is impacted directly by the related tax treatment of the
trust units and the trust unit distributions, and indirectly by the tax treatment of
alternative equity investments. Changes in Canadian or U.S. tax legislation could adversely
affect the value of our trust units.




---



##### 








---



##### 








---



##### 








---



##### 



APPENDIX C
 CONSOLIDATED FINANCIAL STATEMENTS OF PENGROWTH ENERGY TRUST INCLUDING MANAGEMENTS REPORT TO
UNITHOLDERS, THE AUDITORS REPORTS AND NOTE 23 THEREOF WHICH INCLUDES A RECONCILIATION OF THE
CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES




---



##### 



-s- JAMES S KINNEAR
    
    -s- CHRISTOPHER G WEBSTERJames S. Kinnear
    
    Christopher G. WebsterChairman, President and
    
    Chief Financial OfficerChief Executive Officer




---



##### 



(CHARTERED ACCOUNTANTS)Chartered AccountantsCalgary, CanadaMarch 3, 2008




---



##### 



(CHARTERED ACCOUNTANTS)Chartered AccountantsCalgary, CanadaMarch 3, 2008




---



##### 



CONSOLIDATED BALANCE SHEETS
 As at December 31
    
    
    2007
    
    
    
    2006ASSETSCurrent assetsCash and term deposits
    
    
    $
    2,017
    
    
    
    $
    Accounts receivable
    
    
    
    206,583
    
    
    
    
    171,876Due from Pengrowth Management Limited
    
    
    
    731
    
    
    
    
    Fair value of risk management contracts (Note 19)
    
    
    
    8,034
    
    
    
    
    37,972Future income taxes (Note 11)
    
    
    
    18,751
    
    
    
    
    236,116
    
    
    
    
    209,848Fair value of risk management contracts(Note 19)
    
    
    
    6,024
    
    
    
    
    495Deposit on acquisition
    
    
    
    
    
    
    
    
    103,750Other assets(Note 5)
    
    
    
    24,831
    
    
    
    
    36,132Property, plant and equipment(Note 6)
    
    
    
    4,306,682
    
    
    
    
    3,741,602Goodwill(Note 4)
    
    
    
    660,598
    
    
    
    
    598,302TOTAL ASSETS
    
    
    $
    5,234,251
    
    
    
    $
    4,690,129LIABILITIES AND UNITHOLDERS EQUITYCurrent liabilitiesBank indebtedness
    
    
    $
    
    
    
    
    $
    9,374Accounts payable and accrued liabilities
    
    
    
    239,091
    
    
    
    
    221,213Distributions payable to unitholders
    
    
    
    111,119
    
    
    
    
    122,080Due to Pengrowth Management Limited
    
    
    
    
    
    
    
    
    2,101Fair value of risk management contracts (Note 19)
    
    
    
    70,846
    
    
    
    
    Future income taxes (Note 11)
    
    
    
    
    
    
    
    
    11,012Contract liabilities (Note 7)
    
    
    
    4,663
    
    
    
    
    5,017425,719
    
    
    
    
    370,797Fair value of risk management contracts(Note 19)
    
    
    
    22,613
    
    
    
    
    1,367Contract liabilities(Note 7)
    
    
    
    12,162
    
    
    
    
    16,825Convertible debentures(Note 8)
    
    
    
    75,030
    
    
    
    
    75,127Long term debt(Note 9)
    
    
    
    1,203,236
    
    
    
    
    604,200Asset retirement obligations(Note 10)
    
    
    
    352,171
    
    
    
    
    255,331Future income taxes(Note 11)
    
    
    
    387,100
    
    
    
    
    316,805Trust unitholders equity(Note 12)Trust Unitholders capital
    
    
    
    4,432,737
    
    
    
    
    4,383,993Equity portion of convertible debentures
    
    
    
    160
    
    
    
    
    160Contributed surplus
    
    
    
    9,679
    
    
    
    
    4,931Deficit (Note 14)
    
    
    
    (1,686,356
    )
    
    
    
    (1,339,407
    )2,756,220
    
    
    
    
    3,049,677Commitments(Note 20)Contingencies(Note 21)Subsequent Events(Note 22)TOTAL LIABILITIES AND UNITHOLDERS EQUITY
    
    
    $
    5,234,251
    
    
    
    $
    4,690,129
   -s- ILLEGIBLE
    
    -s- ILLEGIBLEDirector
    
    Director




---



##### 



CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
 Years ended December 31
    
    
    2007
    
    
    
    2006REVENUESOil and gas sales
    
    
    $
    1,722,038
    
    
    
    $
    1,214,093Unrealized (loss) gain on commodity risk management (Note 19)
    
    
    
    (122,307
    )
    
    
    
    26,499Processing and other income
    
    
    
    20,573
    
    
    
    
    18,768Royalties, net of incentives
    
    
    
    (319,319
    )
    
    
    
    (241,494
    )Net revenue
    
    
    
    1,300,985
    
    
    
    
    1,017,866EXPENSESOperating
    
    
    
    406,522
    
    
    
    
    270,519Transportation
    
    
    
    12,672
    
    
    
    
    7,621Amortization of injectants for miscible floods
    
    
    
    34,063
    
    
    
    
    34,644Interest on bank indebtedness
    
    
    
    13,876
    
    
    
    
    Interest on long term debt
    
    
    
    70,416
    
    
    
    
    32,109General and administrative
    
    
    
    55,903
    
    
    
    
    36,613Management fee
    
    
    
    6,807
    
    
    
    
    9,941Foreign exchange (gain) loss (Note 15)
    
    
    
    (61,857
    )
    
    
    
    22Depletion, depreciation and amortization
    
    
    
    639,084
    
    
    
    
    351,575Accretion (Note 10)
    
    
    
    25,722
    
    
    
    
    16,591Other expenses
    
    
    
    2,737
    
    
    
    
    10,1971,205,945
    
    
    
    
    769,832Income before taxes
    
    
    
    95,040
    
    
    
    
    248,034Future income tax reduction (Note 11)
    
    
    
    (264,612
    )
    
    
    
    (14,269
    )NET INCOME
    
    
    $
    359,652
    
    
    
    $
    262,303Deficit, beginning of year
    
    
    
    (1,339,407
    )
    
    
    
    (1,042,647
    )Distributions declared
    
    
    
    (706,601
    )
    
    
    
    (559,063
    )DEFICIT, END OF YEAR
    
    
    $
    (1,686,356
    )
    
    
    $
    (1,339,407
    )Net income per trust unit (Note 18)Basic
    
    
    $
    1.47
    
    
    
    $
    1.49Diluted
    
    
    $
    1.46
    
    
    
    $
    1.49




---



##### 



CONSOLIDATED STATEMENTS OF CASH FLOWS
 Years ended December 31
    
    
    2007
    
    
    
    2006CASH PROVIDED BY (USED FOR):OPERATINGNet income
    
    
    $
    359,652
    
    
    
    $
    262,303Depletion, depreciation and accretion
    
    
    
    664,806
    
    
    
    
    368,166Future income tax reduction (Note 11)
    
    
    
    (264,612
    )
    
    
    
    (14,269
    )Contract liability amortization (Note 7)
    
    
    
    (5,017
    )
    
    
    
    (5,447
    )Amortization of injectants
    
    
    
    34,063
    
    
    
    
    34,644Purchase of injectants
    
    
    
    (26,052
    )
    
    
    
    (34,630
    )Expenditures on remediation
    
    
    
    (11,428
    )
    
    
    
    (9,093
    )Unrealized foreign exchange (gain) loss (Note 15)
    
    
    
    (73,940
    )
    
    
    
    480Unrealized loss (gain) on risk management contracts (Note 19)
    
    
    
    130,374
    
    
    
    
    (26,499
    )Trust unit based compensation (Note 13)
    
    
    
    5,351
    
    
    
    
    2,546Deferred charges and other items
    
    
    
    2,987
    
    
    
    
    498Changes in non-cash operating working capital (Note 16)
    
    
    
    (15,840
    )
    
    
    
    (24,331
    )800,344
    
    
    
    
    554,368FINANCINGDistributions paid (Note 14)
    
    
    
    (717,562
    )
    
    
    
    (516,966
    )Bank indebtedness
    
    
    
    (9,374
    )
    
    
    
    9,374Change in long term debt, net
    
    
    
    674,276
    
    
    
    
    (54,870
    )Redemption of convertible debentures (Note 8)
    
    
    
    
    
    
    
    
    (21,184
    )Repayment of note payable
    
    
    
    
    
    
    
    
    (20,000
    )Proceeds from issue of trust units
    
    
    
    48,141
    
    
    
    
    971,791(4,519
    )
    
    
    
    368,145INVESTINGBusiness acquisition (Note 4)
    
    
    
    (923,121
    )
    
    
    
    (500,451
    )Expenditures on property, plant and equipment
    
    
    
    (309,708
    )
    
    
    
    (300,809
    )Other property acquisitions
    
    
    
    (9,012
    )
    
    
    
    (52,880
    )Proceeds on property dispositions
    
    
    
    458,804
    
    
    
    
    15,230Deposit on acquisition
    
    
    
    
    
    
    
    
    (103,750
    )Change in remediation trust funds
    
    
    
    (6,950
    )
    
    
    
    (2,815
    )Change in non-cash investing working capital (Note 16)
    
    
    
    (3,821
    )
    
    
    
    37,529(793,808
    )
    
    
    
    (907,946
    )CHANGE IN CASH AND TERM DEPOSITS
    
    
    
    2,017
    
    
    
    
    14,567CASH AND TERM DEPOSITS (BANK INDEBTEDNESS)
AT BEGINNING OF YEAR
    
    
    
    
    
    
    
    
    (14,567
    )CASH AND TERM DEPOSITS AT END OF YEAR
    
    
    $
    2,017
    
    
    
    $
    




---



##### 








---



##### 








---



##### 



92
    
    Notes to Consolidated Financial Statements  PENGROWTH 2007 ANNUAL REPORT




---



##### 








---



##### 



I.
    
    Pengrowth had deferred $2.8 million of debt issue costs related to prior issuances of private
placement debt. The deferred issue costs were being amortized on a straight-line basis over the
term of the debt. On January 1, 2007, an adjustment of $1.6 million was made to reduce the carrying
amount of the related debt and other assets. No adjustment was made to opening retained earnings
for the cumulative effect of the change in accounting policy as the amount was not significant.II.
    
    Foreign exchange swaps were used to fix the foreign exchange rate on the interest and principal
of the Pounds Sterling 50 million ten year senior unsecured notes (see Note 9). In prior years,
Pengrowth had formally documented this relationship as a hedge and applied hedge accounting to this
transaction which resulted in any unrealized foreign exchange gains (losses) on the translation of
the debt to be deferred and recorded in other assets (other liabilities). On January 1, 2007,
Pengrowth ceased to designate the foreign exchange swaps as a cash flow hedge of the U.K. Pounds
Sterling 50 million unsecured notes and as a result hedge accounting was no longer used to account
for the transaction. As the hedging relationship qualified for hedge accounting under the revised
hedging standards, $13.6 million of deferred foreign exchange loss related to the debt was
reclassified to accumulated other comprehensive income. An asset related to the fair value of
foreign exchange swaps of $13.9 million was recognized on the balance sheet on January 1, 2007 with
a corresponding adjustment to reduce accumulated other comprehensive income. The remaining balance
in accumulated other comprehensive income of $0.3 million was reclassified to net income in the
period as the amount was not significant.
    94
    
    Notes to Consolidated Financial Statements  PENGROWTH 2007 ANNUAL REPORT




---



##### 



Allocation of Purchase Price:Property, plant and equipment
    
    
    $
    1,360,491Goodwill
    
    
    
    62,296Asset retirement obligations
    
    
    
    (90,772
    )Future income taxes
    
    
    
    (305,144
    )$
    1,026,871Consideration:Cash
    
    
    $
    1,024,585Acquisition costs
    
    
    
    2,286$
    1,026,871




---



##### 



Carson Creek
    
    
    EspritProperties
    
    
    Energy Trust
    
    
    
    TotalAllocation of Purchase Price:Property, plant and equipment
    
    
    $
    495,806
    
    
    $
    1,207,121
    
    
    
    $
    1,702,927Goodwill
    
    
    
    129,745
    
    
    
    285,722
    
    
    
    
    415,467Fair value of commodity contracts
    
    
    
    
    
    
    
    10,601
    
    
    
    
    10,601Bank debt
    
    
    
    
    
    
    
    (276,870
    )
    
    
    
    (276,870
    )Convertible debentures
    
    
    
    
    
    
    
    (96,500
    )
    
    
    
    (96,500
    )Contract liabilities
    
    
    
    (9,073
    )
    
    
    
    
    
    
    
    (9,073
    )Asset retirement obligations
    
    
    
    (20,668
    )
    
    
    (51,651
    )
    
    
    
    (72,319
    )Future income taxes
    
    
    
    (121,384
    )
    
    
    (110,590
    )
    
    
    
    (231,974
    )Working capital deficiency
    
    
    
    
    
    
    
    (45,864
    )
    
    
    
    (45,864
    )$
    474,426
    
    
    $
    921,969
    
    
    
    $
    1,396,395Consideration:Cash
    
    
    $
    474,089
    
    
    $
    19,990
    
    
    
    $
    494,079Pengrowth trust units issued
    
    
    
    
    
    
    
    895,944
    
    
    
    
    895,944Acquisition costs
    
    
    
    337
    
    
    
    6,035
    
    
    
    
    6,372$
    474,426
    
    
    $
    921,969
    
    
    
    $
    1,396,395
   Carson Creek Properties
   Esprit Energy Trust




---



##### 



2007
    
    
    
    2006Deferred compensation expense (net
of accumulated amortization of $5,077, 2006  $2,381)
    
    
    $
    
    
    
    
    $
    2,696Debt issue costs (net of accumulated
amortization of, 2006  $1,192)
    
    
    
    
    
    
    
    
    1,626
    
    
    
    
    4,322Deferred foreign exchange loss on translation of U.K. debt
    
    
    
    
    
    
    
    
    13,631Remediation trust funds (Note 10)
    
    
    
    18,094
    
    
    
    
    11,144Equity investment
    
    
    
    6,737
    
    
    
    
    7,035$
    24,831
    
    
    
    $
    36,132
    2007
    
    
    
    2006Property, plant and equipment, at cost
    
    
    $
    6,577,484
    
    
    
    $
    5,365,309Accumulated depletion, depreciation and amortization
    
    
    
    (2,298,083
    )
    
    
    
    (1,658,999
    )Net book value of property, plant and equipment
    
    
    $
    4,279,401
    
    
    
    
    3,706,310Net book value of deferred injectant costs
    
    
    
    27,281
    
    
    
    
    35,292Net book value of property, plant and equipment and deferred injectants
    
    
    $
    4,306,682
    
    
    
    $
    3,741,602




---



##### 



Foreign
    
    
    Edmonton LightWTI Oil
    
    
    Exchange Rate
    
    
    Crude Oil
    
    
    AECO GasYear
    
    
    (U.S.$/bbl)
    
    
    (U.S.$/Cdn$)
    
    
    (Cdn$/bbl)
    
    
    (Cdn$/mmbtu)2008
    
    
    $
    92.00
    
    
    
    1.000
    
    
    $
    91.10
    
    
    $
    6.752009
    
    
    $
    88.00
    
    
    
    1.000
    
    
    $
    87.10
    
    
    $
    7.552010
    
    
    $
    84.00
    
    
    
    1.000
    
    
    $
    83.10
    
    
    $
    7.602011
    
    
    $
    82.00
    
    
    
    1.000
    
    
    $
    81.10
    
    
    $
    7.602012
    
    
    $
    82.00
    
    
    
    1.000
    
    
    $
    81.10
    
    
    $
    7.602013
    
    
    $
    82.00
    
    
    
    1.000
    
    
    $
    81.10
    
    
    $
    7.602014
    
    
    $
    82.00
    
    
    
    1.000
    
    
    $
    81.10
    
    
    $
    7.802015
    
    
    $
    82.00
    
    
    
    1.000
    
    
    $
    81.10
    
    
    $
    7.972016
    
    
    $
    82.02
    
    
    
    1.000
    
    
    $
    81.12
    
    
    $
    8.142017
    
    
    $
    83.66
    
    
    
    1.000
    
    
    $
    82.76
    
    
    $
    8.31Thereafter
    
    
    + 2.0 percent/yr
    
    
    
    1.000
    
    
    + 2.0 percent/yr
    
    
    + 2.0 percent/yr
   2007
    
    
    
    2006Fixed price commodity contract
    
    
    $
    4,110
    
    
    
    $
    7,800Firm transportation contracts
    
    
    
    12,715
    
    
    
    
    14,04216,825
    
    
    
    
    21,842Less current portion
    
    
    
    (4,663
    )
    
    
    
    (5,017
    )$
    12,162
    
    
    
    $
    16,825




---



##### 



Debt
    
    
    Equity
    
    
    TotalFair value on October 2, 2006 (Note 4)
    
    
    $
    96,295
    
    
    $
    205
    
    
    $
    96,500Amortization of debt premium
    
    
    
    (29
    )
    
    
    
    
    
    
    (29
    )Redeemed for cash
    
    
    
    (21,139
    )
    
    
    (45
    )
    
    
    (21,184
    )Balance, December 31, 2006
    
    
    $
    75,127
    
    
    $
    160
    
    
    $
    75,287Amortization of debt premium
    
    
    
    (97
    )
    
    
    
    
    
    
    (97
    )Balance, December 31, 2007
    
    
    $
    75,030
    
    
    $
    160
    
    
    $
    75,190
  2007
    
    
    
    2006U.S. dollar denominated debt:U.S. dollar 150 million senior unsecured notes at 4.93 percent due April 2010
    
    
    $
    148,053
    
    
    
    $
    174,810U.S. dollar 50 million senior unsecured notes at 5.47 percent due April 2013
    
    
    
    49,351
    
    
    
    
    58,270U.S. dollar 400 million senior unsecured notes at 6.35 percent due July 2017
    
    
    
    394,390
    
    
    
    
    591,794
    
    
    
    
    233,080Pound sterling denominated 50 million unsecured notes
at 5.46 percent due December 2015
    
    
    
    97,444
    
    
    
    
    114,120Canadian dollar revolving credit borrowings
    
    
    
    513,998
    
    
    
    
    257,000$
    1,203,236
    
    
    
    $
    604,200




---



##### 



2007
    
    
    
    2006Asset retirement obligations, beginning of year
    
    
    $
    255,331
    
    
    
    $
    184,699Increase (decrease) in liabilities during the year related to:Acquisitions
    
    
    
    91,333
    
    
    
    
    72,680Disposals
    
    
    
    (35,199
    )
    
    
    
    (1,500
    )Additions
    
    
    
    3,753
    
    
    
    
    1,649Revisions
    
    
    
    22,659
    
    
    
    
    (9,695
    )Accretion expense
    
    
    
    25,722
    
    
    
    
    16,591Liabilities settled during the year
    
    
    
    (11,428
    )
    
    
    
    (9,093
    )Asset retirement obligations, end of year
    
    
    $
    352,171
    
    
    
    $
    255,331
 Remediation trust funds




---



##### 



Remediation Trust Funds
    
    
    2007
    
    
    
    2006Opening balance
    
    
    $
    11,144
    
    
    
    $
    8,329Contributions to Judy Creek Remediation Trust Fund
    
    
    
    917
    
    
    
    
    1,036Contributions to SOEP Environmental Restoration Fund
    
    
    
    6,441
    
    
    
    
    2,153Remediation funded by Judy Creek Remediation Trust Fund
    
    
    
    (408
    )
    
    
    
    (374
    )Change in remediation trust funds
    
    
    
    6,950
    
    
    
    
    2,815Closing balance
    
    
    $
    18,094
    
    
    
    $
    11,144Expenditures on ARO
    
    
    
    2007
    
    
    
    
    2006Expenditures on ARO not covered by the trust funds
    
    
    $
    11,020
    
    
    
    $
    8,719Expenditures on ARO covered by the trust funds
    
    
    
    408
    
    
    
    
    374$
    11,428
    
    
    
    $
    9,093




---



##### 



2007
    
    
    
    2006Income before taxes
    
    
    $
    95,040
    
    
    
    $
    248,048Combined federal and provincial tax rate
    
    
    
    32.1
    %
    
    
    
    34.1
    %Expected income tax
    
    
    
    30,508
    
    
    
    
    84,584Net income of the Trust
    
    
    
    (123,227
    )
    
    
    
    (85,989
    )Impact of SIFT legislation
    
    
    
    (71,048
    )
    
    
    
    Resource allowance
    
    
    
    
    
    
    
    
    (8,618
    )Non-deductible crown charges
    
    
    
    
    
    
    
    
    17,586Unrealized foreign exchange gain
    
    
    
    (9,254
    )
    
    
    
    1Book to tax differential on dispositions
    
    
    
    (68,722
    )
    
    
    
    Attributed Canadian royalty income
    
    
    
    
    
    
    
    
    (6,616
    )Change in enacted tax rates
    
    
    
    (59,230
    )
    
    
    
    (19,886
    )Future tax rate difference
    
    
    
    19,679
    
    
    
    
    2,491Other including stock based compensation
    
    
    
    16,682
    
    
    
    
    2,178Future income tax reduction
    
    
    
    (264,612
    )
    
    
    
    (14,269
    )Capital taxes
    
    
    
    
    
    
    
    
    14$
    (264,612
    )
    
    
    $
    (14,255
    )
   2007
    
    
    
    2006Future income tax liabilities:Property, plant, equipment and other assets
    
    
    $
    344,701
    
    
    
    $
    339,660Unrealized foreign exchange gain
    
    
    
    10,776
    
    
    
    
    8,288Deferred partnership income
    
    
    
    27,929
    
    
    
    
    Other
    
    
    
    
    
    
    
    
    150383,406
    
    
    
    
    348,098Future income tax assets:Attributed Canadian royalty income
    
    
    
    (10,351
    )
    
    
    
    (13,947
    )Contract liabilities
    
    
    
    (4,706
    )
    
    
    
    (6,334
    )$
    368,349
    
    
    
    $
    327,817




---



##### 



Total Trust Units:
 Years ended December 31
    
    
    2007
    
    
    
    2006Number
    
    
    
    
    
    
    
    NumberTrust units issued
    
    
    of trust units
    
    
    Amount
    
    
    
    of trust units
    
    
    AmountBalance, beginning of year
    
    
    
    244,016,623
    
    
    $
    4,383,993
    
    
    
    
    159,864,083
    
    
    $
    2,514,997Issued for the Esprit Trust
business combination (non-cash)
    
    
    
    
    
    
    
    
    
    
    
    
    34,725,157
    
    
    
    895,944Issued for cash
    
    
    
    
    
    
    
    
    
    
    
    
    47,575,000
    
    
    
    987,841Issue costs
    
    
    
    
    
    
    
    (745
    )
    
    
    
    
    
    
    
    (51,575
    )Issued on redemption of DEUs (non-cash)
    
    
    
    2,931
    
    
    
    55
    
    
    
    
    14,523
    
    
    
    233Issued for cash on exercise of
trust unit options and rights
    
    
    
    350,615
    
    
    
    4,006
    
    
    
    
    607,766
    
    
    
    9,476Issued for cash under Distribution
Reinvestment Plan (DRIP)
    
    
    
    2,461,299
    
    
    
    44,880
    
    
    
    
    1,226,806
    
    
    
    26,049Issued on redemption of Royalty Units (non-cash)
    
    
    
    14,952
    
    
    
    
    
    
    
    
    3,288
    
    
    
    Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    
    548
    
    
    
    
    
    
    
    
    1,028Balance, end of year
    
    
    
    246,846,420
    
    
    $
    4,432,737
    
    
    
    
    244,016,623
    
    
    $
    4,383,993
 Consolidated Trust Units:
 Years ended December 31
    
    
    2007
    
    
    
    2006Number
    
    
    
    
    
    
    
    NumberTrust units issued
    
    
    of trust units
    
    
    Amount
    
    
    
    of trust units
    
    
    AmountBalance, beginning of year
    
    
    
    244,005,105
    
    
    $
    4,383,819
    
    
    
    
    
    
    
    $
    Issued in trust unit consolidation
    
    
    
    
    
    
    
    
    
    
    
    
    160,921,001
    
    
    
    2,535,949Issued on conversion of Class A trust units
    
    
    
    9,630
    
    
    
    173
    
    
    
    
    3,450
    
    
    
    57Issued for the Esprit Trust business
combination (non-cash)
    
    
    
    
    
    
    
    
    
    
    
    
    34,725,157
    
    
    
    895,944Issued for cash
    
    
    
    
    
    
    
    
    
    
    
    
    47,575,000
    
    
    
    987,841Issue costs
    
    
    
    
    
    
    
    (745
    )
    
    
    
    
    
    
    
    (51,575
    )Issued on redemption of DEUs (non-cash)
    
    
    
    2,931
    
    
    
    55
    
    
    
    
    14,523
    
    
    
    233Issued for cash on exercise of
trust unit options and rights
    
    
    
    350,615
    
    
    
    4,006
    
    
    
    
    99,228
    
    
    
    1,579Issued for cash under DRIP
    
    
    
    2,461,299
    
    
    
    44,880
    
    
    
    
    663,458
    
    
    
    13,415Issued on redemption of Royalty Units (non-cash)
    
    
    
    14,952
    
    
    
    
    
    
    
    
    3,288
    
    
    
    Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    
    548
    
    
    
    
    
    
    
    
    376Balance, end of year
    
    
    
    246,844,532
    
    
    $
    4,432,736
    
    
    
    
    244,005,105
    
    
    $
    4,383,819




---



##### 



Class A Trust Units:
 Years ended December 31
    
    
    2007
    
    
    
    2006Number
    
    
    
    
    
    
    
    NumberTrust units issued
    
    
    of trust units
    
    
    Amount
    
    
    
    of trust units
    
    
    AmountBalance, beginning of year
    
    
    
    11,518
    
    
    $
    174
    
    
    
    
    77,524,673
    
    
    $
    1,196,121Trust units converted to Class A trust units
    
    
    
    (9,630
    )
    
    
    (173
    )
    
    
    
    2,760
    
    
    
    43Trust units converted to consolidated trust units
    
    
    
    
    
    
    
    
    
    
    
    
    (77,515,915
    )
    
    
    (1,195,990
    )Balance, end of year
    
    
    
    1,888
    
    
    $
    1
    
    
    
    
    11,518
    
    
    $
    174
 Class B Trust Units:
 Year ended December 31
    
    
    2006NumberTrust units issued
    
    
    of trust units
    
    
    AmountBalance, beginning of year
    
    
    
    82,301,443
    
    
    $
    1,318,294Trust units converted to (from) Class B trust units
    
    
    
    1,095
    
    
    
    17Issued for cash on exercise of trust unit options and rights
    
    
    
    508,538
    
    
    
    7,897Issued for cash under DRIP
    
    
    
    563,348
    
    
    
    12,634Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    
    652Trust units renamed to become consolidated trust units
    
    
    
    (83,374,424
    )
    
    
    (1,339,494
    )Balance, end of year
    
    
    
    
    
    
    $
    
 Unclassified Trust Units:
 Year ended December 31
    
    
    2006NumberTrust units issued
    
    
    of trust units
    
    
    AmountBalance, beginning of year
    
    
    
    37,967
    
    
    $
    582Converted to Class A or Class B trust units
    
    
    
    (3,855
    )
    
    
    (60
    )Trust units converted to consolidated trust units
    
    
    
    (34,112
    )
    
    
    (522
    )Balance, end of year
    
    
    
    
    
    
    $
    
 Class A Trust Unit and Class B Trust Unit Consolidation




---



##### 



Redemption Rights
  Distribution Reinvestment Plan
  At The Market Distribution
  Contributed Surplus
 2007
    
    
    
    2006Balance, beginning of year
    
    
    $
    4,931
    
    
    
    $
    3,646Trust unit rights incentive plan (non-cash expensed)
    
    
    
    1,903
    
    
    
    
    1,298Deferred entitlement trust units (non-cash expensed)
    
    
    
    3,448
    
    
    
    
    1,248Trust unit rights incentive plan (non-cash exercised)
    
    
    
    (548
    )
    
    
    
    (1,028
    )Deferred entitlement trust units (non-cash exercised)
    
    
    
    (55
    )
    
    
    
    (233
    )Balance, end of year
    
    
    $
    9,679
    
    
    
    $
    4,931




---



##### 



Long Term Incentive Program
    2007
    
    
    
    2006Weighted
    
    
    
    
    
    
    
    WeightedNumber
    
    
    average
    
    
    
    Number of
    
    
    averageDEUs
    
    
    of DEUs
    
    
    fair value
    
    
    
    DEUs
    
    
    fair valueOutstanding, beginning of year
    
    
    
    399,568
    
    
    $
    20.55
    
    
    
    
    185,591
    
    
    $
    18.32Granted
    
    
    
    451,615
    
    
    $
    19.73
    
    
    
    
    222,088
    
    
    $
    22.28Forfeited
    
    
    
    (92,672
    )
    
    $
    20.15
    
    
    
    
    (33,981
    )
    
    $
    20.13Exercised
    
    
    
    (2,931
    )
    
    $
    20.06
    
    
    
    
    (14,207
    )
    
    $
    20.43Deemed DRIP
    
    
    
    112,462
    
    
    $
    20.27
    
    
    
    
    40,077
    
    
    $
    19.14Outstanding, end of year
    
    
    
    868,042
    
    
    $
    20.13
    
    
    
    
    399,568
    
    
    $
    20.55
 Trust Unit Rights Incentive Plan




---



##### 



2007
    
    
    
    2006Weighted
    
    
    
    
    
    
    
    WeightedNumber
    
    
    average
    
    
    
    Number
    
    
    averageTrust Unit Rights
    
    
    of rights
    
    
    exercise price
    
    
    
    of rights
    
    
    exercise priceOutstanding at beginning of year
    
    
    
    1,534,241
    
    
    $
    16.06
    
    
    
    
    1,441,737
    
    
    $
    14.85Granted (1)
    
    
    
    1,259,562
    
    
    $
    19.75
    
    
    
    
    617,409
    
    
    $
    22.39Exercised
    
    
    
    (343,925
    )
    
    $
    11.35
    
    
    
    
    (452,468
    )
    
    $
    14.75Forfeited
    
    
    
    (199,822
    )
    
    $
    14.63
    
    
    
    
    (72,437
    )
    
    $
    17.47Outstanding at year-end
    
    
    
    2,250,056
    
    
    $
    17.39
    
    
    
    
    1,534,241
    
    
    $
    16.06Exercisable at year-end
    
    
    
    1,317,296
    
    
    $
    16.30
    
    
    
    
    969,402
    
    
    $
    14.22
 
 (1)
    
    Weighted average exercise price of rights granted are based on the exercise price at the date of grant.  Rights Outstanding
    
    
    
    Rights ExercisableWeightedaverage
    
    
    Weighted
    
    
    
    
    
    
    Weightedremaining
    
    
    average
    
    
    
    
    
    
    averageNumber
    
    
    contractual
    
    
    exercise
    
    
    
    Number
    
    
    exerciseRange of exercise prices
    
    
    outstanding
    
    
    life (years)
    
    
    price
    
    
    
    exercisable
    
    
    price$9.00 to $11.99
    
    
    
    255,178
    
    
    
    1.1
    
    
    $
    11.07
    
    
    
    
    255,178
    
    
    $
    11.07$12.00 to $14.99
    
    
    
    281,990
    
    
    
    2.0
    
    
    $
    13.91
    
    
    
    
    281,990
    
    
    $
    13.91$15.00 to $16.99
    
    
    
    97,376
    
    
    
    2.8
    
    
    $
    15.83
    
    
    
    
    97,376
    
    
    $
    15.83$17.00 to $18.99
    
    
    
    1,206,999
    
    
    
    4.2
    
    
    $
    17.84
    
    
    
    
    415,257
    
    
    $
    18.55$19.00 to $23.99
    
    
    
    408,513
    
    
    
    3.2
    
    
    $
    20.47
    
    
    
    
    267,495
    
    
    $
    20.47$9.00 to $23.99
    
    
    
    2,250,056
    
    
    
    3.3
    
    
    $
    17.39
    
    
    
    
    1,317,296
    
    
    $
    16.30




---



##### 



Trust Unit Option Plan
   2007
    
    
    
    2006Weighted
    
    
    
    
    
    
    
    WeightedNumber
    
    
    average
    
    
    
    Number
    
    
    averageTrust Unit Options
    
    
    of options
    
    
    exercise price
    
    
    
    of options
    
    
    exercise priceOutstanding at beginning of year
    
    
    
    98,619
    
    
    $
    16.12
    
    
    
    
    259,317
    
    
    $
    17.28Exercised
    
    
    
    (6,690
    )
    
    $
    15.25
    
    
    
    
    (155,298
    )
    
    $
    18.03Expired
    
    
    
    (25,611
    )
    
    $
    18.61
    
    
    
    
    (5,400
    )
    
    $
    16.96Outstanding and exercisable at year-end
    
    
    
    66,318
    
    
    $
    15.25
    
    
    
    
    98,619
    
    
    $
    16.12
 Trust Unit Award Plan
  Employee Savings Plans
  Trust Unit Margin Purchase Plan




---



##### 



2007
    
    
    
    2006Accumulated earnings
    
    
    $
    1,675,338
    
    
    
    $
    1,315,686Accumulated distributions declared
    
    
    
    (3,361,694
    )
    
    
    
    (2,655,093
    )$
    (1,686,356
    )
    
    
    $
    (1,339,407
    )
  Distributions paid
   2007
    
    
    
    2006Unrealized foreign exchange loss (gain) on translation
of U.S. dollar denominated debt
    
    
    $
    (57,820
    )
    
    
    $
    480Unrealized foreign exchange gain on translation
of U.K. Pound denominated debt
    
    
    
    (16,120
    )
    
    
    
    $
    (73,940
    )
    
    
    $
    480Unrealized loss on foreign exchange risk management contracts (Note 19)
    
    
    
    8,067
    
    
    
    
    Realized foreign exchange (gain) loss
    
    
    
    4,016
    
    
    
    
    (458
    )$
    (61,857
    )
    
    
    $
    22




---



##### 



Change in Non-Cash Operating Working Capital
 Cash provided by (used for):
    
    
    2007
    
    
    
    2006Accounts receivable
    
    
    $
    (34,707
    )
    
    
    $
    12,819Accounts payable and accrued liabilities
    
    
    
    21,699
    
    
    
    
    (30,974
    )Due to Pengrowth Management Limited
    
    
    
    (2,832
    )
    
    
    
    (6,176
    )$
    (15,840
    )
    
    
    $
    (24,331
    )
 Change in Non-Cash Investing Working Capital
 Cash provided by (used for):
    
    
    2007
    
    
    
    2006Accounts payable for capital accruals
    
    
    $
    (3,821
    )
    
    
    $
    37,529
 Cash payments
 2007
    
    
    
    2006Interest on long term debt
    
    
    $
    58,192
    
    
    
    $
    32,183Interest on bank indebtedness
    
    
    
    13,876
    
    
    
    
    $
    72,068
    
    
    
    $
    32,183
       2007
    
    
    
    2006Weighted average number of trust units  Basic
    
    
    
    245,470
    
    
    
    
    175,871Dilutive effect of trust unit options, trust unit rights and DEUs
    
    
    
    740
    
    
    
    
    583Weighted average number of trust units  Diluted
    
    
    
    246,210
    
    
    
    
    176,454




---



##### 



Interest Rate Risk
  Foreign Currency Exchange Risk
   Credit Risk
  Forward and Futures Contracts
    Volume
    
    
    Reference
    
    
    PriceRemaining Term
    
    
    (bbl/d)
    
    
    Point
    
    
    per bblFinancial:Jan 1, 2008  Oct 31, 2008
    
    
    
    1,000
    
    
    WTI (1)
    
    $74.25 CdnJan 1, 2008  Dec 31, 2008
    
    
    
    16,500
    
    
    WTI (1)
    
    $76.20 CdnJan 1, 2009  Dec 31, 2009
    
    
    
    6,000
    
    
    WTI (1)
    
    $77.57 Cdn
 
 (1)
    
    Associated Cdn $ / U.S. $ foreign exchange rate has been fixed




---



##### 



Volume
    
    
    Reference
    
    PriceRemaining Term
    
    
    (mmbtu/d)
    
    
    Point
    
    per mmbtuFinancial:Jan 1, 2008  Dec 31, 2008
    
    
    
    5,000
    
    
    Transco Z6 (1)
    
    $10.90 CdnJan 1, 2008  Dec 31, 2008
    
    
    
    12,500
    
    
    NYMEX (1)
    
    $8.22 CdnJan 1, 2009  Dec 31, 2009
    
    
    
    10,000
    
    
    NYMEX (1)
    
    $8.50 CdnJan 1, 2008  Mar 31, 2008
    
    
    
    2,370
    
    
    AECO
    
    $8.44 CdnJan 1, 2008  Dec 31, 2008
    
    
    
    61,609
    
    
    AECO
    
    $8.26 CdnJan 1, 2009  Dec 31, 2009
    
    
    
    26,065
    
    
    AECO
    
    $7.56 CdnJan 1, 2008  Dec 31, 2008
    
    
    
    15,000
    
    
    Chicago MI (1)
    
    $8.45 CdnJan 1, 2009  Dec 31, 2009
    
    
    
    12,500
    
    
    Chicago MI (1)
    
    $8.40 Cdn
 
 (1)
    
    Associated Cdn $ / U.S. $ foreign exchange rate has been fixed   ForeignCommodity risk
    
    
    exchange riskmanagement
    
    
    managementBalance Sheet as at December 31, 2007
    
    
    contracts
    
    
    contracts
    
    
    TotalCurrent portion of unrealized risk management assets
    
    
    $
    8,034
    
    
    $
    
    
    
    $
    8,034Non-current portion of unrealized risk management assets
    
    
    
    66
    
    
    
    5,958
    
    
    
    6,024Current portion of unrealized risk management liabilities
    
    
    
    (70,694
    )
    
    
    (152
    )
    
    
    (70,846
    )Non-current portion of unrealized risk management liabilities
    
    
    
    (22,613
    )
    
    
    
    
    
    
    (22,613
    )Total unrealized risk management assets (liabilities)
as at December 31, 2007
    
    
    $
    (85,207
    )
    
    $
    5,806
    
    
    $
    (79,401
    )
 ForeignCommodity risk
    
    
    exchange riskmanagement
    
    
    managementBalance Sheet as at December 31, 2006
    
    
    contracts
    
    
    contracts
    
    
    TotalCurrent portion of unrealized risk management assets
    
    
    $
    37,972
    
    
    $
    
    
    
    $
    37,972Non-current portion of unrealized risk management assets
    
    
    
    495
    
    
    
    
    
    
    
    495Current portion of unrealized risk management liabilities
    
    
    
    
    
    
    
    
    
    
    
    Non-current portion of unrealized risk management liabilities
    
    
    
    (1,367
    )
    
    
    
    
    
    
    (1,367
    )Total unrealized risk management assets (liabilities)
as at December 31, 2006
    
    
    $
    37,100
    
    
    $
    
    
    
    $
    37,100




---



##### 



ForeignCommodity risk
    
    
    exchange riskmanagement
    
    
    managementYear ended December 31, 2007
    
    
    contracts
    
    
    contracts
    
    
    TotalTotal unrealized risk management assets (liabilities)
at December 31, 2007
    
    
    $
    (85,207
    )
    
    $
    5,806
    
    
    $
    (79,401
    )Less: Unrealized risk management assets at January 1, 2007
    
    
    
    37,100
    
    
    
    13,873
    
    
    
    50,973Unrealized loss on risk management for
the year ended December 31, 2007
    
    
    $
    (122,307
    )
    
    $
    (8,067
    )
    
    $
    (130,374
    )
 ForeignCommodity risk
    
    
    exchange riskmanagement
    
    
    managementYear ended December 31, 2006
    
    
    contracts
    
    
    contracts
    
    
    TotalTotal unrealized risk management assets at December 31, 2006
    
    
    $
    37,100
    
    
    $
    
    
    
    $
    37,100Less: Unrealized risk management asset recognized
as part of Esprit business combination
    
    
    
    10,601
    
    
    
    
    
    
    
    10,601Unrealized gain on risk management
for the year ended December 31, 2006
    
    
    $
    26,499
    
    
    $
    
    
    
    $
    26,499
 Natural Gas Fixed Price Sales Contract
  Volume
    
    
    PriceRemaining Term 2008 to 2009
    
    
    (mmbtu/d)
    
    
    per mmbtu (1)Jan 1, 2008  Oct 31, 2008
    
    
    
    3,886
    
    
    $2.34 CdnNov 1, 2008  April 30, 2009
    
    
    
    3,886
    
    
    $2.40 Cdn
 
 (1)
    
    Reference price based on AECO




---



##### 



Fair value of financial instruments
  2007
    
    
    
    2006Net book
    
    
    
    
    
    
    
    Net bookAs at December 31
    
    
    Fair value
    
    
    value
    
    
    
    Fair value
    
    
    valueRemediation funds
    
    
    $
    18,107
    
    
    $
    18,094
    
    
    
    $
    11,162
    
    
    $
    11,144U.S. dollar denominated debt
    
    
    $
    627,674
    
    
    $
    591,794
    
    
    
    $
    224,624
    
    
    $
    233,080U.K. Pound Sterling denominated debt
    
    
    $
    96,181
    
    
    $
    97,444
    
    
    
    $
    109,692
    
    
    $
    114,120Convertible debentures
    
    
    $
    74,741
    
    
    $
    75,030
    
    
    
    $
    75,488
    
    
    $
    75,127
  2008
    
    
    2009
    
    
    2010
    
    
    2011
    
    
    2012
    
    
    Thereafter
    
    
    TotalOperating leases
    
    
    $
    9,015
    
    
    $
    9,232
    
    
    $
    8,652
    
    
    $
    8,221
    
    
    $
    8,139
    
    
    $
    42,028
    
    
    $
    85,287
      Volume
    
    
    Reference
    
    
    PriceRemaining Term
    
    
    (bbl/d)
    
    
    Point
    
    
    per bblFinancial:Mar 1, 2008  Dec 31, 2008
    
    
    
    1,500
    
    
    WTI (1)
    
    $95.88CdnJan 1, 2009  Dec 31, 2009
    
    
    
    3,000
    
    
    WTI (1)
    
    $93.25Cdn
  Volume
    
    
    Reference
    
    
    PriceRemaining Term
    
    
    (mmbtu/d)
    
    
    Point
    
    
    per mmbtuFinancial:Mar 1, 2008  Dec 31, 2008
    
    
    
    2,370
    
    
    AECO
    
    $7.97CdnJan 1, 2009  Dec 31, 2009
    
    
    
    14,217
    
    
    AECO
    
    $7.97CdnFeb 1, 2008  Dec 31, 2008
    
    
    
    2,500
    
    
    Chicago MI (1)
    
    
    $8.31Cdn
 (1)
    
    Associated Cdn $ / U.S. $ foreign exchange rate has been fixed




---



##### 



23.
    
    RECONCILIATION OF FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES




---



##### 



2007
    
    
    
    2006Number Exercised
    
    
    Intrinsic Value
    
    
    
    Number Exercised
    
    
    Intrinsic ValueDEUs
    
    
    
    2,931
    (1)
    
    $
    58
    
    
    
    
    14,523
    (1)
    
    $
    334Trust Unit Options
    
    
    
    6,690
    
    
    
    32
    
    
    
    
    155,298
    
    
    
    827Trust Unit Rights
    
    
    
    343,925
    
    
    
    2,837
    
    
    
    
    452,468
    
    
    
    3,924Total
    
    
    
    353,546
    
    
    $
    2,927
    
    
    
    
    622,289
    
    
    $
    5,085
 (1)
    
    DEUs exercised relates to trust units issued under the plan for retirees as DEUs
vest immediately upon retirement, including accumulated DRIP




---



##### 



Trust Unit
    
    
    Trust UnitAs at December 31, 2007
    
    
    Options
    
    
    Rights
    
    
    DEUsNumber vested and expected to vest
    
    
    
    66,318
    
    
    
    2,088,505
    
    
    
    921,480Weighted average exercise price per unit (1)
    
    
    $
    15.25
    
    
    $
    17.26
    
    
    $
    Aggregate intrinsic value (2)
    
    
    $
    157
    
    
    $
    756
    
    
    $
    16,236Weighted average remaining life (years)
    
    
    
    0.8
    
    
    
    3.3
    
    
    
    1.5
 (1)
    
    No proceeds are received upon exercise price of DEUs(2)
    
    Based on December 31 closing trust unit price
 Trust Unit
    
    
    Trust UnitAs at December 31, 2006
    
    
    Options
    
    
    Rights
    
    
    DEUsNumber vested and expected to vest
    
    
    
    98,619
    
    
    
    1,521,207
    
    
    
    374,595Weighted average exercise price per unit (1)
    
    
    $
    16.12
    
    
    $
    16.04
    
    
    $
    Aggregate intrinsic value (2)
    
    
    $
    377
    
    
    $
    5,936
    
    
    $
    7,469Weighted average remaining life (years)
    
    
    
    1.5
    
    
    
    3.2
    
    
    
    1.8
 (1)
    
    No proceeds are received upon exercise price of DEUs(2)
    
    Based on December 31 closing trust unit price
  As at December 31, 2007
    
    
    Trust Unit Options
    
    
    Trust Unit RightsNumber exercisable (1)
    
    
    
    66,318
    
    
    
    1,317,296Weighted average exercise price per unit
    
    
    $
    15.25
    
    
    $
    16.30Aggregate intrinsic value (2)
    
    
    $
    157
    
    
    $
    1,743Weighted average remaining life (years)
    
    
    
    0.8
    
    
    
    3.3
 (1)
    
    No DEUs were exercisable at December 31, 2007(2)
    
    Based on December 31 closing trust unit price
 As at December 31, 2006
    
    
    Trust Unit Options
    
    
    Trust Unit RightsNumber exercisable (1)
    
    
    
    98,619
    
    
    
    969,402Weighted average exercise price per unit
    
    
    $
    16.12
    
    
    $
    14.22Aggregate intrinsic value (2)
    
    
    $
    377
    
    
    $
    5,542Weighted average remaining life (years)
    
    
    
    1.5
    
    
    
    3.2
 (1)
    
    No DEUs were exercisable at December 31, 2006(2)
    
    Based on December 31 closing trust unit price




---



##### 



Pro Forma(unaudited)Oil and gas sales
    
    
    $
    1,458,370Net income
    
    
    $
    182,661Net income per trust unit:Basic
    
    
    $
    0.90Diluted
    
    
    $
    0.89
   2007Balance, January 1
    
    
    $
    Additions based on tax positions related to the current year
    
    
    
    17,810Balance, December 31
    
    
    $
    17,810
  Jurisdiction
    
    
    YearsFederal (1)
    
    
    
    2004  2007Alberta, British Columbia, Saskatchewan and Nova Scotia
    
    
    
    2003  2007
 
 (1)
    
    The 2004 tax examination by federal authorities is currently in progress




---



##### 








---



##### 



Years ended December 31
    
    
    2007
    
    
    
    2006Net income, as reported
    
    
    $
    359,652
    
    
    
    $
    262,303Adjustments:Depletion and depreciation (a)
    
    
    
    35,761
    
    
    
    
    23,997Ceiling test write down under U.S. GAAP (a)
    
    
    
    
    
    
    
    
    (114,212
    )Unrealized gain (loss) on ineffective portion of oil and natural gas hedges (c)
    
    
    
    
    
    
    
    
    255Reclassification of hedging losses on foreign exchange swap from other
comprehensive income (c)
    
    
    
    
    
    
    
    
    13,631Deferred foreign exchange loss (c)
    
    
    
    (242
    )
    
    
    
    (13,631
    )Non-cash interest on convertible debentures (g)
    
    
    
    69
    
    
    
    
    (29
    )Amortization of discontinued hedge (c)
    
    
    
    272
    
    
    
    
    Future tax adjustments (e)(i)
    
    
    
    69,040
    
    
    
    
    Net income  U.S. GAAP
    
    
    $
    464,552
    
    
    
    $
    172,314Other comprehensive income (b):Unrealized gain on foreign exchange swap (c)
    
    
    
    
    
    
    
    
    16,077Unrealized hedging gain (c)
    
    
    
    
    
    
    
    
    18,153Reclassification to net income (c)
    
    
    
    
    
    
    
    
    (13,631
    )Amortization of discontinued hedge (c)
    
    
    
    (272
    )
    
    
    
    Comprehensive income  U.S. GAAP
    
    
    $
    464,280
    
    
    
    $
    192,913Net income  U.S. GAAP  Basic and diluted
    
    
    $
    1.89
    
    
    
    $
    0.98




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
    As
    
    
    IncreaseAs at December 31, 2007
    
    
    Reported
    
    
    (Decrease)
    
    
    U.S. GAAPAssetsProperty, plant and equipment (a)
    
    
    $
    4,306,682
    
    
    $
    (246,673
    )
    
    $
    4,060,009$
    (246,673
    )LiabilitiesConvertible debentures (g)
    
    
    $
    75,030
    
    
    $
    120
    
    
    $
    75,150Future income taxes (e) (i)
    
    
    
    387,100
    
    
    
    (86,850
    )
    
    
    300,250Other long term liabilities (i)
    
    
    
    
    
    
    
    17,810
    
    
    
    17,810Unitholders equity (d):Accumulated other comprehensive income (b)(c)
    
    
    $
    
    
    
    $
    2,174
    
    
    $
    2,174Trust Unitholders Equity (a)
    
    
    
    2,756,220
    
    
    
    (179,927
    )
    
    
    2,576,293$
    (246,673
    )
 As
    
    
    IncreaseAs at December 31, 2006
    
    
    Reported
    
    
    (Decrease)
    
    
    U.S. GAAPAssetsCurrent portion of unrealized foreign exchange gain (c)
    
    
    $
    
    
    
    $
    1,559
    
    
    $
    1,559Other assets (c)
    
    
    
    36,132
    
    
    
    (1,317
    )
    
    
    34,815Property, plant and equipment (a)
    
    
    
    3,741,602
    
    
    
    (282,434
    )
    
    
    3,459,168$
    (282,192
    )LiabilitiesConvertible debentures (g)
    
    
    $
    75,127
    
    
    $
    189
    
    
    $
    75,316Unitholders equity (d):Accumulated other comprehensive income (b)(c)
    
    
    $
    
    
    
    $
    2,446
    
    
    $
    2,446Trust Unitholders Equity (a)
    
    
    
    3,049,677
    
    
    
    (284,827
    )
    
    
    2,764,850$
    (282,192
    )




---



##### 



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
   As at December 31
    
    
    2007
    
    
    2006Trade
    
    
    $
    179,253
    
    
    $
    145,680Prepaids
    
    
    
    27,330
    
    
    
    23,972Other
    
    
    
    
    
    
    
    2,224$
    206,583
    
    
    $
    171,876
  As at December 31
    
    
    2007
    
    
    2006Accounts payable
    
    
    $
    93,180
    
    
    $
    93,788Accrued liabilities
    
    
    
    145,911
    
    
    
    127,425$
    239,091
    
    
    $
    221,213




---



##### 



APPENDIX D
 COMMENTS BY AUDITORS FOR US READERS
ON CANADA-US REPORTING DIFFERENCES
  /s/
KPMG LLP




---



##### 



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




---



##### 



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




---



##### 



RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
  (thousands of dollars)
    
    2007
    
    
    2006RevenueSales
    
    $
    1,422,148
    
    
    $
    988,238DeductProduction costs
    
    
    378,216
    
    
    
    253,162Transportation costs
    
    
    12,672
    
    
    
    7,621Amortization of injectant costs
    
    
    34,063
    
    
    
    34,644Technical support and other
    
    
    28,306
    
    
    
    17,357Depletion, depreciation and amortization
    
    
    603,323
    
    
    
    327,578Results of operations from producing activities
    
    $
    365,568
    
    
    $
    347,876
 
 1.
    
    The costs in this schedule exclude corporate overhead, interest expense and other operating
costs which are not directly related to producing activities.




---



##### 



COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
  2007
    
    
    2006(thousands of dollars)Property Acquisition CostsProved
    
    $
    986,148
    
    
    $
    1,333,666Unproved
    
    
    383,355
    
    
    
    440,357Exploration Costs
    
    
    21,192
    
    
    
    8,900Development Costs
    
    
    288,277
    
    
    
    275,705Injectant Costs
    
    
    26,052
    
    
    
    34,630$
    1,705,024
    
    
    $
    2,093,258
      CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
  (thousands of dollars)
    
    2007
    
    
    2006Oil and gas properties
    
    $
    6,578,258
    
    
    $
    5,400,601Less accumulated depletion, depreciation and amortization
    
    
    (2,540,283
    )
    
    
    (1,941,433
    )Net capitalized costs
    
    $
    4,037,975
    
    
    $
    3,459,168
 (thousands of dollars)
    
    2007
    
    
    2006Unproven oil and gas properties
    
    $
    1,065,519
    
    
    $
    471,820Proven oil and gas properties
    
    
    2,972,456
    
    
    
    2,987,348Net capitalized costs
    
    $
    4,037,975
    
    
    $
    3,459,168




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##### 



OIL AND GAS RESERVE INFORMATION
  Crude Oiland Natural
    
    NaturalGas Liquids
    
    GasMMbbls
    
    BcfNET PROVED DEVELOPED AND UNDEVELOPED
RESERVES AFTER ROYALTIESEnd of year 2005
    
    
    88.2
    
    
    
    333.5Revision of previous estimates
    
    
    5.5
    
    
    
    9.6Purchase of reserves in place
    
    
    18.2
    
    
    
    184.7Sales of reserves in place
    
    
    (0.4
    )
    
    
    (8.0
    )Discoveries and extensions
    
    
    0.8
    
    
    
    23.9Production
    
    
    (10.1
    )
    
    
    (51.8
    )End of year 2006
    
    
    102.2
    
    
    
    491.9Revision of previous estimates
    
    
    4.5
    
    
    
    34.2Purchase of reserves in place
    
    
    20.6
    
    
    
    133.4Sales of reserves in place
    
    
    (4.3
    )
    
    
    (79.9
    )Discoveries and extensions
    
    
    1.1
    
    
    
    27.1Production
    
    
    (12.6
    )
    
    
    (78.0
    )End of year 2007
    
    
    111.5
    
    
    
    528.7NET PROVED DEVELOPED RESERVES AFTER ROYALTIESEnd of year 2005
    
    
    70.4
    
    
    
    309.3End of year 2006
    
    
    84.1
    
    
    
    453.1End of year 2007
    
    
    93.0
    
    
    
    474.9
 
  1.
    
    Net after royalty reserves are the Trusts lessor royalty, overriding royalty, and working
interest share of the gross remaining reserves, after deduction of any crown, freehold and
overriding royalties. Such royalties are subject to change by legislation or regulation and
can also vary depending on production rates, selling prices and timing of initial production.2.
    
    Reserves are the estimated quantities of crude oil, natural gas and related substances
anticipated from geological and engineering data to be recoverable from known accumulations,
from a given date forward, by known technology, under existing operating conditions and prices
in effect at year end.3.
    
    Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing economic and
operating conditions.4.
    
    Proved developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Proved undeveloped
reserves are reserves that are expected to be recovered from known accumulations where a
significant expenditure is required.




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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
  2007
    
    
    2006(millions of dollars)Future cash inflows
    
    $
    12,796
    
    
    $
    9,480Future costsFuture production and development costs
    
    
    (4,957
    )
    
    
    (4,162
    )Future income taxes(1)
    
    
    (2,000
    )
    
    
    Future net cash flows
    
    
    5,839
    
    
    
    5,318Deduct: 10% annual discount factor
    
    
    (2,149
    )
    
    
    (2,152
    )Standardized measure of discounted future net cash flows
    
    $
    3,690
    
    
    $
    3,166




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##### 



CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS
RESERVES
  2007
    
    
    2006(millions of dollars)Future discounted net cash flows at beginning of year
    
    $
    3,166
    
    
    $
    3,344Sales and transfer, net of production costs
    
    
    (970
    )
    
    
    (676
    )Net change in sales and transfer prices, net of production costs
    
    
    1,111
    
    
    
    (637
    )Development costs during the year
    
    
    271
    
    
    
    284Changes in estimated future development costs
    
    
    (346
    )
    
    
    (355
    )Changes due to extensions and discoveries
    
    
    130
    
    
    
    83Changes due to revisions (including infill drilling and improved recovery)
    
    
    234
    
    
    
    129Accretion of discount
    
    
    317
    
    
    
    334Sales of reserves in place
    
    
    (303
    )
    
    
    (40
    )Purchase of reserves in place
    
    
    983
    
    
    
    842Net changes in income taxes
    
    
    (895
    )
    
    
    Changes in timing of future net cash flows and other
    
    
    (8
    )
    
    
    (142
    )End of Year
    
    $
    3,690
    
    
    $
    3,166
 
  1.
    
    The schedules above are calculated using year-end prices, costs, statutory tax rates and
existing proved oil and gas reserves. The value of exploration properties and probable
reserves, future exploration costs, future changes in oil and gas prices and in production and
development costs are excluded.




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##### 



APPENDIX
F
 PENGROWTH ENERGY TRUST CODE OF BUSINESS CONDUCT AND ETHICS
DATED FEBRUARY 19, 2008




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##### 



February 19, 2008




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##### 



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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##### 



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 by Directors, Officers and
Employees
 Books of Account
  Patents and Inventions
   Community Relations
 Public Disclosure Policy,
Electronic Communications and Related Procedures
 Company Property and Opportunities
  Page 9




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##### 



Accounting and Financial Reporting
   Employee Relations and Reporting
     Policies, Procedures and Internal Controls
  Acknowledgement
  Page 10




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##### 



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 Accounting Matters may report
their concerns to the Chairman of the Audit Committee.
 
    
    Directors, officers, employees, consultants or contractors with concerns regarding Conduct
Matter may report their concerns to the Chairman of the Corporate Governance Committee.
 
    
    Directors, officers and employees may report concerns regarding Accounting Matters or
Conduct Matters 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 Accounting Matters or Conduct Matters and (ii) when possible,
acknowledge receipt of the complaint to the sender.
 
    
    Complaints relating to Accounting Matters 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 Conduct Matters will be reviewed by the Corporate Governance Committee,
outside legal counsel and such other 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 Accounting Matters or Conduct Matters.
 
    
    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 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
     Page 15