##### 



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 SECTION13(a)OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended: December 31, 2005
    
    Commission File Number: 1-31253
 PENGROWTH ENERGY TRUST
  Alberta, Canada
 1311
    
    None(Primary Standard Industrial
    
    (I.R.S. EmployerClassification Code Number)
    
    Identification Number)
 Suite 2900,
240  4th Avenue S.W.
Calgary, Alberta Canada T2P 4H4
(403) 233-0224
 Vinson & Elkins L.L.P.
2300 First City Tower, 1001 Fannin
Houston, Texas 77002-6760
(713) 758-2222
 Securities registered or to be registered pursuant to Section 12(b) of the Act.
 Title
of each class
    

Name
of each exchange on which registeredClass A Trust 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     Annual information form
    
    þ     Audited annual financial statements
    Yes     o
    
    No     þ
  Yes     þ
    
    No     o




---



##### 



DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT
  Appendix
    
    DocumentsA
    
    Pengrowth Energy Trust Annual Information Form for the year ended
December 31, 2005.B
    
    Managements Discussion and Analysis (included on pages 54
through 80 of the Pengrowth Energy Trust 2005 Annual Report).C
    
    Consolidated Financial Statements of Pengrowth Energy Trust,
including note 20 thereof which includes a reconciliation of the
Consolidated Financial Statements to United States generally
accepted accounting principles.D
    
    Five Year Review  Pengrowth Energy Trust Consolidated Financial
Results (included on pages 115 through 119 of the Pengrowth
Energy Trust 2005 Annual Report).E
    
    Corporate Governance (included on pages 48 through 53 of the
Pengrowth Energy Trust 2005 Annual Report).F
    
    Oil and Gas Producing Activities Prepared in Accordance with SFAS
No. 69  Disclosures about Oil and Gas Producing Activities.
 - 2 -




---



##### 



CONTROLS AND PROCEDURES
   - 3 -




---



##### 



NOTICES PURSUANT TO REGULATION BTR
  IDENTIFICATION OF THE AUDIT COMMITTEE
  AUDIT COMMITTEE FINANCIAL EXPERT
  GOVERNANCE DISCLOSURE INCORPORATED BY REFERENCE
  UNDERTAKING
  - 4 -




---



##### 



SIGNATURES
  Date: March 29, 2006
    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, 2005




---



##### 



PENGROWTH ENERGY TRUST
 ANNUAL INFORMATION FORM
 Pengrowth Energy Trust is an energy investment trust formed under
the laws of the Province of Alberta which offers and sells its trust
units to the public. The trust units are not deposits within the
meaning of the Canadian Deposit Insurance Corporation Act (Canada)
(CDIC Act) and are not insured under the provisions of the CDIC Act
or any other legislation. Furthermore, Pengrowth Energy Trust is not
a trust company and, accordingly, is not registered under any trust
and loan company legislation as it does not carry on or intend to
carry on the business of a trust company.




---



##### 



TABLE OF CONTENTS
 GLOSSARY OF TERMS AND ABBREVIATIONS
    
    
    1CONVERSION
    
    
    4PRESENTATION OF OUR FINANCIAL INFORMATION
    
    
    4PRESENTATION OF OUR RESERVE INFORMATION
    
    
    4FORWARD-LOOKING STATEMENTS
    
    
    5PENGROWTH ENERGY TRUST
    
    
    6GENERAL DEVELOPMENT OF PENGROWTH TRUST
    
    
    6Organization and Structure
    
    
    6Business Strategy and Strengths
    
    
    7Historical Development
    
    
    8Recent Acquisitions, Financings and Developments
    
    
    11Trends
    
    
    12PENGROWTH MANAGEMENT LIMITED
    
    
    13Business
    
    
    13Management Agreement
    
    
    13Management Agreement Second Term
    
    
    15PENGROWTH CORPORATION  OPERATIONAL INFORMATION
    
    
    15Principal Properties
    
    
    16Additional Information Relating to Reserves Data
    
    
    32Finding, Development and Acquisition Costs
    
    
    34FD&A Costs  Company Interest Reserves
    
    
    35Other Oil and Gas Information
    
    
    35Production
    
    
    38Replacement of Properties
    
    
    40Borrowing
    
    
    40TRUST UNITS
    
    
    41The Trust Indenture
    
    
    41The Trustee
    
    
    41Redemption Right
    
    
    42Voting at Meetings of Pengrowth Trust
    
    
    42Voting at Meetings of Pengrowth Corporation
    
    
    42Termination of Pengrowth Trust
    
    
    42Unitholder Limited Liability
    
    
    43Special Voting Unit
    
    
    43Trust Unit Reclassification
    
    
    43Background
    
    
    43THE ROYALTY INDENTURE
    
    
    48Royalty Units
    
    
    48The Royalty
    
    
    49The Trustee
    
    
    49EXCHANGEABLE SHARES
    
    
    50DISTRIBUTIONS
    
    
    50
 -i-




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##### 



INDUSTRY CONDITIONS
    
    
    51Government Regulation
    
    
    51Pricing and Marketing  Oil
    
    
    51Pricing and Marketing  Natural Gas
    
    
    51Pricing and Marketing  Natural Gas Liquids
    
    
    52The North American Free Trade Agreement
    
    
    52Provincial Royalties and Incentives
    
    
    52Environmental Regulation
    
    
    54MARKET FOR SECURITIES
    
    
    55Class A Trust Units
    
    
    55Class B Trust Units
    
    
    55DIRECTORS AND OFFICERS
    
    
    56Directors and Officers of Pengrowth Management Limited
    
    
    56Principal Holders of Shares of Pengrowth Management
    
    
    56Directors and Officers of the Corporation
    
    
    57Corporate Cease Trade Orders or Bankruptcies
    
    
    58Personal Bankruptcies
    
    
    58Penalties or Sanctions
    
    
    58AUDIT COMMITTEE
    
    
    59Principal Accountant Fees and Services
    
    
    60Pre-approval Policies and Procedures
    
    
    60RISK FACTORS
    
    
    60CONFLICTS OF INTEREST
    
    
    71LEGAL PROCEEDINGS
    
    
    72INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    
    
    72INTERESTS OF EXPERTS
    
    
    72AUDITORS, TRANSFER AGENT AND REGISTRAR
    
    
    72MATERIAL CONTRACTS
    
    
    73CODE OF ETHICS
    
    
    73OFF-BALANCE SHEET ARRANGEMENTS
    
    
    73TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
    
    
    73DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
    
    
    73ADDITIONAL INFORMATION
    
    
    75
 -ii-




---



##### 



APPENDIX A
    
    
    A-1Report On Reserves Data By IndependentQualified Reserves Evaluations On Form 51-101F2APPENDIX B
    
    
    B-1Report Of Management And Directors OnOil And Gas Disclosure On Form 51-101F3APPENDIX C
    
    
    C-1
  Unless otherwise indicated, all of the information provided in this Annual Information Form is as
at December 31, 2005.
 -iii-




---



##### 



GLOSSARY OF TERMS AND ABBREVIATIONS
  Corporate
 
    
    Board of Directorsrefers to the board of directors of the Corporation;
    
    Computersharerefers to Computershare Trust Company of Canada;
    
    Corporationrefers to Pengrowth Corporation, the administrator of the Trust;
    
    Pengrowth, we, usandourrefers to the Trust and the Corporation on a consolidated basis;
    
    Managerrefers to Pengrowth Management Limited, the manager of the Trust and the Corporation;
    
    Reclassificationmeans the reclassification of our outstanding Trust Units as Class
B Trust Units and the conversion of Class B Trust Units held by non-residents of Canada
to Class A Trust Units which occurred on July 27, 2004;
    
    Trustrefers to Pengrowth Energy Trust;
    
    Trust Units, when used in reference to any time before 5:00 p.m. Eastern Daylight
Time on July 27, 2004, refers to the Trust Units of the Trust as they existed before
the Reclassification, and when used in reference to any time after 5:00 p.m. Eastern
Daylight Time on July 27, 2004, refers to the Class A Trust Units and the Class B Trust
Units of the Trust as well as the Trust Units of the Trust that remain as they existed
before the Reclassification; and
    
    Unitholdersrefers to holders of Trust Units issued by the Trust.
 Engineering
 
    
    Company Gross InterestorPengrowth Gross Interestrefers to the Working Interest
share of reserves prior to the deduction of interests owned by others (burdens).
Company Royalty Interest reserves are not included in the Company Gross Interest
reserves;
    
    Company Net InterestorPengrowth Net Interestrefers to Pengrowths Working
Interest share of production or reserves, as the case may be, after the deduction of
royalties and including Company Royalty Interest reserves, and, with respect to land
and wells, refers to Pengrowths Working Interest share therein;
    
    Company Royalty Interestrefers to an interest in production and payment that is
based on the gross production at the wellhead. A royalty is paid in either cash or
kind, but is paid on a value calculated at the wellhead;
    
    Developed Non-Producing Reservesrefers to those reserves that either have not been
on production, or have previously been on production, but are shut-in, and the date of
resumption of production is unknown;
    
    Developed Producing Reservesrefers to those reserves expected to be recovered from
completion intervals open at the time of the estimate. These reserves may be currently
producing or, if shut in, they must have previously been on production and the date of
resumption of production must be known with reasonable certainty;
    
    Developed Reservesrefers to those reserves that are expected to be recovered from
existing wells and facilities or, if facilities have not been installed, that would
involve a low expenditure to put the reserves on production. The developed category may
be subdivided into producing and non-producing;
    
    GLJrefers to GLJ Petroleum Consultants Ltd., independent petroleum consultants,
Calgary, Alberta;
    
    GLJ Reportrefers to the report prepared by GLJ dated February 17, 2006, having an
effective date of December 31, 2005;
 - 1 -




---



##### 




    
    Grosswith respect to production and reserves refers to the total production and
reserves attributable to a property before the deduction of royalties and with respect
to land and wells refers to the total number of acres or wells, as the case may be, in
which Pengrowth has a Working Interest or a royalty interest;
    
    Netrefers to Pengrowths Working Interest share of production or reserves, as the
case may be, after the deduction of royalties, and, with respect to land and wells,
refers to Pengrowths Working Interest share therein;
    
    Pengrowth Company Interestis equal to Company Gross Interest plus Company Royalty
Interest.That is, the Working Interest share of production or reserves prior to the
deduction of interests owned by others (burdens) plus the interest in production made
from gross production or reserves at the wellhead;
    
    Pengrowth Total Proved Plus Probable Reservesmeans Company Interest share of the
Total Proved Plus Probable Reserves;
    
    Probable Reservesrefers to those additional reserves that are less likely to be
recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated proved plus
probable reserves;
    
    Proved Reservesrefers to those reserves that can be estimated with a high degree of
certainty to be recoverable. It is likely that the actual remaining quantities
recovered will exceed the estimated proved reserves;
    
    Reserve Life Indexrefers to the number of years determined by dividing the
aggregate of the reserves of a property by the estimated production per year from such
property using estimated production for the year 2006 as a reference;
    
    Reservesrefers to estimated remaining quantities of oil and natural gas and related
substances anticipated to be recovered from known accumulations, from a given date
forward, based on: (i) analysis of drilling, geological, geophysical and engineering
data; (ii) the use of established technology; and specified economic conditions which
are generally accepted as being reasonable and shall be disclosed. Reserves are
classified according to the degree of certainty associated with the estimate (e.g.,
proved, probable);
    
    Total Proved Plus Probable Reservesmeans the aggregate of Proved Reserves and
Probable Reserves before the deduction of royalties;
    
    Undeveloped Reservesrefers to those reserves expected to be produced from known
accumulations where a significant expenditure (e.g. the cost of drilling a well) is
required to render them capable of production. They must fully meet the requirements of
the reserve classification (proved, probable) to which they are assigned;
    
    Unitizationrefers to a process whereby owners of adjoining properties pool reserves
into a single unit operated by one of the owners, typically in order to conduct
secondary recovery projects in a manner that promotes improved recovery of reserves
from a pool or field; and
    
    Working Interestrefers to the percentage of undivided interest held by Pengrowth in
an oil and gas property.
 Abbreviations
 
    
    APImeans American Petroleum Institute;
    
    bbl, bbls, mbbls, and mmbblsrefers to barrel, barrels, thousands of barrels and
millions of barrels, respectively;
    
    bblpdrefers to barrels per day;
    
    boe, mboe and mmboerefers to barrels of oil equivalent, thousands of barrels of oil
equivalent and millions of barrels of oil equivalent, respectively, on the basis of one
boe being equal to one barrel of oil or NGLs or six mcf of natural gas; barrels of oil
equivalent may be misleading, particularly if used in isolation; a conversion ratio of
6 mcf of natural gas to one boe is based on an energy equivalency
 - 2 -




---



##### 



conversion method primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead;
    
    boepdrefers to barrels of oil equivalent per day;
    
    CBMrefers to coal bed methane;
    
    EORrefers to enhanced oil recovery;
    
    $Mand $MMrefers to thousands of dollars and millions of dollars, respectively;
    
    mmBtuand mmBtupdrefers to million British thermal units and million British
thermal units per day respectively;
    
    mcf, mmcf, bcfand tcfrefers to thousands of cubic feet, millions of cubic feet,
billions of cubic feet and trillions of cubic feet, respectively;
    
    mcfpdand mmcfpdrefers to thousands of cubic feet per day and millions of cubic
feet per day respectively;
    
    NGLsrefers to natural gas liquids;
    
    NYSErefers to the New York Stock Exchange; and
    
    TSXrefers to the Toronto Stock Exchange.
 - 3 -




---



##### 



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
  PRESENTATION OF OUR FINANCIAL INFORMATION
 www.sedar.com www.sec.gov
 PRESENTATION OF OUR RESERVE INFORMATION
 Standards of Disclosure for Oil and Gas
Activities www.sec.gov
 - 4 -




---



##### 



FORWARD-LOOKING STATEMENTS
 Securities Act Private Securities Litigation Reform Act of 1995
    - 5 -




---



##### 



PENGROWTH ENERGY TRUST
    GENERAL DEVELOPMENT OF PENGROWTH TRUST
 Organization and Structure
      Business
 - 6 -




---



##### 



Corporations Act
   
 
 Note:
 (1)
    
    These properties were acquired on May 31, 2004 in an acquisition from Murphy
Oil which had interests in oil and natural gas assets in Alberta and(2)
    
    These
properties were acquired on April29, 2005 in the acquisition of Crispin.
 Business Strategy and Strengths
  - 7 -




---



##### 



Financial
 
    
    Acquisitions should increase future distributions on a per Trust Unit basis based
upon current economics.
    
    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.
    
    The oil and gas producing properties to be acquired should, in the context of the
market, have an attractive rate of return.
 Operational
 
    
    Properties to be acquired should be high quality, relatively long life and proven
producing properties. The Corporation 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
    
    relatively long reserve life;o
    
    potential synergies with our current properties and areas of our core expertise; ando
    
    low environmental and site remediation risk.
 Independent Verification
 
    
    Each purchase of new properties will be based on an independent engineering report
except for properties where the purchase price is less than $5 million.
  Historical Development
  - 8 -




---



##### 



- 9 -




---



##### 



Business Corporations Act
    - 10 -




---



##### 



Recent Acquisitions, Financings and Developments
 2006 Forecast Capital, Production and Operating Costs
    PLANNED CAPITAL EXPENDITURES
    
    $ MILLIONS
    
    % OF TOTALDrilling expenditures
    
    
    131
    
    
    
    56Facilities and maintenance
    
    
    64
    
    
    
    27Land and seismic
    
    
    21
    
    
    
    9Recompletions and workovers
    
    
    12
    
    
    
    5Other
    
    
    8
    
    
    
    3TOTAL
    
    
    236
    
    
    
    100Average daily production volume (boepd)
    
    
    54,000 -
56,000(1)Operating costs per boe
    
    
    $
11.00(2)
 Notes:
 1.
    
    After the divestiture of approximately 1,300 boepd of production in the first quarter of 2006
comprised of volumes associated with previously disclosed purchase and sale agreements, as
well as the divestment of approximately 1,000 boepd of production related to the Monterey
transactions announced on January 12, 2006. The 2006 estimate excludes potential additions
through acquisition.2.
    
    Assuming the production targets for 2006 are achieved.
 Borrowing and Note Payable
  U.K. 10 Year Term Notes
  - 11 -




---



##### 



Crispin Acquisition
 Business Corporations Act
 Monterey Transaction
   Formation of Special Committee to Examine Dual Class Structure
 Tax Act
   Trends
    - 12 -




---



##### 



PENGROWTH MANAGEMENT LIMITED
 Business
  Management Agreement
   
    
    two distinct 3-year terms with a declining fee structure in the second 3-year term;
    
    a base fee determined on a sliding scale:
 o
    
    in the first three-year contract term:
 §
    
    2 percent of the first $200 million of Income; and§
    
    1 percent of the balance of Income over $200 million; and
 o
    
    in the second three-year contract term:
 §
    
    1.5 percent of the first $200 million of Income; and§
    
    0.5 percent of the balance of Income over $200 million.
  
    
    a performance based fee based on total returns received by Unitholders which
essentially compensates the Manager for total annual returns which average in excess of
8 percent per annum over a 3-year period;
 - 13 -




---



##### 




    
    a ceiling on total fees payable determined in reference to a percentage of the fees
paid under the previous management agreement: 80 percent each year in the first
three-year contract term and 60 percent each year in the second three-year contract
term and subject to a further ceiling essentially equivalent to $12 million annually
during the second three-year contract term;
    
    requirement for the Manager to pay certain expenses of the Corporation and the Trust
of approximately $2 million per year;
    
    an annual minimum management fee of $3.6 million comprised of $1.6 million of
management fees and $2.0 million of expenses;
    
    key man provisions in respect of James S. Kinnear, the President of the Manager;
    
    an annual bonus pool based on 10 percent of the Managers base fee and performance
fee for employees of, and special consultants to, the Corporation; and
    
    an optional buyout of the Management Agreement at the election of the Board of
Directors upon the expiry of the first three-year contract term with a termination
payment of approximately 2/3 of the management fee paid during the first three-year
contract term plus expenses of termination.
  
    
    reviewing and negotiating acquisitions for the Corporation and the Trust;
    
    providing written reports to the Board of Directors to keep the Corporation fully
informed about the acquisition, exploration, development, operation and disposition of
properties, the marketing of petroleum substances, risk management practices and
forecasts as to market conditions;
    
    supervising the Corporation in connection with it acting as operator of certain of
its properties;
    
    arranging for, and negotiating on behalf of, and in the name of, the Corporation all
contracts with third parties for the proper management and operation of the properties
of the Corporation;
    
    supervising, training and providing leadership to the employees and consultants of
the Corporation and assisting in recruitment of key employees of the Corporation;
    
    arranging for professional services for the Corporation and the Trust;
    
    arranging for borrowings by the Corporation and equity issuances by the Trust; and
    
    conducting general Unitholder services, including investor relations, maintaining
regulatory compliance, providing information to Unitholders in respect of material
changes in the business of the Corporation or the Trust and all other reports required
by law, and calling, holding and distributing material in respect of meetings of
Unitholders and holders of royalty units.
  Management Fee
  - 14 -




---



##### 



Bonus Pool
  Management Agreement Second Term
    
    
    The amount of the termination fee payable to the Manager on termination of the
Management Agreement effective June 30, 2006;
    
    The estimated cost of internal management to June 30, 2009 in the event of a termination
of the Management Agreement effective June 30, 2006;
    
    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 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 ending 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.
  PENGROWTH CORPORATION  OPERATIONAL INFORMATION
  - 15 -




---



##### 



Principal Properties
    Summary of Property Interests Held by Pengrowth Corporation as at December 31, 2005 (3)  Forecast Prices and Costs
 Company Interest
    
    
    
    
    
    2005 ActualRemaining
    
    Reserve Life
    
    Total Proved Plus
    
    Value at
    
    Oil EquivalentReserve Life
    
    Index
    
    Probable Reserves(2)
    
    10% Discount
    
    Production(2)(Years)
    
    (Years)
    
    (Mboe)
    
    ($million)
    
    (boepd)Judy Creek BHL Unit
    
    
    50
    
    
    
    11.9
    
    
    
    36,820
    
    
    
    538.1
    
    
    
    8,847Swan Hills Unit No.1
    
    
    50
    
    
    
    21.1
    
    
    
    19,903
    
    
    
    196.5
    
    
    
    2,481Weyburn Unit
    
    
    50
    
    
    
    18.6
    
    
    
    19,253
    
    
    
    186.1
    
    
    
    2,649SOEP
    
    
    11
    
    
    
    5.7
    
    
    
    15,241
    
    
    
    346.1
    
    
    
    7,075Judy Creek West BHL Unit
    
    
    50
    
    
    
    23.1
    
    
    
    9,160
    
    
    
    81.1
    
    
    
    1,415Monogram Gas Unit
    
    
    36
    
    
    
    8.7
    
    
    
    6,265
    
    
    
    120.6
    
    
    
    2,517McLeod River
    
    
    50
    
    
    
    7.3
    
    
    
    5,480
    
    
    
    92.5
    
    
    
    2,321East Bodo
    
    
    50
    
    
    
    28.3
    
    
    
    5,252
    
    
    
    31.5
    
    
    
    542Dunvegan Gas Unit No. 1
    
    
    39
    
    
    
    9.3
    
    
    
    5,154
    
    
    
    72.6
    
    
    
    1,442Twining
    
    
    45
    
    
    
    10.3
    
    
    
    4,390
    
    
    
    63.9
    
    
    
    1,360Kaybob Notikewin Unit No. 1
    
    
    40
    
    
    
    12.8
    
    
    
    4,366
    
    
    
    53.6
    
    
    
    1,048Tangleflags
    
    
    18
    
    
    
    6.8
    
    
    
    4,344
    
    
    
    22.8
    
    
    
    1,806Oak
    
    
    50
    
    
    
    10.9
    
    
    
    4,030
    
    
    
    70.4
    
    
    
    1,014Quirk Creek
    
    
    35
    
    
    
    11.9
    
    
    
    3,574
    
    
    
    42.7
    
    
    
    807Princess
    
    
    50
    
    
    
    9.0
    
    
    
    3,556
    
    
    
    65.1
    
    
    
    796Enchant
    
    
    50
    
    
    
    15.3
    
    
    
    3,270
    
    
    
    37.1
    
    
    
    684Rigel
    
    
    21
    
    
    
    6.7
    
    
    
    3,150
    
    
    
    73.4
    
    
    
    1,625Other(1)
    
    
    50
    
    
    
    8.9
    
    
    
    66,188
    
    
    
    1,110.4
    
    
    
    20,928Total
    
    
    50
    
    
    
    10.5
    
    
    
    219,396
    
    
    
    3,204.5
    
    
    
    59,357
 Notes:
 1.
    
    Other includes the Corporations working and royalty interest in approximately 100 other
properties.
2. Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of natural
gas being equal to one boe.3.
    
    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.
 Judy Creek Beaverhill Lake Unit and Judy Creek West Beaverhill Lake Unit
  - 16 -




---



##### 



Development Activity
   2
  Swan Hills Unit No. 1
  Development Activity
   2
 - 17 -




---



##### 



Weyburn Unit
 2
 Development Activity
 2 2 2 2
 2 2
 Sable Offshore Energy Project
   Development Activity
   Monogram Gas Unit
  - 18 -




---



##### 



Development Activity
  McLeod River
   Development Activity
  Bodo/Cactus Lake/Plover
   Development Activity
    - 19 -




---



##### 



Dunvegan Gas Unit No. 1
  Development Activity
  Twining
   Development Activity
   Kaybob Notikewin No. 1
  Development Activity
  - 20 -




---



##### 



Tangleflags
   Development Activity
  Oak
    Development Activity
  Quirk Creek
   - 21 -




---



##### 



Development Activity
  Princess
  Development Activity
  Enchant
    Development Activity
  Rigel
   - 22 -




---



##### 



Development Activity
  Reserves
   All evaluations 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
  a.
    
    analysis of drilling, geological, geophysical and engineering data;b.
    
    the use of established technology; andc.
    
    specified economic conditions.
  a.
    
    Proved Reserves are those reserves that can be estimated with a high degree of
certainty to be recoverable. It is likely that the actual remaining quantities
recovered will exceed the estimated proved reserves.b.
    
    Probable Reserves are those additional reserves that are less certain to be
recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated proved plus
probable reserves.
  - 23 -




---



##### 




    
    at least a 90 percent probability that the quantities actually recovered will equal or
exceed the estimated proved reserves; and
    
    at least a 50 percent probability that the quantities actually recovered will equal or
exceed the sum of the estimated proved plus probable reserves.
     a.
    
    the GLJ Report does not estimate general and administrative expenses, interest,
management fees and holdbacks;b.
    
    the GLJ Report does not estimate all abandonment or any reclamation
liabilities;c.
    
    for purposes of calculating distributable income, the Trust amortizes the cost
of miscible flood injection fluids purchased from third parties over the period of
expected future economic benefit arising from the injection of those fluids, which had
been 30 months and was revised to 24 months for 2005 onward. The GLJ Report includes
the full cost of purchased injection fluids ($34.7 million in 2005) in operating costs
in the year incurred; andd.
    
    the Corporation withholds certain amounts from distributable cash to fund
capital.
  - 24 -




---



##### 



SUMMARY OF OIL AND GAS RESERVES
 AND NET PRESENT VALUES OF FUTURE NET REVENUE
 as of December 31, 2005
 CONSTANT PRICES AND COSTS
 OIL AND GAS RESERVESLight and Medium Oil
    
    Heavy Oil
    
    Natural GasPengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    PengrowthCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (bcf)
    
    (bcf)
    
    (bcf)Proved ReservesProved Developed Producing
    
    
    59,164
    
    
    
    58,988
    
    
    
    50,539
    
    
    
    10,860
    
    
    
    10,853
    
    
    
    9,627
    
    
    
    368.0
    
    
    
    360.2
    
    
    
    290.8Proved Developed Non-Producing
    
    
    368
    
    
    
    368
    
    
    
    311
    
    
    
    62
    
    
    
    62
    
    
    
    57
    
    
    
    24.5
    
    
    
    24.1
    
    
    
    18.5Proved Undeveloped
    
    
    18,761
    
    
    
    18,748
    
    
    
    15,574
    
    
    
    1,673
    
    
    
    1,673
    
    
    
    1,402
    
    
    
    31.2
    
    
    
    29.3
    
    
    
    24.2Total Proved Reserves
    
    
    78,292
    
    
    
    78,104
    
    
    
    66,424
    
    
    
    12,595
    
    
    
    12,588
    
    
    
    11,086
    
    
    
    423.7
    
    
    
    413.6
    
    
    
    333.5Probable Reserves
    
    
    21,361
    
    
    
    21,324
    
    
    
    17,820
    
    
    
    3,118
    
    
    
    3,117
    
    
    
    2,651
    
    
    
    94.4
    
    
    
    91.1
    
    
    
    72.7Total Proved Plus Probable Reserves
    
    
    99,653
    
    
    
    99,427
    
    
    
    84,245
    
    
    
    15,713
    
    
    
    15,705
    
    
    
    13,737
    
    
    
    518.1
    
    
    
    504.7
    
    
    
    406.2
 OIL AND GAS RESERVESNatural Gas Liquids
    
    Total Oil Equivalent BasisPengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    PengrowthCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)Proved ReservesProved Developed Producing
    
    
    13,660
    
    
    
    13,478
    
    
    
    9,377
    
    
    
    145,010
    
    
    
    143,348
    
    
    
    118,007Proved Developed Non-Producing
    
    
    642
    
    
    
    633
    
    
    
    462
    
    
    
    5,149
    
    
    
    5,071
    
    
    
    3,920Proved Undeveloped
    
    
    1,157
    
    
    
    1,106
    
    
    
    821
    
    
    
    26,788
    
    
    
    26,419
    
    
    
    21,834Total Proved Reserves
    
    
    15,459
    
    
    
    15,217
    
    
    
    10,660
    
    
    
    176,948
    
    
    
    174,838
    
    
    
    143,761Probable Reserves
    
    
    3,631
    
    
    
    3,552
    
    
    
    2,604
    
    
    
    43,839
    
    
    
    43,180
    
    
    
    35,193Total Proved Plus Probable Reserves
    
    
    19,090
    
    
    
    18,768
    
    
    
    13,264
    
    
    
    220,788
    
    
    
    218,019
    
    
    
    178,954
 NET PRESENT VALUES OF FUTURE NET REVENUECONSTANT PRICES AND COSTS BEFORE INCOME TAXESReserves
Category
    
    DISCOUNTED AT (%/YEAR)0% ($MM)
    
    5% ($MM)
    
    10% ($MM)
    
    15% ($MM)
    
    20% ($MM)Proved ReservesProved Developed Producing
    
    
    4,745.1
    
    
    
    3,568.7
    
    
    
    2,896.0
    
    
    
    2,460.1
    
    
    
    2,153.1Proved Developed Non-Producing
    
    
    183.2
    
    
    
    134.0
    
    
    
    106.0
    
    
    
    87.7
    
    
    
    74.8Proved Undeveloped
    
    
    770.4
    
    
    
    499.3
    
    
    
    342.5
    
    
    
    243.7
    
    
    
    177.4Total Proved Reserves
    
    
    5,698.7
    
    
    
    4,202.0
    
    
    
    3,344.5
    
    
    
    2,791.5
    
    
    
    2,405.3Probable Reserves
    
    
    1,587.6
    
    
    
    904.8
    
    
    
    608.7
    
    
    
    449.6
    
    
    
    351.6Total Proved Plus Probable Reserves
    
    
    7,286.3
    
    
    
    5,106.8
    
    
    
    3,953.2
    
    
    
    3,241.1
    
    
    
    2,756.9
 - 25 -




---



##### 



TOTAL FUTURE NET REVENUE
 (UNDISCOUNTED)
 as of December 31, 2005
 CONSTANT PRICES AND COSTS
 FUTURE NETCAPITAL
    
    
    
    
    
    REVENUEOPERATING
    
    DEVELOPMENT
    
    ABANDONMENT
    
    BEFOREREVENUE
    
    ROYALTIES
    
    COSTS
    
    COSTS
    
    COSTS(1)
    
    INCOME TAXReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    10,453
    
    
    
    1,988
    
    
    
    2,348
    
    
    
    318
    
    
    
    99
    
    
    
    5,699Total Proved Plus Probable Reserves
    
    
    13,082
    
    
    
    2,523
    
    
    
    2,791
    
    
    
    379
    
    
    
    101
    
    
    
    7,286
 
 Note:
 1.
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See page
37 Abandonment & Reclamation Costs. FUTURE NET REVENUE
 BY PRODUCTION GROUP
 as of December 31, 2005
 CONSTANT PRICES AND COSTS
 FUTURE NET REVENUEPRODUCTION GROUP
    
    BEFORE INCOME TAXESReserves Category
    
    
    
    (discounted at 10% yr) ($M)Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other
by-products) (1)
    
    
    1,666,575Heavy Oil (including solution gas and other by-products)(1)
    
    
    122,962Natural Gas (including by-products but excluding solution gas from oil
wells) (2)
    
    
    1,554,956Total Proved Plus Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products)
(1)
    
    
    1,977,086Heavy Oil (including solution gas and other by-products) (1)
    
    
    148,256Natural Gas (including by-products but excluding solution gas from oil
wells) (2)
    
    
    1,827,831
 
 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. 
 - 26 -




---



##### 



SUMMARY OF OIL AND GAS RESERVES
 AND NET PRESENT VALUES OF FUTURE NET REVENUE
 as of December 31, 2005
 FORECAST PRICES AND COSTS
 OIL AND GAS RESERVESLight and Medium Oil
    
    Heavy Oil
    
    Natural GasPengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    PengrowthCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (bcf)
    
    (bcf)
    
    (bcf)Proved ReservesProved Developed Producing
    
    
    58,219
    
    
    
    58,060
    
    
    
    49,693
    
    
    
    10,924
    
    
    
    10,916
    
    
    
    9,621
    
    
    
    366.2
    
    
    
    358.5
    
    
    
    289.4Proved Developed Non-Producing
    
    
    365
    
    
    
    365
    
    
    
    308
    
    
    
    62
    
    
    
    62
    
    
    
    57
    
    
    
    24.3
    
    
    
    23.9
    
    
    
    18.4Proved Undeveloped
    
    
    18,768
    
    
    
    18,755
    
    
    
    15,991
    
    
    
    1,699
    
    
    
    1,699
    
    
    
    1,420
    
    
    
    30.8
    
    
    
    29.0
    
    
    
    23.9Total Proved Reserves
    
    
    77,351
    
    
    
    77,179
    
    
    
    65,992
    
    
    
    12,684
    
    
    
    12,677
    
    
    
    11,098
    
    
    
    421.3
    
    
    
    411.4
    
    
    
    331.7Probable Reserves
    
    
    21,332
    
    
    
    21,296
    
    
    
    17,937
    
    
    
    3,106
    
    
    
    3,104
    
    
    
    2,616
    
    
    
    94.3
    
    
    
    91.0
    
    
    
    72.6Total Proved Plus Probable Reserves
    
    
    98,684
    
    
    
    98,476
    
    
    
    83,929
    
    
    
    15,790
    
    
    
    15,781
    
    
    
    13,714
    
    
    
    515.6
    
    
    
    502.4
    
    
    
    404.3
 OIL AND GAS RESERVESNatural Gas Liquids
    
    Total Oil Equivalent BasisPengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    PengrowthCompany
    
    Gross
    
    Net
    
    Company
    
    Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)Proved ReservesProved Developed Producing
    
    
    13,566
    
    
    
    13,385
    
    
    
    9,334
    
    
    
    143,741
    
    
    
    142,103
    
    
    
    116,877Proved Developed Non-Producing
    
    
    637
    
    
    
    628
    
    
    
    460
    
    
    
    5,113
    
    
    
    5,035
    
    
    
    3,893Proved Undeveloped
    
    
    1,139
    
    
    
    1,088
    
    
    
    805
    
    
    
    26,745
    
    
    
    26,376
    
    
    
    22,200Total Proved Reserves
    
    
    15,342
    
    
    
    15,101
    
    
    
    10,600
    
    
    
    175,599
    
    
    
    173,513
    
    
    
    142,970Probable Reserves
    
    
    3,643
    
    
    
    3,564
    
    
    
    2,617
    
    
    
    43,797
    
    
    
    43,138
    
    
    
    35,276Total Proved Plus Probable Reserves
    
    
    18,985
    
    
    
    18,665
    
    
    
    13,218
    
    
    
    219,396
    
    
    
    216,652
    
    
    
    178,246
 NET PRESENT VALUES OF FUTURE NET REVENUEFORECAST PRICES AND COSTS BEFORE INCOME TAXESReserves Category
    
    discounted at (%/year)0% ($MM)
    
    5% ($MM)
    
    10% ($MM)
    
    15% ($MM)
    
    20% ($MM)Proved ReservesProved Developed Producing
    
    
    3,676.7
    
    
    
    2,871.1
    
    
    
    2,401.0
    
    
    
    2,089.9
    
    
    
    1,865.9Proved Developed Non-Producing
    
    
    148.7
    
    
    
    109.2
    
    
    
    87.6
    
    
    
    73.7
    
    
    
    63.8Proved Undeveloped
    
    
    559.9
    
    
    
    347.9
    
    
    
    229.6
    
    
    
    156.7
    
    
    
    108.5Total Proved Reserves
    
    
    4,385.3
    
    
    
    3,328.2
    
    
    
    2,718.2
    
    
    
    2,320.3
    
    
    
    2,038.2Probable Reserves
    
    
    1,308.2
    
    
    
    727.9
    
    
    
    486.3
    
    
    
    359.7
    
    
    
    282.8Total Proved Plus Probable Reserves
    
    
    5,693.5
    
    
    
    4,056.1
    
    
    
    3,204.5
    
    
    
    2,680.0
    
    
    
    2,321.0
 - 27 -




---



##### 



TOTAL FUTURE NET REVENUE
 (UNDISCOUNTED)
 as of December 31, 2005
 FORECAST PRICES AND COSTS
 FUTURE NETCAPITAL
    
    
    
    
    
    REVENUEOPERATING
    
    DEVELOPMENT
    
    ABANDONMENT
    
    BEFOREREVENUE
    
    ROYALTIES
    
    COSTS
    
    COSTS
    
    COSTS(1)
    
    INCOME TAXReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    9,302
    
    
    
    1,712
    
    
    
    2,735
    
    
    
    335
    
    
    
    134
    
    
    
    4,385Total Proved Plus Probable Reserves
    
    
    11,818
    
    
    
    2,186
    
    
    
    3,390
    
    
    
    402
    
    
    
    147
    
    
    
    5,694
 
 Note:
 1.
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See page
37 Abandonment & Reclamation Costs. FUTURE NET REVENUE
 BY PRODUCTION GROUP
 as of December 31, 2005
 FORECAST PRICES AND COSTS
 FUTURE NET REVENUEPRODUCTION GROUP
    
    BEFORE INCOME TAXESReserves Category
    
    
    
    (discounted at 10% yr) ($M)Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other
by-products) (1)
    
    
    1,285,742Heavy Oil (including solution gas and other by-products) (1)
    
    
    138,224Natural Gas (including by-products but excluding solution gas from oil
wells) (2)
    
    
    1,294,222Total Proved Plus Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other
by-products) (1)
    
    
    1,532,149Heavy Oil (including solution gas and other by-products)(1)
    
    
    165,396Natural Gas (including by-products but excluding solution gas from oil
wells) (2)
    
    
    1,506,936
 
 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. 
 - 28 -




---



##### 



SUMMARY OF PRICING ASSUMPTIONS
 as of December 31, 2005
 CONSTANT PRICES AND COSTS
 EXCHANGEOIL
    
    NATURAL GAS
    
    NATURAL GAS LIQUIDS(1)
    
    RATE(2)Edmonton
    
    Cromer
    
    LLB CrudeWTI Cushing
    
    Par Price
    
    Medium
    
    Oil at
    
    AECOOklahoma
    
    400API
    
    29.30API
    
    Hardisty
    
    Gas Price
    
    Propane
    
    Butane
    
    Pentanes PlusYEAR(3)
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/mmbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($US/Cdn)2005(4)
    
    
    61.04
    
    
    
    68.27
    
    
    
    51.84
    
    
    
    39.20
    
    
    
    9.71
    
    
    
    43.69
    
    
    
    50.52
    
    
    
    71.67
    
    
    
    0.8577
 
 Notes:
 1.
    
    FOB Edmonton.2.
    
    The exchange rate used to generate the benchmark reference prices in this table.3.
    
    Information provided as at December 31, 2005.4.
    
    This forecast represents the constant price forecast used by GLJ and is a representation of
posted prices as of December 31, 2005. SUMMARY OF PRICING
 AND INFLATION RATE ASSUMPTIONS
 as of January 1, 2006
 FORECAST PRICES AND COSTS
 INFLATION
    
    EXCHANGEOIL
    
    NATURAL GAS
    
    NATURAL GAS LIQUIDS(1)
    
    RATES(2)
    
    RATE(3)Edmonton Par
    
    Cromer
    
    HardistyWTI Cushing
    
    Price
    
    Medium
    
    Heavy
    
    AECOOklahoma
    
    400API
    
    29.30API
    
    120API
    
    Gas Price
    
    Propane
    
    Butane
    
    Pentanes PlusYear
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/mmbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    (%/Year)
    
    ($US/Cdn)2005(4)
    
    
    56.60
    
    
    
    69.11
    
    
    
    57.07
    
    
    
    34.14
    
    
    
    8.58
    
    
    
    42.55
    
    
    
    51.41
    
    
    
    69.45
    
    
    
    2.20
    %
    
    
    0.8252006
    
    
    57.00
    
    
    
    66.25
    
    
    
    55.75
    
    
    
    33.25
    
    
    
    10.60
    
    
    
    42.50
    
    
    
    49.00
    
    
    
    67.00
    
    
    
    2.00
    %
    
    
    0.8502007
    
    
    55.00
    
    
    
    64.00
    
    
    
    55.25
    
    
    
    32.75
    
    
    
    9.25
    
    
    
    41.00
    
    
    
    47.25
    
    
    
    65.25
    
    
    
    2.00
    %
    
    
    0.8502008
    
    
    51.00
    
    
    
    59.25
    
    
    
    51.25
    
    
    
    32.50
    
    
    
    8.00
    
    
    
    38.00
    
    
    
    43.75
    
    
    
    60.50
    
    
    
    2.00
    %
    
    
    0.8502009
    
    
    48.00
    
    
    
    55.75
    
    
    
    48.25
    
    
    
    32.50
    
    
    
    7.50
    
    
    
    35.75
    
    
    
    41.25
    
    
    
    56.75
    
    
    
    2.00
    %
    
    
    0.8502010
    
    
    46.50
    
    
    
    54.00
    
    
    
    46.75
    
    
    
    32.00
    
    
    
    7.20
    
    
    
    34.50
    
    
    
    40.00
    
    
    
    55.00
    
    
    
    2.00
    %
    
    
    0.8502011
    
    
    45.00
    
    
    
    52.25
    
    
    
    45.25
    
    
    
    33.50
    
    
    
    6.90
    
    
    
    33.50
    
    
    
    38.75
    
    
    
    53.25
    
    
    
    2.00
    %
    
    
    0.8502012
    
    
    45.00
    
    
    
    52.25
    
    
    
    45.25
    
    
    
    33.50
    
    
    
    6.90
    
    
    
    33.50
    
    
    
    38.75
    
    
    
    53.25
    
    
    
    2.00
    %
    
    
    0.8502013
    
    
    46.00
    
    
    
    53.25
    
    
    
    46.00
    
    
    
    34.00
    
    
    
    7.05
    
    
    
    34.00
    
    
    
    39.50
    
    
    
    54.25
    
    
    
    2.00
    %
    
    
    0.8502014
    
    
    46.75
    
    
    
    54.25
    
    
    
    47.00
    
    
    
    34.75
    
    
    
    7.20
    
    
    
    34.75
    
    
    
    40.25
    
    
    
    55.25
    
    
    
    2.00
    %
    
    
    0.8502015
    
    
    47.75
    
    
    
    55.50
    
    
    
    48.00
    
    
    
    35.25
    
    
    
    7.40
    
    
    
    35.50
    
    
    
    41.00
    
    
    
    56.50
    
    
    
    2.00
    %
    
    
    0.8502016
    
    
    48.75
    
    
    
    56.50
    
    
    
    48.75
    
    
    
    36.00
    
    
    
    7.55
    
    
    
    36.25
    
    
    
    41.75
    
    
    
    57.75
    
    
    
    2.00
    %
    
    
    0.850Thereafter
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    +2.0%/yr
    
    
    2.00
    %
    
    
    0.850
 
 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, inflation rate and exchange rate estimated for 2005. - 29 -




---



##### 



RECONCILIATION OF NET RESERVES
 BY PRINCIPAL PRODUCT TYPE
 FORECAST PRICES AND COSTS
 LIGHT AND MEDIUM OIL
    
    NATURAL GAS
    
    NATURAL GAS LIQUIDSNet
    
    
    
    
    
    
    
    
    
    Net
    
    
    
    
    
    
    
    
    
    NetProved
    
    
    
    
    
    
    
    
    
    Proved
    
    
    
    
    
    
    
    
    
    ProvedNet
    
    Net
    
    Plus
    
    Net
    
    Net
    
    Plus
    
    Net
    
    Net
    
    PlusProved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    ProbableFactors
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (bcf)
    
    (bcf)
    
    (bcf)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)December 31, 2004
    
    
    63,572
    
    
    
    16,871
    
    
    
    80,443
    
    
    
    341.4
    
    
    
    74.0
    
    
    
    415.4
    
    
    
    10,974
    
    
    
    2,845
    
    
    
    13,819Extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    13.9
    
    
    
    2.7
    
    
    
    16.6
    
    
    
    492
    
    
    
    78
    
    
    
    570Improved Recovery
    
    
    1,986
    
    
    
    225
    
    
    
    2,211
    
    
    
    1.3
    
    
    
    0.2
    
    
    
    1.5
    
    
    
    309
    
    
    
    (116
    )
    
    
    193Technical Revisions
    
    
    (354
    )
    
    
    (1,107
    )
    
    
    (1,461
    )
    
    
    10.6
    
    
    
    (9.6
    )
    
    
    1.0
    
    
    
    591
    
    
    
    (259
    )
    
    
    332Discoveries
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1.7
    
    
    
    0.4
    
    
    
    2.1
    
    
    
    2
    
    
    
    1
    
    
    
    3Acquisitions
    
    
    7,769
    
    
    
    2,183
    
    
    
    9,952
    
    
    
    15.2
    
    
    
    6.1
    
    
    
    21.3
    
    
    
    260
    
    
    
    73
    
    
    
    333Dispositions
    
    
    (1,174
    )
    
    
    (235
    )
    
    
    (1,409
    )
    
    
    (3.9
    )
    
    
    (1.1
    )
    
    
    (5.0
    )
    
    
    (71
    )
    
    
    (4
    )
    
    
    (75
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (5,807
    )
    
    
    
    
    
    
    (5,807
    )
    
    
    (48.6
    )
    
    
    
    
    
    
    (48.6
    )
    
    
    (1,957
    )
    
    
    
    
    
    
    (1,957
    )December 31, 2005
    
    
    65,992
    
    
    
    17,937
    
    
    
    83,929
    
    
    
    331.6
    
    
    
    72.7
    
    
    
    404.3
    
    
    
    10,600
    
    
    
    2,618
    
    
    
    13,218
 HEAVY OIL
    
    TOTAL OIL EQUIVALENT BASISNet
    
    
    
    
    
    
    
    
    
    NetProved
    
    
    
    
    
    
    
    
    
    ProvedNet
    
    Net
    
    Plus
    
    Net
    
    Net
    
    PlusProved
    
    Probable
    
    Probable
    
    Proved
    
    Probable
    
    ProbableFactors
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)December 31, 2004
    
    
    12,733
    
    
    
    3,065
    
    
    
    15,798
    
    
    
    144,171
    
    
    
    35,114
    
    
    
    179,298Extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,815
    
    
    
    526
    
    
    
    3,341Improved Recovery
    
    
    117
    
    
    
    12
    
    
    
    129
    
    
    
    2,635
    
    
    
    146
    
    
    
    2,781Technical Revisions
    
    
    59
    
    
    
    (471
    )
    
    
    (412
    )
    
    
    2,074
    
    
    
    (3,435
    )
    
    
    (1,370
    )Discoveries
    
    
    71
    
    
    
    9
    
    
    
    80
    
    
    
    348
    
    
    
    87
    
    
    
    435Acquisitions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,561
    
    
    
    3,266
    
    
    
    13,827Dispositions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,888
    )
    
    
    (432
    )
    
    
    (2,320
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (1,882
    )
    
    
    
    
    
    
    (1,882
    )
    
    
    (17,746
    )
    
    
    
    
    
    
    (17,746
    )December 31, 2005
    
    
    11,098
    
    
    
    2,615
    
    
    
    13,714
    
    
    
    142,970
    
    
    
    35,272
    
    
    
    178,246
   - 30 -




---



##### 



PENGROWTH COMPANY INTEREST
 RECONCILIATION OF RESERVES
 ON TOTAL OIL EQUIVALENT BASIS
 FORECAST PRICES AND COSTS
 ProvedProved
    
    Total
    
    PlusProducing
    
    Proved
    
    ProbableReserves
    
    Reserves
    
    Reserves(mboe)
    
    (mboe)
    
    (mboe)December 31, 2004
    
    
    142,353
    
    
    
    175,502
    
    
    
    218,613Exploration and Development
    
    
    2,797
    
    
    
    4,096
    
    
    
    4,898Improved Recovery and Infill Drilling
    
    
    7,386
    
    
    
    3,193
    
    
    
    3,342Revisions
    
    
    6,105
    
    
    
    4,072
    
    
    
    344Acquisitions
    
    
    8,964
    
    
    
    12,699
    
    
    
    16,697Dispositions
    
    
    (2,197
    )
    
    
    (2,296
    )
    
    
    (2,831
    )Production
    
    
    (21,667
    )
    
    
    (21,667
    )
    
    
    (21,667
    )December 31, 2005
    
    
    143,741
    
    
    
    175,599
    
    
    
    219,396
  
    
    The acquisition of Crispin and additional interest in Swan Hills Unit No. 1
accounted for 66 percent of the Total Proved Plus Probable Reserves added in 2005.
    
    New reserves were added from development activity, mainly at Weyburn for infill
drilling and improved recovery, West Pembina for drilling extensions and Gutah, in
northeast British Columbia where reserves for the field could be booked when economics
became favorable. Reserve increases in the Proved Producing category also resulted from
reclassification of Proved Undeveloped reserves primarily for development drilling in
the SOEP South Venture field and infill drilling in the Dunvegan Unit and Princess
shallow gas properties.
    
    Various performance related revisions were made to previous estimates resulting in a
net positive change. The largest revisions to proved reserves occurred at Weyburn
(+1,131 mboe), Twining (+912 mboe), McLeod River (+484 mboe), Quirk Creek (+464 mboe),
SOEP (+464 mboe), Monogram (+461 mboe), Nipisi (+458 mboe), Swan Hills Unit No. 1 (-958
mboe), and Squirrel (-455 mboe).
    
    Numerous small, non-core properties were sold in a disposition program which
concluded late in 2005.
 - 31 -




---



##### 



RECONCILIATION OF CHANGES IN
 NET PRESENT VALUES OF FUTURE NET REVENUE
 DISCOUNTED AT TEN PERCENT PER YEAR
 PROVED RESERVES
CONSTANT PRICES AND COSTS
 PERIOD AND FACTOR
    
    Before Tax 2005 ($M)Estimated Net Present Value at Beginning of Year
    
    
    1,992,385Oil and Gas Sales During the Period Net of Production Costs and Royalties (1)
    
    
    (706,339
    )Net Change due to Prices and Royalties Related to Forecast Production (2)
    
    
    1,450,352Change in Development Costs During the Period (3)
    
    
    165,800Change in Forecast Development Costs (4)
    
    
    (139,485
    )Change Resulting from Extensions, Infill Drilling and Improved Recovery (5)
    
    
    126,767Net Change Resulting from Discoveries (5)
    
    
    8,094Change Resulting from Acquisitions of Reserves (5)
    
    
    195,907Change Resulting from Dispositions of Reserves (6)
    
    
    (26,035
    )Accretion of Discount (7)
    
    
    199,239Net Change in Income Taxes (8)
    
    
    Change Resulting from Technical Reserves Revisions (5)
    
    
    48,218All Other Changes
    
    
    29,592Estimated Net Present Value at End of Year
    
    
    3,344,494
 Notes:
 1.
    
    Excluding general and administrative expenses.2.
    
    The impact of changes in prices and other economic factors on future net revenue.3.
    
    Actual capital expenditures relating to the development and production of oil and gas
reserves.4.
    
    The change in forecast development costs.5.
    
    End of period net present value of the related reserves.6.
    
    Start of period net present value of related reserves.7.
    
    Estimated as 10 percent of the beginning of period net present value.8.
    
    The difference between forecast income taxes at beginning of period and actual taxes for the
period plus forecast income taxes at the end of period. Additional Information Relating to Reserves Data
 Undeveloped Reserves
   Proved Undeveloped Reserves
  - 32 -




---



##### 



2 2
  Probable Undeveloped Reserves
  Future Development Costs
  2006(1)
    
    2007(1)
    
    2008(1)
    
    2009(1)
    
    2010(1)
    
    Remainder(1)
    
    Total(1)
    
    Total(2)Reserve Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
(Constant Prices and Costs)
    
    
    109.5
    
    
    
    62.4
    
    
    
    40.2
    
    
    
    23.4
    
    
    
    14.0
    
    
    
    68.9
    
    
    
    318.4
    
    
    
    246.4Proved Reserves 
(Forecast Prices and Costs)
    
    
    109.5
    
    
    
    63.6
    
    
    
    41.9
    
    
    
    24.9
    
    
    
    15.2
    
    
    
    80.3
    
    
    
    335.4
    
    
    
    255.0Proved & Probable Reserves
(Forecast Prices and Costs)
    
    
    121.1
    
    
    
    75.3
    
    
    
    52.0
    
    
    
    29.9
    
    
    
    20.1
    
    
    
    103.4
    
    
    
    401.8
    
    
    
    300.2
 
 Notes:
 1.
    
    Undiscounted.2.
    
    Discounted at 10 percent.  - 33 -




---



##### 



Finding, Development and Acquisition Costs
 Finding and Development Costs
 2
     2 2
 Acquisitions and Divestitures
     Future Development Capital
  - 34 -




---



##### 



FD&A Costs  Company Interest Reserves
 Proved plusProved
    
    ProbableFD&A Costs Excluding Future Development CapitalExploration and Development Capital Expenditures  $thousands
    
    $
    175,700
    
    
    $
    175,700Exploration and Development Reserve Additions including Revisions  mboe
    
    
    11,361
    
    
    
    8,591Finding and Development Cost  $/boe
    
    $
    15.47
    
    
    $
    20.45Net Acquisition Capital  $thousands
    
    $
    175,100
    
    
    $
    175,100Net Acquisition Reserve Additions  mboe
    
    
    10,403
    
    
    
    13,866Net Acquisition Cost  $/boe
    
    $
    16.83
    
    
    $
    12.63Total Capital Expenditures including Net Acquisitions  $thousands
    
    $
    350,800
    
    
    $
    350,800Reserve Additions including Net Acquisitions  mboe
    
    
    21,764
    
    
    
    22,457Finding Development and Acquisition Cost  $/boe
    
    $
    16.12
    
    
    $
    15.62FD&A Costs Including Future Development CapitalExploration and Development Capital Expenditures  $thousands
    
    $
    175,700
    
    
    $
    175,700Exploration and Development Change in FDC  $thousands
    
    ($
    54,931
    )
    
    ($
    50,749
    )Exploration and Development Capital including Change in FDC  $thousands
    
    $
    120,769
    
    
    $
    124,951Exploration and Development Reserve Additions including Revisions  mboe
    
    
    11,361
    
    
    
    8,591Finding and Development Cost  $/boe
    
    $
    10.63
    
    
    $
    14.54Net Acquisition Capital  $thousands
    
    $
    175,100
    
    
    $
    175,100Net Acquisition FDC  $thousands
    
    $
    17,900
    
    
    $
    24,700Net Acquisition Capital including FDC  $thousands
    
    $
    193,000
    
    
    $
    199,800Net Acquisition Reserve Additions  mboe
    
    
    10,403
    
    
    
    13,866Net Acquisition Cost  $/boe
    
    $
    18.55
    
    
    $
    14.41Total Capital Expenditures including Net Acquisitions  $thousands
    
    $
    350,800
    
    
    $
    350,800Total Change in FDC  $thousands
    
    ($
    37,031
    )
    
    ($
    26,049
    )Total Capital including Change in FDC  $thousands
    
    $
    313,769
    
    
    $
    324,751Reserve Additions including Net Acquisitions  mboe
    
    
    21,764
    
    
    
    22,457Finding Development and Acquisition Cost including FDC  $/boe
    
    $
    14.42
    
    
    $
    14.46
 Other Oil and Gas Information
 Oil and Gas Wells
  - 35 -




---



##### 



PRODUCING
    
    NON-PRODUCINGGross
    
    Net
    
    Gross
    
    NetCrude Oil WellsAlberta
    
    
    1,293
    
    
    
    613
    
    
    
    408
    
    
    
    245British Columbia
    
    
    151
    
    
    
    106
    
    
    
    48
    
    
    
    44Saskatchewan
    
    
    1,078
    
    
    
    283
    
    
    
    193
    
    
    
    84Nova Scotia
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0Natural Gas WellsAlberta
    
    
    2,794
    
    
    
    943
    
    
    
    176
    
    
    
    48British Columbia
    
    
    146
    
    
    
    81
    
    
    
    65
    
    
    
    51Saskatchewan
    
    
    40
    
    
    
    31
    
    
    
    83
    
    
    
    43Nova Scotia
    
    
    18
    
    
    
    1
    
    
    
    0
    
    
    
    0OtherAlberta (1)
    
    
    50
    
    
    
    42
    
    
    
    142
    
    
    
    103British Columbia (1)
    
    
    0
    
    
    
    0
    
    
    
    50
    
    
    
    46Saskatchewan (1)
    
    
    21
    
    
    
    15
    
    
    
    22
    
    
    
    19Total
    
    
    5,591
    
    
    
    2,115
    
    
    
    1,187
    
    
    
    683
 
 Note:
 1.
    
    We cannot classify these wells as either oil or gas. Properties with No Attributed Reserves
  UNPROVED PROPERTIES (acres)Location
    
    Gross
    
    Net
    
    Net Area to Expire(1)Alberta
    
    
    331,085
    
    
    
    198,471
    
    
    
    21,013British Columbia
    
    
    301,302
    
    
    
    139,365
    
    
    
    17,007Saskatchewan
    
    
    55,955
    
    
    
    44,808
    
    
    
    1,160Nova Scotia
    
    
    0
    
    
    
    0
    
    
    
    0Other
    
    
    0
    
    
    
    0
    
    
    
    0TOTAL
    
    
    688,342
    
    
    
    382,644
    
    
    
    39,180
 Note:
 1.
    
    This acreage will expire if we take no action to continue the term through operational or
administrative actions. Taking these actions may or may not cause the land expiry to be
stayed. Unproved Properties
  Forward Contracts
   - 36 -




---



##### 



Abandonment & Reclamation Costs
    FUTURE RECLAMATION, REMEDIATION, DISMANTLING AND ABANDONMENT COSTS
 2006
    
    2007
    
    2008
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment,
Reclamation,
Remediation &
Dismantling
    
    
    14,866
    
    
    
    15,888
    
    
    
    14,154
    
    
    
    995,985
    
    
    
    1,040,893Discounted at 10%
    
    
    14,174
    
    
    
    13,772
    
    
    
    11,154
    
    
    
    107,408
    
    
    
    146,508
 Income Tax
  - 37 -




---



##### 



Costs Incurred
  NATURE OF COST
    
    AMOUNT ($MM)Acquisition CostsProved
    
    
    208.4Unproved
    
    
    18.7Exploration Costs
    
    
    0.0Development Costs
    
    
    204.0Total
    
    
    431.1
 Development Activities
  GROSS
    
    
    NETDevelopment WellsGas
    
    
    209
    
    
    
    73.7Oil
    
    
    70
    
    
    
    15.4Service
    
    
    3
    
    
    
    2.1Dry
    
    
    4
    
    
    
    2.7Total Wells
    
    
    286
    
    
    
    93.9
 Production
 Production Estimates
  PRODUCTIONTotal Proved Constant
    
    Proved Plus Probable ForecastPrices and Costs
    
    Prices and CostsLight and Medium Crude Oil (bblpd)
    
    
    19,799
    
    
    
    20,420Heavy Oil (bblpd)
    
    
    4,892
    
    
    
    5,169Natural Gas (mcfpd)
    
    
    153,257
    
    
    
    156,194Natural Gas Liquids (bblpd)
    
    
    5,489
    
    
    
    5,613Oil Equivalent (boepd)
    
    
    55,723
    
    
    
    57,234
 - 38 -




---



##### 



Production History
  QUARTER ENDEDMarch 31,
    
    June 30,
    
    September 30,
    
    December 31,2005
    
    2005
    
    2005
    
    2005Light Crude OilAverage Daily Oil Production(1) (bblpd)
    
    
    20,443
    
    
    
    20,906
    
    
    
    20,660
    
    
    
    21,179Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    54.42
    
    
    
    56.44
    
    
    
    63.95
    
    
    
    59.40Processing and other income ($/bbl)
    
    
    0.80
    
    
    
    1.03
    
    
    
    1.01
    
    
    
    0.51Royalties ($/bbl)
    
    
    (7.11
    )
    
    
    (9.96
    )
    
    
    (11.03
    )
    
    
    (6.47
    )Amortization of injectants ($/bbl)
    
    
    (2.93
    )
    
    
    (3.13
    )
    
    
    (3.14
    )
    
    
    (3.63
    )Production Costs(2)($/bbl)
    
    
    (11.04
    )
    
    
    (11.44
    )
    
    
    (13.14
    )
    
    
    (14.59
    )Operating Netback ($/bbl)
    
    
    34.14
    
    
    
    32.94
    
    
    
    37.65
    
    
    
    35.22Heavy OilAverage Daily Oil Production(1) (bblpd)
    
    
    6,046
    
    
    
    5,641
    
    
    
    5,405
    
    
    
    5,410Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    24.39
    
    
    
    30.32
    
    
    
    47.74
    
    
    
    31.77Processing and other income ($/bbl)
    
    
    0.99
    
    
    
    0.49
    
    
    
    (0.83
    )
    
    
    0.74Royalties ($/bbl)
    
    
    (2.58
    )
    
    
    (4.75
    )
    
    
    (8.00
    )
    
    
    (2.98
    )Production Costs(2)($/bbl)
    
    
    (18.56
    )
    
    
    (15.88
    )
    
    
    (16.30
    )
    
    
    (11.60
    )Operating Netback ($/bbl)
    
    
    4.24
    
    
    
    10.18
    
    
    
    22.61
    
    
    
    17.93NGLsAverage Daily NGL Production(1) (bblpd)
    
    
    6,345
    
    
    
    5,870
    
    
    
    5,448
    
    
    
    6,710Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    50.48
    
    
    
    50.03
    
    
    
    57.75
    
    
    
    58.46Royalties ($/bbl)
    
    
    (14.07
    )
    
    
    (14.59
    )
    
    
    (20.57
    )
    
    
    (21.29
    )Production Costs(2)($/bbl)
    
    
    (6.88
    )
    
    
    (9.15
    )
    
    
    (10.13
    )
    
    
    (10.05
    )Operating Netback ($/bbl)
    
    
    29.53
    
    
    
    26.29
    
    
    
    27.05
    
    
    
    27.12Natural GasAverage Daily Gas Production(1) (mcfpd)
    
    
    157,491
    
    
    
    153,423
    
    
    
    164,288
    
    
    
    168,862Sales Price (net of hedging gains/losses) ($/mcf)
    
    
    6.84
    
    
    
    7.34
    
    
    
    8.57
    
    
    
    11.97Processing and other income ($/mcf)
    
    
    0.21
    
    
    
    0.44
    
    
    
    0.09
    
    
    
    0.19Royalties ($/mcf)
    
    
    (1.27
    )
    
    
    (1.34
    )
    
    
    (1.47
    )
    
    
    (2.62
    )Production Costs(2)($/mcf)
    
    
    (1.17
    )
    
    
    (1.25
    )
    
    
    (1.40
    )
    
    
    (1.50
    )Operating Netback ($/mcf)
    
    
    4.61
    
    
    
    5.19
    
    
    
    5.79
    
    
    
    8.04
 
 Notes:
   QUARTER ENDEDMarch 31,
    
    June 30,
    
    September 30,
    
    December 31,2005
    
    2005
    
    2005
    
    2005Barrels of Oil EquivalentAverage Daily Production(1) (boepd)
    
    
    59,082
    
    
    
    57,988
    
    
    
    58,894
    
    
    
    61,442Sales Price (net of hedging gains/losses) ($/boe)
    
    
    44.97
    
    
    
    47.79
    
    
    
    56.07
    
    
    
    62.55Processing and other income ($/boe)
    
    
    0.94
    
    
    
    1.58
    
    
    
    0.52
    
    
    
    0.77Royalties ($/boe)
    
    
    (7.63
    )
    
    
    (9.08
    )
    
    
    (10.60
    )
    
    
    (12.02
    )Amortization of injectants ($/boe)
    
    
    (1.01
    )
    
    
    (1.13
    )
    
    
    (1.10
    )
    
    
    (1.25
    )Production Costs (2) ($/boe)
    
    
    (9.57
    )
    
    
    (9.90
    )
    
    
    (10.95
    )
    
    
    (11.24
    )Operating Netback ($/boe)
    
    
    27.70
    
    
    
    29.26
    
    
    
    33.94
    
    
    
    38.81
 
 Notes:
   - 39 -




---



##### 



Production History
  PENGROWTH COMPANY INTEREST PRODUCTION
 Light/Medium Oil
    
    Heavy Oil
    
    Natural Gas
    
    Natural Gas LiquidsAverage
    
    
    
    
    
    Average
    
    
    
    
    
    Average
    
    
    
    
    
    Average
    
    AverageAnnual
    
    Daily
    
    Annual
    
    Daily
    
    Annual
    
    Daily
    
    Annual
    
    Daily
    
    Daily TotalProduction
    
    Production
    
    Production
    
    Production
    
    Production
    
    Production
    
    Production
    
    Production
    
    ProductionYear Ended
    
    (mbbls)
    
    (bblpd)
    
    (mbbls)
    
    (bblpd)
    
    (mmcf)
    
    (mcfpd)
    
    (mbbls)
    
    (bblpd)
    
    (boepd)Dec 31, 1997
    
    
    2,792
    
    
    
    7,650
    
    
    
    
    
    
    
    
    
    
    
    18,744
    
    
    
    51,355
    
    
    
    677
    
    
    
    1,856
    
    
    
    18,140Dec 31, 1998
    
    
    6,094
    
    
    
    16,695
    
    
    
    
    
    
    
    
    
    
    
    21,063
    
    
    
    57,707
    
    
    
    1,220
    
    
    
    3,342
    
    
    
    29,741Dec 31, 1999
    
    
    6,413
    
    
    
    17,570
    
    
    
    
    
    
    
    
    
    
    
    22,445
    
    
    
    61,494
    
    
    
    1,433
    
    
    
    3,927
    
    
    
    31,821Dec 31, 2000
    
    
    6,441
    
    
    
    17,599
    
    
    
    
    
    
    
    
    
    
    
    25,656
    
    
    
    70,098
    
    
    
    1,539
    
    
    
    4,205
    
    
    
    33,581Dec 31, 2001
    
    
    7,200
    
    
    
    19,726
    
    
    
    
    
    
    
    
    
    
    
    33,494
    
    
    
    91,764
    
    
    
    1,919
    
    
    
    5,258
    
    
    
    40,320Dec 31, 2002
    
    
    7,269
    
    
    
    19,914
    
    
    
    
    
    
    
    
    
    
    
    40,775
    
    
    
    111,713
    
    
    
    1,917
    
    
    
    5,252
    
    
    
    43,785Dec 31, 2003
    
    
    8,518
    
    
    
    23,337
    
    
    
    
    
    
    
    
    
    
    
    43,742
    
    
    
    119,842
    
    
    
    2,089
    
    
    
    5,722
    
    
    
    49,033Dec 31, 2004
    
    
    7,619
    
    
    
    20,817
    
    
    
    1,302
    
    
    
    3,558
    
    
    
    52,806
    
    
    
    144,278
    
    
    
    1,933
    
    
    
    5,281
    
    
    
    53,702Dec 31, 2005
    
    
    7,591
    
    
    
    20,799
    
    
    
    2,052
    
    
    
    5,623
    
    
    
    58,786
    
    
    
    161,056
    
    
    
    2,224
    
    
    
    6,093
    
    
    
    59,357
 Replacement of Properties
     Borrowing
  - 40 -




---



##### 



TRUST UNITS
 The Trust Indenture
  Income Tax Act Tax Act
 The Trustee
   - 41 -




---



##### 



Redemption Right
  Voting at Meetings of Pengrowth Trust
    Voting at Meetings of Pengrowth Corporation
 Business
Corporations Act
 Termination of Pengrowth Trust
  - 42 -




---



##### 



a.
    
    a vote may be held only if requested in writing by the holders of not less than
25 percent of the Trust Units, or if the Trust Units have become ineligible for
investment by RRSPs, RRIFs, RESPs and DPSPs;b.
    
    the termination must be approved by extraordinary resolution of the
Unitholders; andc.
    
    a quorum representing five percent of the issued and outstanding Trust Units
must be present or represented by proxy at the meeting at which the vote is taken.
  Unitholder Limited Liability
  Special Voting Unit
  Trust Unit Reclassification
  Background
 Tax Act
 Tax Act
  - 43 -




---



##### 



Tax Act
      - 44 -




---



##### 



Tax Act
      Key Features of the Trust Units
  Class A Trust Units
 
    
    are not subject to any residency restriction;
    
    are subject to a restriction on the number to be issued such that the total number
of issued and outstanding Class A Trust Units will not exceed 99% of the number of
issued and outstanding Class B Trust Units (after an initial implementation period)
(the Ownership Threshold);
 - 45 -




---



##### 




    
    may be converted by a holder at any time into Class B Trust Units provided that the
holder is a resident of Canada and provides a suitable residency declaration;
    
    trade on both the TSX and NYSE; and
    
    have identical rights to voting, distributions and assets of Pengrowth Trust on a
wind-up to the Class B Trust Units.
 Class B Trust Units
 
    
    may not be owned or controlled, directly or indirectly, otherwise than by security
only, by non-residents of Canada;
    
    trade only on the TSX;
    
    may be converted by a holder into Class A Trust Units, provided that the Ownership
Threshold will not be exceeded (see page 11 General Development of Pengrowth Trust -
Recent Acquisitions, Financings and Developments  Conversion of Class B Trust Units
into Class A Trust Units); and
    
    have identical rights to voting, distributions and assets of Pengrowth Trust on a
wind-up to the Class A Trust Units.
 Tax Act Tax Act
 Ownership of Class B Trust Units Restricted
  
    
    The Canadian Depository for Securities Limited (CDS) has been advised that it is
prohibited from holding Class B Trust Units on behalf of non-residents. Pengrowth
Corporation will require participants in the book-based system to provide a participant
declaration on a periodic basis to ensure that no non-resident of Canada owns any Class
B Trust Units;
    
    Depository Trust Company (DTC) is not be permitted to hold Class B Trust Units;
    
    a residency declaration is required for any proposed registered transfer of Class B
Trust Units; and
    
    a residency declaration is required for any proposed conversion of Class A Trust
Units into Class B Trust Units.
  Violations of Ownership Provisions
  - 46 -




---



##### 



Exclusionary Offers
   - 47 -




---



##### 




    
    holders of Class A Trust Units do not have the right to convert Class A Trust Units
to Class B Trust Units where an exclusionary offer is made for the Class B Trust Units
if the offeror is a non-resident of Canada (this would not be a valid offer because a
non-resident is not permitted to hold Class B Trust Units);
    
    where Class B Trust Units are converted to Class A Trust Units upon an exclusionary
offer being made for the Class A Trust Units, those units will be immediately converted
back to Class B Trust Units upon being taken up and paid for to preserve the relative
number of Class A Trust Units and Class B Trust Units outstanding both before and after
the bid (even if the offeror is a non-resident of Canada and Pengrowth will have all of
the remedies described above against such offeror);
    
    if a non-resident acquires 10 percent or more of the outstanding Class A Trust Units
(including Class A Trust Units issued on the conversion of Class B Trust Units) the
non-resident shall not be entitled to vote or receive distributions in respect to all
of such units. These sanctions provide a strong disincentive for a non-resident to
make an exclusionary offer for Class A Trust Units;
    
    if Class A Trust Units or Class B Trust Units are tendered to an exclusionary offer
for the Class B Trust Units or the Class A Trust Units, respectively, the deemed
conversion of such units is delayed until the take-up of the units pursuant to the
offer and not before; and
    
    if an exclusionary offer is withdrawn or expires, or Trust Units that are tendered
to an exclusionary offer are withdrawn, no conversion will occur.
 THE ROYALTY INDENTURE
 Royalty Units
      - 48 -




---



##### 



The Royalty
  a.
    
    operating costs;b.
    
    general and administrative costs;c.
    
    management fees and debt service charges;d.
    
    taxes or other charges payable by the Corporation; ande.
    
    any amounts paid into the reserve.
     The Trustee
   - 49 -




---



##### 



EXCHANGEABLE SHARES
 Tax Act
     DISTRIBUTIONS
  - 50 -




---



##### 



ACTUAL DISTRIBUTIONS PAID OR DECLARED PER TRUST UNIT
(Canadian $)
 2005
    
    2004
    
    2003
    
    2002
    
    2001First Quarter
    
    
    0.69
    
    
    
    0.63
    
    
    
    0.75
    
    
    
    0.41
    
    
    
    1.14Second Quarter
    
    
    0.69
    
    
    
    0.64
    
    
    
    0.67
    
    
    
    0.54
    
    
    
    0.83Third Quarter
    
    
    0.69
    
    
    
    0.67
    
    
    
    0.63
    
    
    
    0.52
    
    
    
    0.63Fourth Quarter
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.63
    
    
    
    0.60
    
    
    
    0.41
   INDUSTRY CONDITIONS
 Government Regulation
  Pricing and Marketing  Oil
  Pricing and Marketing  Natural Gas
  - 51 -




---



##### 



Pricing and Marketing  Natural Gas Liquids
  The North American Free Trade Agreement
   Provincial Royalties and Incentives
   - 52 -




---



##### 



- 53 -




---



##### 



Environmental Regulation
    Alberta
Environmental Protection and Enhancement Act, Environmental Assessment Act (British Columbia)
 - 54 -




---



##### 



MARKET FOR SECURITIES
  Class A Trust Units
 Toronto Stock Exchange
    
    New York Stock ExchangeShare Price Range
    
    
    
    
    
    Share Price RangeHigh
    
    Low
    
    Close
    
    Volume
    
    High
    
    Low
    
    Close
    
    Volume(Canadian $ per trust unit)
    
    (thousands)
    
    (U.S. $ per trust unit)
    
    
    
    
    
    (thousands)2005January
    
    
    26.51
    
    
    
    23.18
    
    
    
    25.76
    
    
    
    484
    
    
    
    21.44
    
    
    
    19.10
    
    
    
    20.75
    
    
    
    6,259February
    
    
    28.29
    
    
    
    25.75
    
    
    
    26.75
    
    
    
    962
    
    
    
    22.94
    
    
    
    20.75
    
    
    
    21.56
    
    
    
    7,330March
    
    
    26.80
    
    
    
    22.15
    
    
    
    24.03
    
    
    
    603
    
    
    
    21.56
    
    
    
    18.11
    
    
    
    20.00
    
    
    
    11,032April
    
    
    26.01
    
    
    
    23.95
    
    
    
    25.30
    
    
    
    684
    
    
    
    20.95
    
    
    
    19.20
    
    
    
    20.17
    
    
    
    6,511May
    
    
    26.39
    
    
    
    24.23
    
    
    
    25.89
    
    
    
    422
    
    
    
    20.79
    
    
    
    19.05
    
    
    
    20.61
    
    
    
    4,307June
    
    
    27.90
    
    
    
    25.75
    
    
    
    27.20
    
    
    
    692
    
    
    
    22.74
    
    
    
    20.62
    
    
    
    22.25
    
    
    
    5,335July
    
    
    28.98
    
    
    
    26.84
    
    
    
    28.55
    
    
    
    634
    
    
    
    23.45
    
    
    
    22.00
    
    
    
    23.40
    
    
    
    4,265August
    
    
    29.39
    
    
    
    26.30
    
    
    
    28.39
    
    
    
    593
    
    
    
    24.20
    
    
    
    21.55
    
    
    
    23.93
    
    
    
    6,025September
    
    
    30.10
    
    
    
    27.38
    
    
    
    29.50
    
    
    
    820
    
    
    
    25.75
    
    
    
    23.05
    
    
    
    25.42
    
    
    
    4,212October
    
    
    29.80
    
    
    
    23.64
    
    
    
    25.58
    
    
    
    687
    
    
    
    25.56
    
    
    
    20.00
    
    
    
    21.75
    
    
    
    8,554November
    
    
    27.85
    
    
    
    24.61
    
    
    
    26.65
    
    
    
    427
    
    
    
    23.74
    
    
    
    20.75
    
    
    
    22.84
    
    
    
    5,448December
    
    
    28.35
    
    
    
    26.51
    
    
    
    27.41
    
    
    
    211
    
    
    
    24.35
    
    
    
    22.95
    
    
    
    23.53
    
    
    
    3,807
 Class B Trust Units
 Toronto Stock ExchangeShare Price RangeHigh
    
    Low
    
    Close
    
    Volume(Canadian $ per trust unit )
    
    (thousands)2005January
    
    
    19.25
    
    
    
    18.24
    
    
    
    18.95
    
    
    
    7,574February
    
    
    19.90
    
    
    
    18.79
    
    
    
    18.88
    
    
    
    10,415March
    
    
    18.80
    
    
    
    16.10
    
    
    
    17.05
    
    
    
    11,230April
    
    
    18.08
    
    
    
    16.37
    
    
    
    17.24
    
    
    
    6,682May
    
    
    17.98
    
    
    
    16.80
    
    
    
    17.50
    
    
    
    6,121June
    
    
    19.01
    
    
    
    17.41
    
    
    
    18.40
    
    
    
    6,566July
    
    
    18.50
    
    
    
    18.95
    
    
    
    18.50
    
    
    
    7,747August
    
    
    19.47
    
    
    
    18.25
    
    
    
    19.45
    
    
    
    7,523September
    
    
    21.26
    
    
    
    19.28
    
    
    
    20.58
    
    
    
    7,467October
    
    
    20.83
    
    
    
    17.27
    
    
    
    18.50
    
    
    
    5,651November
    
    
    21.75
    
    
    
    18.34
    
    
    
    21.35
    
    
    
    6,032Decem ber
    
    
    23.38
    
    
    
    20.87
    
    
    
    22.65
    
    
    
    8,064
 - 55 -




---



##### 



DIRECTORS AND OFFICERS
  Directors and Officers of Pengrowth Management Limited
  Name and Municipality of Residence
    
    Position with Pengrowth Management
    
    Principal OccupationJames S. Kinnear
Calgary, Alberta
    
    President and Director (since 1982)
    
    President,
Pengrowth Management LimitedGordon M. Anderson
Calgary, Alberta
    
    Vice President, Financial Services (since 2001)
Vice President, Treasurer (1998-2001)
Treasurer (1995-1998)
    
    Vice President, Financial Services
Pengrowth Management LimitedCharles V. Selby
Calgary, Alberta
    
    Corporate Secretary (since 1993)
    
    Lawyer, Selby Professional Corporation
Lawyer and Corporate Financial Advisor
  Principal Holders of Shares of Pengrowth Management
  - 56 -




---



##### 



Directors and Officers of the Corporation
  Trust UnitsControlled orName and Municipality of
    
    
    
    
    
    BeneficiallyResidence
    
    Position with Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)(2)James S. Kinnear(7)
Calgary, Alberta
    
    President, Chairman, Director and
Chief Executive Office (since 1988)
    
    President, Pengrowth Management Limited
    
    
    4,051,039Stanley H. Wong(4)(8)
Calgary, Alberta
    
    Director (since 1988)
    
    President, Carbine Resources Ltd. a private
oil and gas producing and engineering
consulting company
    
    
    46,576John B. Zaozirny(5)(6)
Calgary, Alberta
    
    Director (since 1988)
    
    Counsel, McCarthy Tétrault, Barristers and
Solicitors
    
    
    47,362Thomas A. Cumming(3)(5)(6)
Calgary, Alberta
    
    Director (since 2000)
    
    Business Consultant
    
    
    6,678Michael S. Parrett(3)(5)(6)
Aurora, Ontario
    
    Director (since 2004)
    
    Business Consultant
    
    
    4,000Kirby L. Hedrick(3)(4)
Pinedale, Wyoming
    
    Director (since 2005)
    
    Business Consultant
    
    NilA. Terence Poole(3)(5)
Calgary, Alberta
    
    Director (since 2005)
    
    Executive Vice President, Corporate Strategy
and Development, Nova Chemicals Corporation
    
    
    10,000Gordon M. Anderson
Calgary, Alberta
    
    Vice President (since 2001)
Vice President, Treasurer (1997-2001)
Treasurer (1995-1997)
Chief Financial Officer (1991-1998)
    
    Vice President, Financial Services, Pengrowth
Management Limited
    
    
    47,245Charles V. Selby
Calgary, Alberta
    
    Vice President and Corporate
Secretary (since 2005)
Corporate Secretary (since 1993)
    
    Lawyer, Selby Professional Corporation
Lawyer and Corporate Financial Advisor
    
    
    127,970Chris Webster
Calgary, Alberta
    
    Chief Financial Officer (since 2005)
Treasurer (2000  2005)
    
    Chief Financial Officer
Pengrowth Corporation
    
    
    19,348Larry B. Strong
Bragg Creek, Alberta
    
    Vice President, Geosciences
(since 2005)
    
    Vice President, Geosciences
Pengrowth Corporation
    
    
    16,357William G. Christensen
Calgary, Alberta
    
    Vice President, Strategic Planning
and Reservoir Exploitation (since
2005)
    
    Vice President, Strategic Planning and
Reservoir Exploitation
Pengrowth Corporation
    
    
    5,589James E.A. Causgrove
Calgary, Alberta
    
    Vice President, Production and
Operations (since 2005)
    
    Vice President, Production and Operations
Pengrowth Corporation
    
    
    11,330Douglas C. Bowles
Calgary, Alberta
    
    Vice President and Controller
(since March 1, 2006)
Controller (since 2005)
    
    Vice President and Controller
Pengrowth Corporation
    
    
    3,834Peter Cheung
Calgary, Alberta
    
    Treasurer (since 2005)
    
    Treasurer
Pengrowth Corporation
    
    
    4,653
 
 Notes:
 1.
    
    Does not include Class B Trust Units issuable upon the exercise of outstanding Trust Unit
options, Trust Unit rights or deferred entitlement units.2.
    
    As at March 7, 2006.3.
    
    Member of Audit Committee.4.
    
    Member of Reserves Committee.5.
    
    Member of Corporate Governance Committee.6.
    
    Member of the Compensation Committee.7.
    
    In addition, Mr. Kinnear exercises control over 13,152 royalty units which are held by
Pengrowth Management Limited.8.
    
    In addition, Mr. Wong exercises control over 3,288 royalty units held by Carbine Resources
Ltd.
 - 57 -




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##### 



Corporate Cease Trade Orders or Bankruptcies
  (i)
    
    was the subject of a cease trade or similar order or an order that denied the issuer 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 issuer being the subject of a cease trade or similar order or an order that
denied the issuer access to any exemption under securities legislation for a period of more
than 30 consecutive days; or
 (iii)
    
    within a year of that person ceasing to act in that capacity, became bankrupt, made a
proposal under any legislation relating to bankruptcy or insolvency or was subject to or
instituted any proceedings, arrangement or compromise with creditors or had a receiver,
receiver manager or trustee appointed to hold its assets.
 Personal Bankruptcies
  Penalties or Sanctions
  - 58 -




---



##### 



(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: (a) penalties for late filing of insider
reports; and (b) Mr. Selby, the Corporate Secretary of the Corporation, and other directors of
AltaCanada Energy Corp. entered into a settlement agreement in 1998 with the Alberta
Securities Commission in regard to the application of rules governing junior capital pool
companies to drilling expenses assumed by the directors on behalf of the Company; 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
  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
Canadian Investor Protection
Fund, the Alberta Capital Market
Foundation and Western Lakota
Energy Services Inc. Mr.
Cumming is a professional
engineer and holds a Bachelor of
Applied Science degree in
Engineering and Business.Michael S. Parrett
    
    Yes
    
    Yes
    
    Mr. Parrett is currently an
independent consultant providing
advisory service to various
public companies in Canada and
the United States. Mr. Parrett
is a member of the Board of
Fording Inc. and is serving as a
Trustee for Fording Canadian
Coal Trust as well as the
Chairman of Gabriel Resources
Limited. He formerly was
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 is currently the
Executive Vice President,
Corporate Strategy and
Development of Nova Chemicals
Corporation. Prior to assuming
his present position in 2000, he
held various senior management
positions with Nova and other
companies. Mr. Poole brings
extensive senior financial
management, accounting, capital
and debt market experience to
Pengrowth. Mr. Poole received a
Bachelor of Commerce degree from
Dalhousie University and holds a
Chartered Accountant
designation.Kirby L. Hedrick
    
    Yes
    
    Yes
    
    Mr. Hedrick has extensive
engineering and senior
management experience in the
United States and
internationally, retiring in
2000 as Executive Vice
President, Upstream of Phillips
Petroleum. He currently serves
on the board of Noble Energy
Inc. 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.
 - 59 -




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##### 



Principal Accountant Fees and Services
  2005
    
    
    2004Category
    
    $M
    
    
    $MAudit Fees
    
    
    305
    
    
    
    624Audit Related Fees
    
    
    
    
    
    
    Tax Fees
    
    
    104
    
    
    
    102All Other Fees
    
    
    6
    
    
    
    6Total
    
    
    415
    
    
    
    732
 Audit Fees.
 Audit-Related Fees.
 Tax Fees.
 All Other Fees. U.S. Sarbanes Oxley Act
 Pre-approval Policies and Procedures
  de minimis
 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 appearing on page 76 of the Trusts Annual Report 2005.
 - 60 -




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##### 



Our distributions are sensitive to the volatility of crude oil and natural gas prices.
  
    
    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;
    
    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.
  Our distributions are affected by production and development costs and capital expenditures.
   Our actual results will vary from our reserve estimates, and those variations could be material.
  
    
    historical production from the area compared with production rates from similar
producing areas;
    
    the assumed effect of government regulation;
 - 61 -




---



##### 




    
    assumptions about future commodity prices, exchange rates, production and
development costs, capital expenditures, abandonment costs, environmental
liabilities, and applicable royalty regimes;
    
    initial production rates;
    
    production decline rates;
    
    ultimate recovery of reserves;
    
    marketability of production; and
    
    other government levies that may be imposed over the producing life of reserves.
   Our reserves will be depleted over time and our level of distributable cash and the value of our
Trust Units could be reduced if reserves are not replaced.
  Our operation of oil and natural gas wells could subject us to environmental claims and liability.
  We may be unable to successfully compete with other companies in our industry.
  - 62 -




---



##### 



Incorrect assessments of value at the time of acquisitions could adversely affect the value of our
Trust Units and our distributions.
  Our level of debt could have a material adverse effect on our ability to pay distributions to our
Unitholders.
  Loss of our key management and other personnel could impact our business.
  Trust distributions are affected by marketability of production.
  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.
  - 63 -




---



##### 



Our distributions could be adversely affected by unforeseen title defects.
  Fluctuations in foreign currency exchange rates could adversely affect our business.
   Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of
the Corporation.
  Management may have conflicts of interest.
  - 64 -




---



##### 



We may incur material costs to comply with, or as a result of, health, safety and environmental
laws and regulations.
  Lower oil and gas prices increase the risk of write-downs of our oil and gas property investments.
  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.
 Tax Act
  
    
    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 Actequal 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
 - 65 -




---



##### 



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 Unit holders, including non-resident persons and residents of Canada who
are exempt from Part I tax.
    
    The Trust Units would be foreign property for RRSPs, RRIFs DPSPs and other
persons subject to tax under Part XI of the Tax Act.
    
    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 Acton the disposition (or deemed disposition) of such Trust Units.
 Changes to the terms of the Class A Trust Units or to the Class B Trust Units could adversely
affect the market value of either class of Trust Units.
   The ability of investors resident in the United States to enforce civil remedies may be affected
for a number of reasons.
 Securities Act of 1933
 a.
    
    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; orb.
    
    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.
 - 66 -




---



##### 



Our Trust Units are not equivalent to shares.
   You may experience substantial future dilution given that the success of the Trust is dependent
upon raising capital.
  Canadian and United States practices differ in reporting reserves and production.
    You may be required to pay taxes even if you do not receive any cash distributions.
  - 67 -




---



##### 



Unitholders who are United States persons face income tax risks.
  
    
    Because the Trust Units will be publicly traded, the Trust 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 the Trust expects to satisfy the
90 percent requirement at all times, if it fails to satisfy this requirement, it will
be treated as a foreign corporation. If the Trust were treated as a corporation, it
could be a passive foreign investment company or PFIC. Treatment of the Trust as a
PFIC could result in a material reduction in the after-tax return to the Unit holders,
likely causing a substantial reduction in the value of the Trust Units.
    
    A successful U.S. Internal Revenue Service (IRS) contest of the federal income tax
positions we take or have taken may adversely affect the market for our Trust Units.
For example, the IRS could challenge our position that the royalty from the Corporation
should be treated as a non-operating, non-Working Interest. We have not requested a
ruling from the IRS with respect to this or any other matter affecting us other than
relating to the timeliness of our election to be treated as a partnership. The IRS may
adopt positions that differ from the conclusions of our counsel or from the positions
we take or have taken. It may be necessary to resort to administrative or court
proceedings to sustain our counsels conclusions or those positions. A court may not
concur with our counsels conclusions or the positions we take or have taken. Any
contest with the IRS may materially and adversely impact the U.S. federal income tax
consequences to Unitholders and, therefore, the market for our Trust Units and the
price at which they trade. In addition, the costs of any contest with the IRS,
principally legal, accounting and related fees, will be borne by us and indirectly by
the Unitholders.
    
    Tax gain or loss on disposition of Trust Units could be different from expected. If
you sell your Trust Units, you will recognize gain or loss equal to the difference
between the amount realized and your tax basis in the Trust Units. Prior distributions
in excess of the total net taxable income you were allocated, which decreased your tax
basis in the Trust Units, will, in effect, become taxable income to you if the Trust
Units are sold at a price greater than your tax basis in those Trust Units, even if the
price you receive is less than your original cost. A substantial portion of the amount
realized, whether or not representing gain, may be ordinary income to you. Should the
IRS successfully contest some positions we take, you could recognize more gain on the
sale of Trust Units than would be the case under those positions, without the benefit
of decreased income in prior years. Also, if you sell Trust Units, you may incur a tax
liability in excess of the amount of cash you receive from the sale.
    
    We have registered with the IRS as a tax shelter. This may increase the risk of an
IRS audit of us or a Unitholder. The tax laws require that some types of entities
register as tax shelters in response to the perception that they claim tax benefits
that may be unwarranted. As a result, we may be audited by the IRS and tax adjustments
could be made. Any Unitholder owning less than a 1 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.
    
    We will treat each owner of Trust Units as having the same tax benefits without
regard to the specific Trust Units purchased. The IRS may challenge this treatment,
which could adversely affect the value of our Trust Units. Because we cannot match
transferors and transferees of our Trust Units, we will adopt depletion, depreciation
and amortization positions that do not conform with all aspects of final Treasury
regulations. A successful IRS challenge to those positions could adversely affect the
amount of tax benefits available to you. It also could affect the timing of these tax
benefits or the amount of gain from your sale of Trust Units and could have a negative
impact on the value of our Trust Units or result in audit adjustments to your tax
returns.
    
    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. Furthermore, we anticipate
that substantially all of the Trusts gross income will not be qualifying income for
purposes of the rules relating to regulated investment companies.
 - 68 -




---



##### 



Pengrowths distributions may be reduced during periods in which it makes capital expenditures
using cash flow.
  Pengrowths operations are subject to changes in government regulations and obtaining required
regulatory approvals.
   We will become subject to additional rules and regulations of the SEC related to internal controls
for our fiscal year ending December 31, 2006 which we expect will increase our legal and compliance
costs.
  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.
  - 69 -




---



##### 



Delays in business operations could adversely affect the Trusts distributions to Unitholders.
  
    
    restrictions imposed by lenders;
    
    accounting delays;
    
    delays in the sale or delivery of products;
    
    delays in the connection of wells to a gathering system;
    
    blowouts or other accidents;
    
    adjustments for prior periods;
    
    recovery by the operator of expenses incurred in the operation of the properties; or
    
    the establishment by the operator of reserves for these expenses.
  Changes in market-based factors may adversely affect the trading price of the Trust Units.
  The limited liability of the Trusts Unitholders is uncertain.
  The redemption right of Unitholders is limited.
 in specie
 - 70 -




---



##### 



The industry in which Pengrowth operates exposes Pengrowth to potential liabilities that may not be
covered by insurance.
  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.
    - 71 -




---



##### 



LEGAL PROCEEDINGS
  INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    INTERESTS OF EXPERTS
  AUDITORS, TRANSFER AGENT AND REGISTRAR
  - 72 -




---



##### 



MATERIAL CONTRACTS
  1.
    
    Trust Indenture;2.
    
    Royalty Indenture;3.
    
    Unanimous Shareholders Agreement; and4.
    
    Management Agreement.
 www.sedar.com.
 CODE OF ETHICS
 U.S.
Securities Exchange Act of 1934 www.pengrowth.com
   OFF-BALANCE SHEET ARRANGEMENTS
  TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
  DISCLOSURE PURSUANT TO THE REQUIREMENTS
OF THE NEW YORK STOCK EXCHANGE
   - 73 -




---



##### 



www.pengrowth.com. ,
  
    
    The NYSE Listed Company Manual requires that each member of the audit committee be
financially literate and that at least one member of the audit committee have accounting or
related financial management expertise. Pengrowths Audit Committee Charter requires that
all members of the Audit Committee be financially literate; however, it does not require
that any member have accounting or related financial management experience. However, as a
matter of practice, Pengrowths Audit Committee includes a financial expert and thereby
satisfies the NYSE requirement.
    
    The NYSE Listed Company Manual requires the audit committee charter to address the
duties and responsibilities of the committee which must include that the audit committee
must discuss the listed companys earnings press releases, as well as financial information
and earnings guidance provided to analysts and rating agencies. Pengrowths audit committee
charter does not require that the audit committee discuss this type of information before
being released to the public or provided to analysts or rating agencies; however, Pengrowth
has a written Corporate Disclosure Policy and has established a Disclosure Policy Committee
consisting of the CEO, CFO, Manager of Investor Relations and Corporate
Secretary. Pursuant to the Corporate Disclosure Policy, the Disclosure Policy Committee
reviews, and makes determinations in respect of, all new releases issued by Pengrowth, and
the release of information to analysts and investors.
    
    The NYSE Listed Company Manual requires the written charter of the compensation
committee to state that the committee has responsibility to review and approve corporate
goals and objectives relevant to CEO compensation, evaluate the CEOs performance in light
of those goals and objectives and either as a committee or together with the other
independent directors (as directed by the board) determine and approve the CEOs
compensation level based on this evaluation. In Pengrowths structure, the CEO is
compensated through the Management Agreement with Pengrowth Management. The charter for
Pengrowths Compensation Committee recognizes this distinction and
requires the committee to review the performance of the Manager and review and consider the
terms of the Management Agreement, where appropriate to enter into discussions with the
Manager as to amendments or changes to the Management Agreement that are in the interests
of Unitholders and to set annual performance targets and plans in connection therewith.
    
    The NYSE Listed Company Manual requires shareholder approval of all equity compensation
plans and any material revisions to such plans, regardless of whether the security is to be
delivered under such plans are newly issued or purchased on the open market, subject to a
few limited exceptions. In contrast, the TSX rules require shareholder approval of equity
compensation plans only when such plans involve newly issued securities. If the plan
provides a procedure for its amendment, the TSX rules require shareholder approval of
amendments only where the amendment involves a reduction in the exercise price or an
extension of the term of options held by insiders. As a matter or practice, Pengrowth has
obtained the approval of its Unitholders to all of its equity compensation plans,
regardless of whether the Trust Units to be delivered under such plans are newly issued or
purchased on the open market.
    
    The NYSE Listed Company Manual requires that the charters of the nominating/corporate
governance committee, the audit committee and the compensation committee require an annual
performance evaluation of the committee. In addition, the NYSE Listed Company Manual
suggests that an issuers corporate governance guidelines include a requirement for the
board to conduct a self-evaluation at least annually. While Pengrowths charters for these
committees does not require those committees to perform an annual performance evaluation
nor does the Pengrowths Corporate Governance Policy require the board to
 - 74 -




---



##### 



conduct annual self-evaluation, the charter of the Corporate Governance
Committee includes the mandate to assess the effectiveness of the board and its committees.
    
    The NYSE Listed Company Manual requires the written charter of the compensation
committee to provide that the committee must produce a compensation committee report on
executive officer compensation for inclusion in the issuers annual information circular or
annual report. While the Terms of Reference of Pengrowths Compensation Committee does not
require such a report, in accordance with applicable Canadian securities laws Pengrowths
annual Information Circular  Proxy Statement contains a report on executive compensation,
which is reviewed and approved by the Compensation Committee.
    
    The NYSE Listed Company Manual requires the written charter of the audit committee to
provide that the audit committee must prepare a report to be included in the issuers
annual information circular. There is no requirement under Canadian law or under
Pengrowths audit committee charter to prepare such a report, and it is not Pengrowths
current practice to prepare such a report. However, read together, the disclosure
contained in Pengrowths Information Circular  Proxy Statement under the heading Part II
 Corporate Governance, Pengrowths Annual Report under the headings Corporate
Responsibility, Corporate Governance Practices and Structure and Function, and herein
under the heading Audit Committee provides the substance of the disclosure mandated by
the NYSE rule.
 ADDITIONAL INFORMATION
    Investor RelationsPengrowth Energy Trust
    
    Toronto Investor RelationsSuite 2900, 240  4th Ave S.W.
    
    Scotia Plaza, 40 King Street WestCalgary, Alberta T2P 4H4
    
    Suite 3006, Box 106Telephone: (403) 233-0224
    
    Toronto, Ontario M5H 3Y21-800-223-4122
    
    Telephone: (416) 362-1748Fax: (403) 294-0051
    
    1-888-744-1111Fax: (416) 362-8191
 Website:
    
    www.pengrowth.comE-mail:
    
    investorrelations@pengrowth.com
 - 75 -




---



##### 



APPENDIX A
 Report On Reserves Data By Independent
 Qualified Reserves Evaluations On Form 51-101F2
 - 76 -




---



##### 



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, 2005. The
reserves data consist of the following:
 (a)
    
    (i)
    
    proved and proved plus probable oil and gas reserves estimated as at
December 31, 2005, using forecast prices and costs; and(ii)
    
    the related estimated future net revenue; and(b)
    
    (i)
    
    proved oil and gas reserves estimated as at December 31, 2005, using
constant prices and costs; and(ii)
    
    the related estimated future net revenue.
 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, 2005, and identifies the respective
portions thereof that we have audited, evaluated and reviewed and reported on to the Companys
board of directors:
 Location ofLocation ofReservesDescription and
    
    
    (Country orIndependent
    
    Preparation Date of
    
    
    Foreign
    
    
    Net Present Value of Future Net RevenueQualified Reserves
    
    Evaluation
    
    
    Geographic
    
    
    (before income taxes, 10% discount rate - $M)Evaluator
    
    Report
    
    
    Area)
    
    
    Audited
    
    
    Evaluated
    
    
    Reviewed
    
    
    TotalGLJ Petroleum Consultants
    
    January 16, 2006
    
    Canada
    
    
    
    
    
    $
    3,204,481
    
    
    
    
    
    
    $
    3,204,481




---



##### 



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 judgements regarding future events, actual results
will vary and the variations may be material.
   -s- DOUG R. SUTTONDoug R. Sutton, P. Eng.VP Corporate Evaluations




---



##### 



APPENDIX B
 Report Of Management And Directors On
 Oil And Gas Disclosure On Form 51-101F3
 B-1




---



##### 



FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
  (a)
    
    (i)
    
    proved and proved plus probable oil and gas reserves estimated as at December 31, 2005
using forecast prices and costs; and(i)
    
    the related estimated future net revenue; and(b)
    
    (i)
    
    proved oil and gas reserves estimated as at December 31, 2005 using constant prices and
costs; and(i)
    
    the related estimated future net revenue.
   (c)
    
    reviewed the Companys procedures for providing information to the independent qualified
reserves evaluator;(d)
    
    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(e)
    
    reviewed the reserves data with management and the independent qualified reserves evaluator.
  (f)
    
    the content and filing with securities regulatory authorities of the reserves data and other
oil and gas information;(g)
    
    the filing of the report of the independent qualified reserves evaluator on the reserves
data; and(h)
    
    the content and filing of this report.
  B-2




---



##### 



James
S. KinnearJames S. KinnearChairman, President and Chief Executive OfficerPengrowth CorporationWilliam
G. ChristensenWilliam G. ChristensenVice President, Strategic Planning and Reservoir ExploitationPengrowth CorporationStanley
H. WongStanley H. WongDirectorPengrowth CorporationKirby
L. HedrickKirby L. HedrickDirectorPengrowth CorporationMarch 29, 2006
 B-3




---



##### 



APPENDIX C
 Audit Committee Charter
 C-1




---



##### 



CHARTER OF THE AUDIT COMMITTEE OF THE
BOARD OF DIRECTORS OF PENGROWTH CORPORATION (THE COMPANY)
JULY 30, 2001
AND AMENDED AND RESTATED MARCH 28, 2006
 I.
    
    Audit Committee purpose:
  
    
    Monitor the performance of the Companys internal audit function and the integrity
of the Companys financial reporting process and systems of internal controls regarding
finance, accounting, and legal compliance.
    
    Monitor the independence and performance of the Companys external auditors.
    
    Provide an avenue of communication among the external auditors, the internal
auditors, management and the Board of Directors.
  II.
    
    Audit Committee Composition and MeetingsAudit Committee members shall meet the requirements of applicable securities laws and the
stock exchanges on which Pengrowth Energy Trust trades. The Audit Committee shall be
comprised of three or more directors as determined by the Board, each of whom shall be
independent and financially literate, as those terms are defined in Multilateral
Instrument 52-110 Audit Committees of the Canadian Securities Administrators.Audit Committee members shall be appointed by the Board. If an audit committee Chair is not
designated or present, the members of the Committee may designate a Chair by majority vote
of the Committee membership.The Committee shall meet at least four times annually, or more frequently as circumstances
dictate. The Audit Committee Chair shall prepare and/or approve an agenda in advance of
each meeting. The Committee should meet privately in executive sessions at least annually
with management, the internal auditors and the external auditors and as a Committee to
discuss any matters that the Committee, management, the internal auditors or the external
auditors believe should be discussed. In addition, the Committee, or at least its Chair,
should communicate with management, the internal auditors and the external auditors
quarterly to review the Companys financial statements and significant findings based upon
the auditors limited review procedures.III.
    
    Audit Committee Responsibilities and DutiesReview Procedures
 1.
    
    Review and reassess the adequacy of this Charter at least annually. Submit the
Charter to the Board of Directors for approval and have the document published at least
every three years in accordance with SEC regulations.2.
    
    Review the Companys annual audited financial statements, managements
discussion and analysis and annual and interim earnings press releases prior to filing
or public distribution. This review
 C-2




---



##### 



should include discussions with management, the internal auditors and the external
auditors of significant issues regarding accounting principles, practices and
judgements.
 3.
    
    In consultation with management, the internal auditors and the external
auditors, consider the integrity of the Companys financial reporting processes and
controls and the performance of the Companys internal financial accounting staff.
Discuss significant financial risk exposures and the steps management has taken to
monitor, control and report such exposures. Review significant findings prepared by
the internal or external auditors together with managements responses.4.
    
    Review with financial management, the internal auditors and the external
auditors the Companys quarterly financial results and accompanying managements
discussion and analysis prior to the release of earnings and/or the Companys quarterly
financial statements prior to filing or public distribution. Discuss any significant
changes to the Company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) (see item 10).5.
    
    Review with financial management, the internal auditors and the external
auditors the Companys policies relating to risk management and risk assessment.6.
    
    Meet separately with each of management of the Company, the internal auditors
and with 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 of Directors on such meetings.
 Internal Auditors
 7.
    
    Review the annual audit plans of the internal auditors.8.
    
    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 thereto.9.
    
    Review the adequacy of the resources of the internal auditors to ensure the
objectivity and independence of the internal audit function.10.
    
    Consult with management on managements appointment, replacement, reassignment
or dismissal of the internal auditors.11.
    
    Ensure that the internal auditors have access to the Chair, the Chair of the
Board of Directors and the Chief Executive Officer.
 External Auditors
 12.
    
    The external auditors are ultimately accountable to the Audit Committee and the
Board of Directors. The Audit Committee is directly responsible for overseeing the
work of the external auditors, shall review the independence and performance of the
external auditors and shall annually recommend to the Board of Directors 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 Companys internal quality
control procedures; (ii) any material issues raised by the most recent internal quality
control review, or peer review, of the Company, or by an inquiry or investigation by
governmental or professional authorities, within the preceding five years, respecting
one or more independent audits carried out by the Company, and any steps taken to deal
with any such issues; and (iii) all relationships between the independent auditor and
the Company.
 C-3




---



##### 



13.
    
    Approve the fees and other significant compensation to be paid to the external
auditors.14.
    
    Pre-approve all non-audit services to be provided to the Company or its
subsidiary entities by the Companys external auditors.15.
    
    On an annual basis, the Committee should review and discuss with the external
auditors all significant relationships they have with the Company that could impair the
auditors independence.16.
    
    The Committee shall review the external auditors audit plan  discuss scope,
staffing, locations, and reliance upon management and general audit approach.17.
    
    Prior to releasing the year-end earnings, discuss the results of the audit with
the external auditors.18.
    
    Consider the external auditors judgments about the quality and appropriateness
of the Companys accounting principles as applied in its financial reporting.19.
    
    Be responsible for the resolution of disagreements between management and the
external auditors regarding financial performance.
 Other Audit Committee Responsibilities
 20.
    
    Establish procedures for: (i) the receipt, retention and treatment of
complaints received by the Company regarding accounting, internal accounting controls,
or auditing matters; and (ii) the confidential and anonymous submission by employees of
the Company of concerns regarding questionable accounting or auditing matters.21.
    
    Review and approve the Companys hiring policies regarding partners, employees
and former partners and employees of the present and former external auditors of the
Company.22.
    
    On at least an annual basis, review with the Companys counsel, any legal
matters that could have a significant impact on the organizations financial
statements, the Companys compliance with applicable laws and regulations, and
inquiries received from regulators or governmental agencies.23.
    
    Annually prepare a report to shareholders as required by the Securities and
Exchange Commission. The report should be included in the Companys annual proxy
statement.24.
    
    Perform any other activities consistent with this Charter, the Companys
by-laws, and governing law as the Committee or the Board deems necessary or
appropriate.25.
    
    Maintain minutes of meetings and periodically report to the Board of Directors
on significant results of the foregoing activities.
 C-4




---



##### 



APPENDIX B
 MANAGEMENTS DISCUSSION AND ANALYSIS
(INCLUDED ON PAGES 54 THROUGH 80 OF THE PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)




---



##### 



Managements Discussion and Analysis
  Frequently Recurring Terms
  Advisory Regarding Forward-Looking Statements
 Securities Act Private Securities Litigation Reform Act of 1995
 Historical Annual Compound Returns by Year




---



##### 



2




---



##### 



Critical Accounting Estimates
   Non-GAAP Financial Measures
  Conversion and Currency
  Year 2005 Overview




---



##### 



Highlights
 
    
    Oil and gas sales increased 41 percent to $1.15 billion in 2005 resulting in record net
income of $326 million, an increase of 112 percent over 2004.
 
    
    Production for 2005 averaged 59,357 barrels of oil equivalent (boe) per day, an increase of
more than ten percent versus 2004. Fourth quarter production averaged 61,442 boe per day, an
increase of four percent over the previous quarter and seven percent over the comparable
period in 2004.
 
    
    Distributable cash reached a new high in 2005 at $620 million, an increase of 54 percent over
2004. Fourth quarter distributable cash increased 87 percent versus 2004 to $196 million, the
highest level of distributable cash generated in any quarter in Pengrowths history.
 
    
    Distributions paid or declared to unitholders increased 23 percent to $446 million or $2.82
per trust unit in 2005 from $363 million or $2.63 per trust unit in 2004. Pengrowths monthly
distribution was increased in December 2005 to an annualized rate of $3.00 per trust unit.
 
    
    Pengrowths payout ratio to unitholders for the full year and fourth quarter of 2005 reached
record lows of 72 percent and 61 percent of cash generated from operations, respectively.
 
    
    Pengrowths 2005 development expenditures were essentially fully funded through withholdings
from distributable cash.
 
    
    During the year Pengrowth spent a combined total of $176 million on maintenance and
development projects ending the year with proved plus probable (P50) reserves of 219.4 million
barrels of oil equivalent (mmboe) compared to 218.6 mmboe at year end 2004. Pengrowths P50
reserves were replaced through the addition of 16.7 mmboe related to acquisitions and 8.6
mmboe resulting from drilling activity, improved recoveries and technical revisions. Additions
were offset by production of 21.7 mmboe and divestitures of 2.8 mmboe.
 
    
    Pengrowths average realized commodity price (after hedging) increased 28 percent to $53.02
per boe in 2005, from $41.33 in 2004.
 
    
    Operating netbacks increased 33 percent to $32.54 per boe (after hedging) versus $24.51 per
boe in 2004. Combined hedging losses totaled $3.04 per boe in 2005 versus $3.52 per boe in
2004.
 
    
    On February 28, 2005, Pengrowth acquired an additional 11.89 percent working interest in the
Swan Hills property for $87 million. This acquisition increased Pengrowths total interest in
the property to 22.34 percent.
 
    
    On April 29, 2005, Pengrowth successfully completed the acquisition of all of the issued and
outstanding shares of Crispin adding approximately 1,900 boe per day of production to our
portfolio.
 
    
    On December 1, 2005, Pengrowth completed a £50 million private placement of senior unsecured
ten year notes.
 
    
    As at December 31, 2005, Pengrowth had generated a combined three-year weighted average
compound total return of 36 percent per annum for Class A and Class B unitholders.




---



##### 



Summary of Financial and Operating Results
 Three months ended December 31
    
    
    
    Twelve months ended December 31(thousands, except per unit amounts)
    
    
    2005
    
    
    
    2004
    
    
    % Change
    
    
    
    2005
    
    
    
    2004
    
    
    % ChangeINCOME STATEMENTOil and gas sales
    
    
    $
    353,923
    
    
    
    $
    223,183
    (2)
    
    
    59
    
    
    
    $
    1,151,510
    
    
    
    $
    815,751
    (2)
    
    
    41Net income
    
    
    $
    116,663
    
    
    
    $
    31,138
    
    
    
    275
    
    
    
    $
    326,326
    
    
    
    $
    153,745
    
    
    
    112Net income per trust unit
    
    
    $
    0.73
    
    
    
    $
    0.23
    
    
    
    217
    
    
    
    $
    2.08
    
    
    
    $
    1.15
    
    
    
    81Cash generated from operations
    
    
    $
    196,588
    
    
    
    $
    93,287
    
    
    
    111
    
    
    
    $
    618,070
    
    
    
    $
    404,167
    
    
    
    53Cash generated from operations
per trust unit
    
    
    $
    1.23
    
    
    
    $
    0.68
    
    
    
    81
    
    
    
    $
    3.93
    
    
    
    $
    3.03
    
    
    
    30Distributable cash (1)
    
    
    $
    195,879
    
    
    
    $
    104,958
    (2)
    
    
    87
    
    
    
    $
    619,739
    
    
    
    $
    401,178
    (2)
    
    
    54Distributable cash per trust unit (1)
    
    
    $
    1.23
    
    
    
    $
    0.77
    
    
    
    60
    
    
    
    $
    3.94
    
    
    
    $
    3.01
    
    
    
    31Distributions paid or declared
    
    
    $
    119,858
    
    
    
    $
    96,466
    
    
    
    24
    
    
    
    $
    445,977
    
    
    
    $
    363,061
    
    
    
    23Distributions paid or
declared per trust unit
    
    
    $
    0.75
    
    
    
    $
    0.69
    
    
    
    9
    
    
    
    $
    2.82
    
    
    
    $
    2.63
    
    
    
    7Weighted average number of
trust units outstanding
    
    
    
    159,528
    
    
    
    
    136,916
    
    
    
    17
    
    
    
    
    157,127
    
    
    
    
    133,395
    
    
    
    18BALANCE SHEETWorking capital
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (112,205
    )
    
    
    $
    (78,546
    )
    
    
    43Property, plant and equipment
and other assets
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    2,067,988
    
    
    
    $
    1,989,288
    
    
    
    4Long term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    368,089
    
    
    
    $
    345,400
    
    
    
    7Unitholders equity
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    1,475,996
    
    
    
    $
    1,462,211
    
    
    
    1Unitholders equity per trust unit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    9.23
    
    
    
    $
    9.56
    
    
    
    (3
    )Number of trust units
outstanding at year end
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    159,864
    
    
    
    
    152,973
    
    
    
    5DAILY PRODUCTIONCrude oil (barrels)
    
    
    
    21,179
    
    
    
    
    20,118
    
    
    
    5
    
    
    
    
    20,799
    
    
    
    
    20,817
    
    
    
    0Heavy oil (barrels)
    
    
    
    5,410
    
    
    
    
    5,819
    
    
    
    (7
    )
    
    
    
    5,623
    
    
    
    
    3,558
    
    
    
    58Natural gas (mcf)
    
    
    
    168,862
    
    
    
    
    156,621
    
    
    
    8
    
    
    
    
    161,056
    
    
    
    
    144,277
    
    
    
    12Natural gas liquids (barrels)
    
    
    
    6,710
    
    
    
    
    5,385
    
    
    
    25
    
    
    
    
    6,093
    
    
    
    
    5,281
    
    
    
    15Total production (boe)
    
    
    
    61,442
    
    
    
    
    57,425
    
    
    
    7
    
    
    
    
    59,357
    
    
    
    
    53,702
    
    
    
    10Total production (mboe)
    
    
    
    5,653
    
    
    
    
    5,283
    
    
    
    7
    
    
    
    
    21,665
    
    
    
    
    19,655
    
    
    
    10PRODUCTION PROFILECrude oil
    
    
    
    34
    %
    
    
    
    35
    %
    
    
    
    
    
    
    
    35
    %
    
    
    
    39
    %Heavy oil
    
    
    
    9
    %
    
    
    
    10
    %
    
    
    
    
    
    
    
    10
    %
    
    
    
    6
    %Natural gas
    
    
    
    46
    %
    
    
    
    46
    %
    
    
    
    
    
    
    
    45
    %
    
    
    
    45
    %Natural gas liquids
    
    
    
    11
    %
    
    
    
    9
    %
    
    
    
    
    
    
    
    10
    %
    
    
    
    10
    %AVERAGE REALIZED PRICES(AFTER HEDGING)Crude oil (per barrel)
    
    
    $
    59.40
    
    
    
    $
    44.76
    
    
    
    33
    
    
    
    $
    58.59
    
    
    
    $
    43.21
    
    
    
    36Heavy oil (per barrel)
    
    
    $
    31.77
    
    
    
    $
    26.99
    
    
    
    18
    
    
    
    $
    33.32
    
    
    
    $
    32.45
    
    
    
    3Natural gas (per mcf)
    
    
    $
    11.97
    
    
    
    $
    7.02
    
    
    
    71
    
    
    
    $
    8.76
    
    
    
    $
    6.80
    
    
    
    29Natural gas liquids (per barrel)
    
    
    $
    58.46
    
    
    
    $
    48.04
    
    
    
    22
    
    
    
    $
    54.22
    
    
    
    $
    42.21
    
    
    
    28Average realized price per boe
    
    
    $
    62.55
    
    
    
    $
    42.08
    (2)
    
    
    49
    
    
    
    $
    53.02
    
    
    
    $
    41.33
    (2)
    
    
    28PROVED PLUS PROBABLE RESERVESCrude oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    98,684
    
    
    
    
    94,066
    
    
    
    5Heavy oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    15,790
    
    
    
    
    18,245
    
    
    
    (13
    )Natural gas (bcf)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    516
    
    
    
    
    521
    
    
    
    (1
    )Natural gas liquids (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18,985
    
    
    
    
    19,395
    
    
    
    (2
    )Total oil equivalent (mboe)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    219,396
    
    
    
    
    218,613
    
    
    
    0
 (1)See the section entitled Non-GAAP Financial Measures(2)Restated to conform to presentation
adopted in the current year




---



##### 



Results of Operations
 Production
  Daily Production
 Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Light crude oil (bbls) (1)
    
    
    
    21,179
    
    
    
    
    20,660
    
    
    
    
    20,118
    
    
    
    
    20,799
    
    
    
    
    20,817Heavy oil (bbls) (1)
    
    
    
    5,410
    
    
    
    
    5,405
    
    
    
    
    5,819
    
    
    
    
    5,623
    
    
    
    
    3,558Natural gas (mcf)
    
    
    
    168,862
    
    
    
    
    164,288
    
    
    
    
    156,621
    
    
    
    
    161,056
    
    
    
    
    144,277Natural gas liquids (bbls) (1)
    
    
    
    6,710
    
    
    
    
    5,448
    
    
    
    
    5,385
    
    
    
    
    6,093
    
    
    
    
    5,281Total boe per day
    
    
    
    61,442
    
    
    
    
    58,894
    
    
    
    
    57,425
    
    
    
    
    59,357
    
    
    
    
    53,702
 (1)bbls refers to barrels




---



##### 



Pricing and Commodity Price Hedging
  Average Realized Prices
 (Cdn$)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Light crude oil (per bbl)
    
    
    
    67.00
    
    
    
    
    74.37
    
    
    
    
    55.24
    
    
    
    
    65.47
    
    
    
    
    50.72after hedging
    
    
    
    59.40
    
    
    
    
    63.95
    
    
    
    
    44.76
    
    
    
    
    58.59
    
    
    
    
    43.21Heavy oil (per bbl)
    
    
    
    31.77
    
    
    
    
    47.74
    
    
    
    
    26.99
    
    
    
    
    33.32
    
    
    
    
    32.45Natural gas (per mcf)
    
    
    
    12.80
    
    
    
    
    8.69
    
    
    
    
    7.25
    
    
    
    
    8.99
    
    
    
    
    7.03after hedging
    
    
    
    11.97
    
    
    
    
    8.57
    
    
    
    
    7.02
    
    
    
    
    8.76
    
    
    
    
    6.80Natural gas liquids (per bbl)
    
    
    
    58.46
    
    
    
    
    57.75
    
    
    
    
    48.04
    
    
    
    
    54.22
    
    
    
    
    42.21Total per boe
    
    
    
    67.43
    
    
    
    
    60.06
    
    
    
    
    46.38
    (3)
    
    
    
    56.06
    
    
    
    
    44.85
    (3)after hedging
    
    
    
    62.55
    
    
    
    
    56.07
    
    
    
    
    42.08
    (3)
    
    
    
    53.02
    
    
    
    
    41.33
    (3)Benchmark PricesWTI oil (U.S. $  per bbl)
    
    
    
    60.05
    
    
    
    
    63.31
    
    
    
    
    48.27
    
    
    
    
    56.70
    
    
    
    
    41.47AECO spot gas (Cdn
$  per gj) (1)
    
    
    
    11.08
    
    
    
    
    7.75
    
    
    
    
    6.72
    
    
    
    
    8.04
    
    
    
    
    6.44NYMEX gas (U.S. $  per mmbtu)(2)
    
    
    
    12.97
    
    
    
    
    8.49
    
    
    
    
    7.11
    
    
    
    
    8.62
    
    
    
    
    6.16Currency
(U.S. $/Cdn $)
    
    
    
    0.85
    
    
    
    
    0.83
    
    
    
    
    0.82
    
    
    
    
    0.83
    
    
    
    
    0.77
 (1) gj refers to gigajoules(2) mmbtu refers to millions of British thermal units(3) Prior years restated to conform to presentation adopted in current year
  Hedging Losses
 Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    


    

Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Light crude oil ($ million)
    
    
    
    14.8
    
    
    
    
    19.8
    
    
    
    
    19.4
    
    
    
    
    52.2
    
    
    
    
    57.2Light crude oil ($  per bbl)
    
    
    
    7.60
    
    
    
    
    10.42
    
    
    
    
    10.48
    
    
    
    
    6.88
    
    
    
    
    7.51Natural gas ($ million)
    
    
    
    12.9
    
    
    
    
    1.8
    
    
    
    
    3.3
    
    
    
    
    13.6
    
    
    
    
    11.9Natural gas ($  per mcf)
    
    
    
    0.83
    
    
    
    
    0.12
    
    
    
    
    0.23
    
    
    
    
    0.23
    
    
    
    
    0.23Combined ($ million)
    
    
    
    27.7
    
    
    
    
    21.6
    
    
    
    
    22.7
    
    
    
    
    65.8
    
    
    
    
    69.1Combined ($  per boe)
    
    
    
    4.88
    
    
    
    
    3.99
    
    
    
    
    4.30
    
    
    
    
    3.04
    
    
    
    
    3.52




---



##### 



Oil
and Gas Sales  Contribution Analysis
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31,
    
    
    % of
    
    
    
    Sep. 30,
    
    
    % of
    
    
    
    Dec. 31,
    
    
    % of
    
    
    
    Dec. 31,
    
    
    % of
    
    
    
    Dec. 31,
    
    
    % ofSales Revenue
    
    
    2005
    
    
    total
    
    
    
    2005
    
    
    total
    
    
    
    2004
    
    
    total
    
    
    
    2005
    
    
    total
    
    
    
    2004
    
    
    totalNatural gas
    
    
    
    186.0
    
    
    
    53
    
    
    
    
    129.5
    
    
    
    43
    
    
    
    
    101.2
    
    
    
    45
    
    
    
    
    514.9
    
    
    
    45
    
    
    
    
    359.3
    
    
    
    44Light crude oil
    
    
    
    115.7
    
    
    
    33
    
    
    
    
    121.6
    
    
    
    40
    
    
    
    
    82.8
    
    
    
    37
    
    
    
    
    444.8
    
    
    
    39
    
    
    
    
    329.2
    
    
    
    40Natural gas liquids
    
    
    
    36.1
    
    
    
    10
    
    
    
    
    28.9
    
    
    
    9
    
    
    
    
    23.8
    
    
    
    11
    
    
    
    
    120.6
    
    
    
    10
    
    
    
    
    81.6
    
    
    
    10Heavy oil
    
    
    
    15.8
    
    
    
    4
    
    
    
    
    23.7
    
    
    
    8
    
    
    
    
    14.5
    
    
    
    7
    
    
    
    
    68.4
    
    
    
    6
    
    
    
    
    42.3
    
    
    
    5Brokered sales/sulphur
    
    
    
    0.3
    
    
    
    
    
    
    
    
    0.8
    
    
    
    
    
    
    
    
    0.9
    
    
    
    
    
    
    
    
    2.8
    
    
    
    
    
    
    
    
    3.4
    
    
    
    1Total oil and gas sales
    
    
    
    353.9
    
    
    
    
    
    
    
    
    304.5
    
    
    
    
    
    
    
    
    223.2
    
    
    
    
    
    
    
    
    1,151.5
    
    
    
    
    
    
    
    
    815.8
    
    
    
    
 Oil and Gas Sales  Price and Volumes Analysis
  ($ millions)
    
    Natural gas
    
    
    Light oil
    
    
    NGLs
    
    
    Heavy oil
    
    
    Other
    
    
    TotalYear ended December 31, 2004
    
    
    359.3
    
    
    
    329.2
    
    
    
    81.6
    
    
    
    42.3
    
    
    
    3.4
    
    
    
    815.8Effect of change in product prices
    
    
    115.3
    
    
    
    112.0
    
    
    
    26.7
    
    
    
    1.8
    
    
    
    
    
    
    
    255.8Effect of change in sales volumes
    
    
    42.0
    
    
    
    (1.4
    )
    
    
    12.3
    
    
    
    24.3
    
    
    
    
    
    
    
    77.2Effect of hedging losses
    
    
    (1.7
    )
    
    
    5.0
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3.3Other
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.6
    )
    
    
    (0.6
    )Year ended
December 31, 2005
    
    
    514.9
    
    
    
    444.8
    
    
    
    120.6
    
    
    
    68.4
    
    
    
    2.8
    
    
    
    1,151.5




---



##### 



Transportation Costs
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Light oil transportation
    
    
    
    0.5
    
    
    
    
    0.6
    
    
    
    
    0.4
    
    
    
    
    2.2
    
    
    
    
    1.8$  per bbl
    
    
    
    0.27
    
    
    
    
    0.29
    
    
    
    
    0.23
    
    
    
    
    0.29
    
    
    
    
    0.23Natural gas
transportation
    
    
    
    1.8
    
    
    
    
    1.4
    
    
    
    
    2.0
    
    
    
    
    5.7
    
    
    
    
    6.3$  per mcf
    
    
    
    0.12
    
    
    
    
    0.09
    
    
    
    
    0.14
    
    
    
    
    0.10
    
    
    
    
    0.12
  Royalties
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Royalty expense
    
    
    
    68.0
    
    
    
    
    57.4
    
    
    
    
    49.1
    
    
    
    
    213.9
    
    
    
    
    160.4$  per boe
    
    
    
    12.03
    
    
    
    
    10.60
    
    
    
    
    9.29
    
    
    
    
    9.87
    
    
    
    
    8.16Royalties as
a percent of sales
    
    
    
    19.2
    %
    
    
    
    18.9
    %
    
    
    
    22.0
    %
    
    
    
    18.6
    %
    
    
    
    19.7
    %
  Processing, Interest and Other Income
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Processing,
interest & other
income
    
    
    
    4.0
    
    
    
    
    2.1
    
    
    
    
    4.5
    
    
    
    
    17.7
    
    
    
    
    14.2$  per boe
    
    
    
    0.71
    
    
    
    
    0.39
    
    
    
    
    0.83
    
    
    
    
    0.82
    
    
    
    
    0.72




---



##### 



Operating Expenses
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Operating expenses
    
    
    
    61.2
    
    
    
    
    57.4
    
    
    
    
    42.6
    
    
    
    
    218.1
    
    
    
    
    159.7$  per boe
    
    
    
    10.83
    
    
    
    
    10.59
    
    
    
    
    8.06
    
    
    
    
    10.07
    
    
    
    
    8.13
  Amortization of Injectants for Miscible Floods
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Purchased and capitalized
    
    
    
    14.5
    
    
    
    
    6.9
    
    
    
    
    8.2
    
    
    
    
    34.7
    
    
    
    
    20.4Amortization
    
    
    
    7.1
    
    
    
    
    6.0
    
    
    
    
    4.9
    
    
    
    
    24.4
    
    
    
    
    19.7
   Interest




---



##### 



Foreign Currency Gains and Losses
  General and Administrative
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Cash G&A expense
    
    
    
    7.7
    
    
    
    
    7.0
    
    
    
    
    6.5
    
    
    
    
    27.4
    
    
    
    
    22.1$  per boe
    
    
    
    1.36
    
    
    
    
    1.29
    
    
    
    
    1.23
    
    
    
    
    1.27
    
    
    
    
    1.12Non-cash G&A expense
    
    
    
    0.8
    
    
    
    
    0.6
    
    
    
    
    0.4
    
    
    
    
    2.9
    
    
    
    
    2.3$  per boe
    
    
    
    0.14
    
    
    
    
    0.11
    
    
    
    
    0.08
    
    
    
    
    0.13
    
    
    
    
    0.12Total G&A ($ million)
    
    
    
    8.5
    
    
    
    
    7.6
    
    
    
    
    6.9
    
    
    
    
    30.3
    
    
    
    
    24.4Total G&A ($  per boe)
    
    
    
    1.50
    
    
    
    
    1.40
    
    
    
    
    1.31
    
    
    
    
    1.40
    
    
    
    
    1.24




---



##### 



Management Fees
 ($ million)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Management Fee
    
    
    
    2.2
    
    
    
    
    1.6
    
    
    
    
    1.4
    
    
    
    
    9.1
    
    
    
    
    6.8Performance Fee
    
    
    
    2.2
    
    
    
    
    1.9
    
    
    
    
    1.2
    
    
    
    
    6.9
    
    
    
    
    6.1Total ($ million)
    
    
    
    4.4
    
    
    
    
    3.5
    
    
    
    
    2.6
    
    
    
    
    16.0
    
    
    
    
    12.9Total ($  per boe)
    
    
    
    0.77
    
    
    
    
    0.65
    
    
    
    
    0.48
    
    
    
    
    0.74
    
    
    
    
    0.66
   Related Party Transactions
   Taxes




---



##### 



Depletion, Depreciation and Accretion
 ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Depletion and
Depreciation
    
    
    
    71.4
    
    
    
    
    73.5
    
    
    
    
    69.4
    
    
    
    
    285.0
    
    
    
    
    247.3$  per boe
    
    
    
    12.63
    
    
    
    
    13.57
    
    
    
    
    13.14
    
    
    
    
    13.15
    
    
    
    
    12.58Accretion
    
    
    
    3.6
    
    
    
    
    3.6
    
    
    
    
    3.2
    
    
    
    
    14.2
    
    
    
    
    10.6$  per boe
    
    
    
    0.64
    
    
    
    
    0.66
    
    
    
    
    0.60
    
    
    
    
    0.65
    
    
    
    
    0.54
   Ceiling Test
  Asset Retirement Obligations




---



##### 



Remediation Trust Funds & Remediation and Abandonment Expenses
   Goodwill
  Netbacks
  Combined Netbacks
 ($ per boe)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Sales price
    
    
    
    62.55
    
    
    
    
    56.07
    
    
    
    
    42.08
    
    
    
    
    53.02
    
    
    
    
    41.33Other production income
    
    
    
    0.06
    
    
    
    
    0.13
    
    
    
    
    0.17
    
    
    
    
    0.13
    
    
    
    
    0.1762.61
    
    
    
    
    56.20
    
    
    
    
    42.25
    
    
    
    
    53.15
    
    
    
    
    41.50Processing, interest and other income
    
    
    
    0.71
    
    
    
    
    0.39
    
    
    
    
    0.83
    
    
    
    
    0.82
    
    
    
    
    0.72Royalties
    
    
    
    (12.02
    )
    
    
    
    (10.60
    )
    
    
    
    (9.29
    )
    
    
    
    (9.87
    )
    
    
    
    (8.16
    )Operating expenses
    
    
    
    (10.83
    )
    
    
    
    (10.59
    )
    
    
    
    (8.07
    )
    
    
    
    (10.07
    )
    
    
    
    (8.13
    )Transportation costs
    
    
    
    (0.41
    )
    
    
    
    (0.36
    )
    
    
    
    (0.47
    )
    
    
    
    (0.36
    )
    
    
    
    (0.42
    )Amortization of injectants
    
    
    
    (1.25
    )
    
    
    
    (1.10
    )
    
    
    
    (0.94
    )
    
    
    
    (1.13
    )
    
    
    
    (1.00
    )Operating netback
    
    
    
    38.81
    
    
    
    
    33.94
    
    
    
    
    24.31
    
    
    
    
    32.54
    
    
    
    
    24.51




---



##### 



Light Crude Netbacks
 ($ per bbl)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Sales price
    
    
    
    59.40
    
    
    
    
    63.95
    
    
    
    
    44.76
    
    
    
    
    58.59
    
    
    
    
    43.21Other production income
    
    
    
    0.17
    
    
    
    
    0.37
    
    
    
    
    0.48
    
    
    
    
    0.37
    
    
    
    
    0.4559.57
    
    
    
    
    64.32
    
    
    
    
    45.24
    
    
    
    
    58.96
    
    
    
    
    43.66Processing, interest and other income
    
    
    
    0.34
    
    
    
    
    0.64
    
    
    
    
    0.51
    
    
    
    
    0.47
    
    
    
    
    0.46Royalties
    
    
    
    (6.47
    )
    
    
    
    (11.03
    )
    
    
    
    (9.65
    )
    
    
    
    (8.64
    )
    
    
    
    (7.62
    )Operating expenses
    
    
    
    (14.32
    )
    
    
    
    (12.85
    )
    
    
    
    (9.17
    )
    
    
    
    (12.28
    )
    
    
    
    (9.31
    )Transportation costs
    
    
    
    (0.27
    )
    
    
    
    (0.29
    )
    
    
    
    (0.23
    )
    
    
    
    (0.29
    )
    
    
    
    (0.23
    )Amortization of injectants
    
    
    
    (3.63
    )
    
    
    
    (3.14
    )
    
    
    
    (2.67
    )
    
    
    
    (3.21
    )
    
    
    
    (2.58
    )Operating netback
    
    
    
    35.22
    
    
    
    
    37.65
    
    
    
    
    24.03
    
    
    
    
    35.01
    
    
    
    
    24.38
 Heavy Oil Netbacks
 ($ per bbl)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Sales price
    
    
    
    31.77
    
    
    
    
    47.74
    
    
    
    
    26.99
    
    
    
    
    33.32
    
    
    
    
    32.45Processing, interest and other income
    
    
    
    0.74
    
    
    
    
    (0.83
    )
    
    
    
    
    
    
    
    
    0.36
    
    
    
    
    Royalties
    
    
    
    (2.98
    )
    
    
    
    (8.00
    )
    
    
    
    (4.19
    )
    
    
    
    (4.53
    )
    
    
    
    (4.87
    )Operating expenses
    
    
    
    (11.60
    )
    
    
    
    (16.30
    )
    
    
    
    (9.44
    )
    
    
    
    (15.65
    )
    
    
    
    (9.85
    )Operating netback
    
    
    
    17.93
    
    
    
    
    22.61
    
    
    
    
    13.36
    
    
    
    
    13.50
    
    
    
    
    17.73
 Natural Gas Netbacks
 ($ per mcf)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31, 2005
    
    
    
    Sep. 30, 2005
    
    
    
    Dec. 31, 2004
    
    
    
    Dec. 31, 2005
    
    
    
    Dec. 31, 2004Sales price
    
    
    
    11.97
    
    
    
    
    8.57
    
    
    
    
    7.02
    
    
    
    
    8.76
    
    
    
    
    6.80Processing, interest and other income
    
    
    
    0.19
    
    
    
    
    0.09
    
    
    
    
    0.24
    
    
    
    
    0.23
    
    
    
    
    0.20Royalties
    
    
    
    (2.62
    )
    
    
    
    (1.47
    )
    
    
    
    (1.34
    )
    
    
    
    (1.70
    )
    
    
    
    (1.26
    )Operating expenses
    
    
    
    (1.38
    )
    
    
    
    (1.31
    )
    
    
    
    (1.16
    )
    
    
    
    (1.24
    )
    
    
    
    (1.15
    )Transportation costs
    
    
    
    (0.12
    )
    
    
    
    (0.09
    )
    
    
    
    (0.14
    )
    
    
    
    (0.10
    )
    
    
    
    (0.12
    )Operating netback
    
    
    
    8.04
    
    
    
    
    5.79
    
    
    
    
    4.62
    
    
    
    
    5.95
    
    
    
    
    4.47




---



##### 



NGLs Netbacks
 ($ per bbl)
    
    
    Three months ended
    
    
    Twelve months endedDec. 31, 2005
    
    
    Sep. 30, 2005
    
    
    Dec. 31, 2004
    
    
    Dec. 31, 2005
    
    
    Dec. 31, 2004Sales price
    
    
    
    58.46
    
    
    
    
    57.75
    
    
    
    
    48.04
    
    
    
    
    54.22
    
    
    
    
    42.21Royalties
    
    
    
    (21.29
    )
    
    
    
    (20.57
    )
    
    
    
    (19.37
    )
    
    
    
    (17.66
    )
    
    
    
    (15.43
    )Operating expenses
    
    
    
    (10.05
    )
    
    
    
    (10.13
    )
    
    
    
    (7.87
    )
    
    
    
    (9.04
    )
    
    
    
    (7.94
    )Transportation costs
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.10
    )
    
    
    
    
    
    
    
    
    (0.10
    )Operating netback
    
    
    
    27.12
    
    
    
    
    27.05
    
    
    
    
    20.70
    
    
    
    
    27.52
    
    
    
    
    18.74
 Distributable Cash, Distributions and Taxability of Distributions
      69
2005 ANNUAL REPORT




---



##### 



($ thousands, except per trust unit amounts)
    
    

Three
months ended
    
    

Twelve
months endedDec. 31, 2005
    
    
    Sep. 30, 2005
    
    
    Dec. 31, 2004
    
    
    Dec. 31, 2005
    
    
    Dec. 31, 2004Cash generated from operations
    
    
    
    196,588
    
    
    
    
    158,976
    
    
    
    
    93,287
    
    
    
    
    618,070
    
    
    
    
    404,167Change in non-cash
operating working capital
    
    
    
    (7,993
    )
    
    
    
    (789
    )
    
    
    
    8,576
    
    
    
    
    (9,833
    )
    
    
    
    (1,173
    )Change in deferred injectants
    
    
    
    7,411
    
    
    
    
    892
    
    
    
    
    3,228
    
    
    
    
    10,265
    
    
    
    
    746Change in remediation trust funds
    
    
    
    784
    
    
    
    
    (272
    )
    
    
    
    32
    
    
    
    
    (20
    )
    
    
    
    (917
    )Change in deferred charges
    
    
    
    (793
    )
    
    
    
    2,818
    
    
    
    
    (473
    )
    
    
    
    1,235
    
    
    
    
    (1,893
    )Other
    
    
    
    (118
    )
    
    
    
    384
    
    
    
    
    308
    
    
    
    
    22
    
    
    
    
    248Distributable cash
    
    
    
    195,879
    
    
    
    
    162,009
    
    
    
    
    104,958
    
    
    
    
    619,739
    
    
    
    
    401,178Allocation of Distributable CashCash withheld
    
    
    
    76,021
    
    
    
    
    52,156
    
    
    
    
    8,492
    
    
    
    
    173,762
    
    
    
    
    38,117Distributions paid or declared
    
    
    
    119,858
    
    
    
    
    109,853
    
    
    
    
    96,466
    
    
    
    
    445,977
    
    
    
    
    363,061Distributable cash
    
    
    
    195,879
    
    
    
    
    162,009
    
    
    
    
    104,958
    
    
    
    
    619,739
    
    
    
    
    401,178Distributable cash per trust unit
    
    
    
    1.23
    
    
    
    
    1.02
    
    
    
    
    0.77
    
    
    
    
    3.94
    
    
    
    
    3.01Distributions paid or
declared per trust unit
    
    
    
    0.75
    
    
    
    
    0.69
    
    
    
    
    0.69
    
    
    
    
    2.82
    
    
    
    
    2.63Payout ratio(1)
    
    
    
    61
    %
    
    
    
    69
    %
    
    
    
    103
    %
    
    
    
    72
    %
    
    
    
    90
    %
 
 (1)
    
    Payout ratio is calculated as distributions paid or declared divided by cash
generated from operations.  Acquisitions and Dispositions
    70
PENGROWTH ENERGY TRUST




---



##### 



Capital Expenditures
  ($
millions)
    
    

Three
months ended
    
    

Twelve
months endedDec. 31, 2005
    
    
    Sep. 30, 2005
    
    
    Dec. 31, 2004
    
    
    Dec. 31, 2005
    
    
    Dec. 31, 2004Geological and geophysical
    
    
    
    
    
    
    
    
    0.2
    
    
    
    
    0.2
    
    
    
    
    1.4
    
    
    
    
    0.6Drilling and completions
    
    
    
    41.1
    
    
    
    
    29.8
    
    
    
    
    36.2
    
    
    
    
    130.3
    
    
    
    
    111.5Plant and facilities
    
    
    
    10.2
    
    
    
    
    10.0
    
    
    
    
    17.7
    
    
    
    
    34.1
    
    
    
    
    49.0Land purchases
    
    
    
    8.8
    
    
    
    
    0.8
    
    
    
    
    
    
    
    
    
    9.9
    
    
    
    
    Development capital
    
    
    
    60.1
    
    
    
    
    40.8
    
    
    
    
    54.1
    
    
    
    
    175.7
    
    
    
    
    161.1Acquisitions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    175.1
    
    
    
    
    573.0Total capital expenditures
and acquisitions
    
    
    
    60.1
    
    
    
    
    40.8
    
    
    
    
    54.1
    
    
    
    
    350.8
    
    
    
    
    734.1
  Reserves
  71
2005 ANNUAL REPORT




---



##### 



Working Capital
   Financial
Resources and Liquidity
      72
PENGROWTH ENERGY TRUST




---



##### 



Financial Leverage and Coverage
 Twelve
months ended December 312005
    
    
    2004Cash generated from operations to interest expense (times)
    
    
    
    29
    
    
    
    
    13Long term debt to cash generated from operations (times)
    
    
    
    0.6
    
    
    
    
    0.9Long term debt to debt plus book equity (%)
    
    
    
    20
    
    
    
    
    19
 Class A
and Class B Trust Unit Structure
 Income Tax Act Income Tax Act
    73
2005 ANNUAL REPORT




---



##### 



Commitments and Contractual Obligations
 ($ thousands)
    
    2006
    
    2007
    
    2008
    
    2009
    
    2010
    
    Thereafter
    
    TotalLong term debt (1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    174,450
    
    
    
    193,639
    
    
    
    368,089Interest payments on
long term debt (2)
    
    
    17,298
    
    
    
    17,298
    
    
    
    17,298
    
    
    
    17,298
    
    
    
    11,564
    
    
    
    34,546
    
    
    
    115,302Note payable
    
    
    20,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    20,000Operating leasesOffice rent
    
    
    2,030
    
    
    
    2,070
    
    
    
    3,096
    
    
    
    3,055
    
    
    
    3,036
    
    
    
    21,529
    
    
    
    34,816Vehicle leases
    
    
    852
    
    
    
    776
    
    
    
    604
    
    
    
    306
    
    
    
    91
    
    
    
    
    
    
    
    2,6292,882
    
    
    
    2,846
    
    
    
    3,700
    
    
    
    3,361
    
    
    
    3,127
    
    
    
    21,529
    
    
    
    37,445Purchase obligationsPipeline transportation
    
    
    43,839
    
    
    
    38,197
    
    
    
    34,981
    
    
    
    29,813
    
    
    
    11,748
    
    
    
    53,525
    
    
    
    212,103Capital expenditures
    
    
    33,323
    
    
    
    7,098
    
    
    
    294
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    40,715CO2 purchases
    
    
    5,119
    
    
    
    4,357
    
    
    
    4,198
    
    
    
    4,232
    
    
    
    4,267
    
    
    
    18,728
    
    
    
    40,90182,281
    
    
    
    49,652
    
    
    
    39,473
    
    
    
    34,045
    
    
    
    16,015
    
    
    
    72,253
    
    
    
    293,719Remediation
trust fund payments
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    11,250
    
    
    
    12,500122,711
    
    
    
    70,046
    
    
    
    60,721
    
    
    
    54,954
    
    
    
    205,406
    
    
    
    333,217
    
    
    
    847,055
 
 (1)
    
    Foreign dollar denominated debt due as follows: $150 million U.S. in April 2010,
$50 million U.S. in April 2013 and £50 million in December 2015, translated at the Dec 31, 2005
exchange rate.(2)
    
    Interest payments on foreign denominated debt, calculated based on Dec 31, 2005
foreign exchange rate. 74
PENGROWTH ENERGY TRUST




---



##### 



Trust
Unit Information
 Trust Unit Trading  after re-class (1)
 High
    
    Low
    
    Close
    
    Volume (000s)
    
    Value ($ millions)TSX  PGF.A ($ Cdn)20051st quarter
    
    
    28.29
    
    
    
    22.15
    
    
    
    24.03
    
    
    
    2,049
    
    
    
    53.32nd quarter
    
    
    27.90
    
    
    
    23.95
    
    
    
    27.20
    
    
    
    1,798
    
    
    
    46.43rd quarter
    
    
    30.10
    
    
    
    26.30
    
    
    
    29.50
    
    
    
    2,047
    
    
    
    58.04th quarter
    
    
    29.80
    
    
    
    23.64
    
    
    
    27.41
    
    
    
    1,324
    
    
    
    35.2Year
    
    
    30.10
    
    
    
    22.15
    
    
    
    27.41
    
    
    
    7,218
    
    
    
    192.920041st quarter2nd quarter3rd quarter
    
    
    24.19
    
    
    
    19.10
    
    
    
    22.67
    
    
    
    1,672
    
    
    
    35.54th quarter
    
    
    26.33
    
    
    
    20.03
    
    
    
    24.93
    
    
    
    2,607
    
    
    
    58.9Year
    
    
    26.33
    
    
    
    19.10
    
    
    
    24.93
    
    
    
    4,279
    
    
    
    94.4TSX  PGF.B ($ Cdn)20051st quarter
    
    
    19.90
    
    
    
    16.10
    
    
    
    17.05
    
    
    
    29,219
    
    
    
    543.72nd quarter
    
    
    19.01
    
    
    
    16.37
    
    
    
    18.40
    
    
    
    19,370
    
    
    
    342.53rd quarter
    
    
    21.26
    
    
    
    18.25
    
    
    
    20.58
    
    
    
    22,738
    
    
    
    441.04th quarter
    
    
    23.38
    
    
    
    17.27
    
    
    
    22.65
    
    
    
    19,747
    
    
    
    411.0Year
    
    
    23.38
    
    
    
    16.10
    
    
    
    22.65
    
    
    
    91,074
    
    
    
    1,738.220041st quarter2nd quarter3rd quarter
    
    
    20.00
    
    
    
    18.03
    
    
    
    18.87
    
    
    
    5,588
    
    
    
    105.64th quarter
    
    
    20.04
    
    
    
    17.51
    
    
    
    18.50
    
    
    
    16,007
    
    
    
    301.8Year
    
    
    20.04
    
    
    
    17.51
    
    
    
    18.50
    
    
    
    21,595
    
    
    
    407.4NYSE  PGH ($ U.S.)20051st quarter
    
    
    22.94
    
    
    
    18.11
    
    
    
    20.00
    
    
    
    24,621
    
    
    
    515.12nd quarter
    
    
    22.74
    
    
    
    19.05
    
    
    
    22.25
    
    
    
    16,153
    
    
    
    335.03rd quarter
    
    
    25.75
    
    
    
    21.55
    
    
    
    25.42
    
    
    
    14,502
    
    
    
    340.34th quarter
    
    
    25.56
    
    
    
    20.00
    
    
    
    23.53
    
    
    
    17,808
    
    
    
    399.7Year
    
    
    25.75
    
    
    
    18.11
    
    
    
    23.53
    
    
    
    73,084
    
    
    
    1,590.120041st quarter2nd quarter3rd quarter
    
    
    18.94
    
    
    
    14.40
    
    
    
    17.93
    
    
    
    21,200
    
    
    
    350.44th quarter
    
    
    21.24
    
    
    
    15.85
    
    
    
    20.82
    
    
    
    31,174
    
    
    
    574.7Year
    
    
    21.24
    
    
    
    14.40
    
    
    
    20.82
    
    
    
    52,374
    
    
    
    925.1
 
 (1)
    
    July 27, 2004, trust units were re-classified as Class A or Class B trust units.
Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock
Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B. 75


2005
ANNUAL REPORT




---



##### 



Trust
Unit Trading  before re-class (1)
 High
    
    Low
    
    Close
    Volume (000s) Value ($ millions)TSX  PGF.UN ($ Cdn)20041st quarter
    
    
    21.25
    
    
    
    15.55
    
    
    
    17.98
    
    
    
    30,620
    
    
    
    567.82nd quarter
    
    
    19.15
    
    
    
    16.15
    
    
    
    18.67
    
    
    
    18,145
    
    
    
    328.53rd quarter
    
    
    19.75
    
    
    
    18.52
    
    
    
    19.42
    
    
    
    3,554
    
    
    
    68.54th quarterYear
    
    
    21.25
    
    
    
    15.55
    
    
    
    19.42
    
    
    
    52,319
    
    
    
    964.8NYSE  PGH ($ U.S.)
    
    
    16.60
    
    
    
    12.10
    
    
    
    13.70
    
    
    
    36,899
    
    
    
    525.620041st quarter2nd quarter
    
    
    14.24
    
    
    
    11.62
    
    
    
    13.98
    
    
    
    22,194
    
    
    
    295.93rd quarter
    
    
    14.95
    
    
    
    13.84
    
    
    
    14.64
    
    
    
    5,797
    
    
    
    84.54th quarterYear
    
    
    14.95
    
    
    
    11.62
    
    
    
    14.64
    
    
    
    64,890
    
    
    
    906.0
 
 (1)
    
    July 27, 2004, trust units were re-classified as Class A or Class B trust units.
Class A trust units trade on the New York Stock Exchange (NYSE) under PGH and on the Toronto Stock
Exchange (TSX) under PGF.A. Class B trust units trade only on the TSX under PGF.B.   
 76
PENGROWTH ENERGY TRUST




---



##### 



Summary of Quarterly Results
   Q1
    
    Q2
    
    Q3
    
    Q42005Oil and gas sales ($000s)
    
    
    239,913
    
    
    
    253,189
    
    
    
    304,484
    
    
    
    353,923Net income ($000s)
    
    
    56,314
    
    
    
    53,106
    
    
    
    100,243
    
    
    
    116,663Net income per trust unit ($)
    
    
    0.37
    
    
    
    0.34
    
    
    
    0.63
    
    
    
    0.73Net income per trust unit  diluted ($)
    
    
    0.37
    
    
    
    0.34
    
    
    
    0.63
    
    
    
    0.73Distributable cash ($000s)
    
    
    127,804
    
    
    
    134,047
    
    
    
    162,009
    
    
    
    195,879Actual distributions paid or declared per trust unit ($)
    
    
    0.69
    
    
    
    0.69
    
    
    
    0.69
    
    
    
    0.75Daily production (boe)
    
    
    59,082
    
    
    
    57,988
    
    
    
    58,894
    
    
    
    61,442Total production (mboe)
    
    
    5,317
    
    
    
    5,277
    
    
    
    5,418
    
    
    
    5,653Average realized price ($  per boe)
    
    
    44.97
    
    
    
    47.79
    
    
    
    56.07
    
    
    
    62.55Operating netback ($  per boe)
    
    
    27.70
    
    
    
    29.26
    
    
    
    33.94
    
    
    
    38.812004Oil and gas sales ($000s) (1)
    
    
    168,771
    
    
    
    197,284
    
    
    
    226,514
    
    
    
    223,183Net income ($000s)
    
    
    38,652
    
    
    
    32,684
    
    
    
    51,271
    
    
    
    31,138Net income per trust unit ($)
    
    
    0.31
    
    
    
    0.24
    
    
    
    0.38
    
    
    
    0.23Net income per trust unit  diluted ($)
    
    
    0.31
    
    
    
    0.24
    
    
    
    0.38
    
    
    
    0.23Distributable cash ($000s) (1)
    
    
    92,895
    
    
    
    99,021
    
    
    
    104,304
    
    
    
    104,958Actual distributions paid or declared per trust unit ($)
    
    
    0.63
    
    
    
    0.64
    
    
    
    0.67
    
    
    
    0.69Daily production (boe)
    
    
    45,668
    
    
    
    51,451
    
    
    
    60,151
    
    
    
    57,425Total production (mboe)
    
    
    4,156
    
    
    
    4,682
    
    
    
    5,534
    
    
    
    5,283Average realized price ($  per boe) (1)
    
    
    40.37
    
    
    
    41.83
    
    
    
    40.90
    
    
    
    42.08Operating netback ($  per boe)
    
    
    25.71
    
    
    
    25.71
    
    
    
    22.77
    
    
    
    24.31
 Selected Annual Information Financial Results
 Twelve months ended December 31($ thousands)
    
    2005
    
    2004
    
    2003Oil and gas sales (1)
    
    
    1,151,510
    
    
    
    815,751
    
    
    
    702,732Net income
    
    
    326,326
    
    
    
    153,745
    
    
    
    189,297Net income per trust unit
    
    
    2.08
    
    
    
    1.15
    
    
    
    1.63Distributable cash (1)
    
    
    619,739
    
    
    
    401,178
    
    
    
    345,911Actual distributions paid or declared per trust unit
    
    
    2.82
    
    
    
    2.63
    
    
    
    2.68Total assets
    
    
    2,391,432
    
    
    
    2,276,534
    
    
    
    1,673,718Long term financial liabilities (2)
    
    
    381,026
    
    
    
    383,616
    
    
    
    294,300Unitholders equity
    
    
    1,475,996
    
    
    
    1,462,211
    
    
    
    1,159,433Number of units outstanding at year end (thousands)
    
    
    159,864
    
    
    
    152,973
    
    
    
    123,874
 
 (1)
    
    Prior years restated to conform to
presentation adopted in the current year(2)
    
    Long term debt plus long term portion of note
payable and contract liabilities 77
2005 ANNUAL REPORT




---



##### 



Business Risks
  
    
    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 governing such royalties, taxes and fees could have a material impact
on Pengrowths financial results and the value of Pengrowth trust units.
    
    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 the 1997 Kyoto
Protocol to the United Nations Framework Convention on Climate Change.
    
    Pengrowths oil and gas reserves will be depleted over time and our level of distributable
cash 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.
    
    Increased competition for properties will drive the cost of acquisition 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 can increase the cost of goods and services
and make it more difficult to hire and retain professional staff.
    
    Changing interest rates influence borrowing costs and the availability of capital.
    
    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.
 78
PENGROWTH ENERGY TRUST




---



##### 




    
    The value of Class A trust units and Class B trust units, relative to one another, may be
influenced by the different markets in which the trust units trade, the restrictions in
entitlement of the Class B trust units to Canadian residents and the limitation in the number
of Class A trust units beneath an ownership threshold of 49.75 percent of all trust units
outstanding.
    
    Inflation may result in escalating costs which could impact unitholder distributions and the
value of Pengrowth trust units.
    
    Canadian / U.S. exchange rates influence revenues and, to a lesser extent, operating and
capital costs.
    
    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.
  
    
    Fixing the price on a portion of its future crude oil and natural gas production.
    
    Fixing the Canadian / U.S. exchange rate through financial hedging contracts or by fixing
commodity prices in Canadian dollars.
    
    Offering competitive incentive-based compensation packages to attract and retain highly
qualified and motivated professional staff.
    
    Adhering to strict investment criteria for acquisitions.
    
    Acquiring mature production with long life reserves and proven production.
    
    Performing extensive geological, geophysical, engineering and environmental analysis before
committing to capital development projects.
    
    Geographically diversifying its portfolio.
    
    Controlling costs to maximize profitability.
    
    Developing and adhering to policies and practices that protect the environment and meet or
exceed the regulations imposed by the government.
    
    Developing and adhering to safety policies and practices that meet or exceed regulatory standards.
    
    Ensuring strong third party operators for non-operated properties.
    
    Carrying insurance to cover physical losses and business interruption.
  Subsequent Event
  79
2005 ANNUAL REPORT




---



##### 



Outlook
  
    
    Operating our properties in a safe and prudent manner in order to protect our employees, the
public, the environment and our investment;
    
    Maintaining a balanced portfolio of oil and gas properties in our key focus areas;
    
    Growing production and reserves through accretive acquisitions and low risk development drilling;
    
    Increasing our undeveloped land position;
    
    Continuing to optimize costs and maximize netbacks;
    
    The selective disposition of oil and gas properties that do not meet our return objectives;
    
    Continuing to maintain a stable distribution policy while withholding a portion of
distributable cash to fund future capital programs.
   2
 80
PENGROWTH ENERGY TRUST




---



##### 



APPENDIX C
 CONSOLIDATED FINANCIAL STATEMENTS OF PENGROWTH ENERGY TRUST
INCLUDING NOTE 20 THEREOF WHICH INCLUDES A RECONCILIATION OF THE
CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY
ACCEPTED ACCOUNTING PRINCIPLES




---



##### 



Managements Report to Unitholders
 Managements
Responsibility to the Unitholders
     (signed)
    
    (signed)James S. Kinnear
    
    Christopher G. WebsterChairman, President and
    
    Chief Financial OfficerChief Executive OfficerFebruary 27, 2006
 812005 ANNUAL REPORT




---



##### 



Auditors Report
 TO THE UNITHOLDERS OF PENGROWTH ENERGY TRUST
     
  82
PENGROWTH ENERGY TRUST




---



##### 



Consolidated Balance Sheets
 (Stated in thousands of dollars)As at December 31
    
    
    2005
    
    
    2004ASSETSCurrent AssetsAccounts receivable
    
    
    $
    127,394
    
    
    
    $
    104,228Inventory
    
    
    
    
    
    
    
    
    439127,394
    
    
    
    
    104,667Remediation Trust Funds (Note 3)
    
    
    
    8,329
    
    
    
    
    8,309Deferred Charges (Note 11)
    
    
    
    4,886
    
    
    
    
    3,651Goodwill (Note 4)
    
    
    
    182,835
    
    
    
    
    170,619Property, Plant And Equipment and Other Assets (Note 5)
    
    
    
    2,067,988
    
    
    
    
    1,989,288$
    2,391,432
    
    
    
    $
    2,276,534LIABILITIES AND UNITHOLDERS EQUITYCurrent LiabilitiesBank indebtedness
    
    
    $
    14,567
    
    
    
    $
    4,214Accounts payable and accrued liabilities
    
    
    
    111,493
    
    
    
    
    80,423Distributions payable to unitholders
    
    
    
    79,983
    
    
    
    
    70,456Due to Pengrowth Management Limited
    
    
    
    8,277
    
    
    
    
    7,325Note payable (Note 7)
    
    
    
    20,000
    
    
    
    
    15,000Current portion of contract liabilities (Note 4)
    
    
    
    5,279
    
    
    
    
    5,795239,599
    
    
    
    
    183,213Note Payable (Note 7)
    
    
    
    
    
    
    
    
    20,000Contract Liabilities (Note 4)
    
    
    
    12,937
    
    
    
    
    18,216Long Term Debt (Note 8)
    
    
    
    368,089
    
    
    
    
    345,400Asset Retirement Obligations (Note 6)
    
    
    
    184,699
    
    
    
    
    171,866Future Income Taxes (Note 14)
    
    
    
    110,112
    
    
    
    
    75,628Trust Unitholders EquityTrust Unitholders capital (Note 10)
    
    
    
    2,514,997
    
    
    
    
    2,383,284Contributed surplus (Note 10)
    
    
    
    3,646
    
    
    
    
    1,923Deficit (Note 9)
    
    
    
    (1,042,647
    )
    
    
    
    (922,996
    )1,475,996
    
    
    
    
    1,462,211Commitments (Note 18)Subsequent Event (Note 19)$
    2,391,432
    
    
    
    $
    2,276,534
   (signed)
    
    (signed)Director
    
    Director
 83
2005 ANNUAL REPORT




---



##### 



Consolidated Statements of
Income and Deficit
 (Stated in thousands of dollars)Years ended December 31
    
    2005
    
    
    2004REVENUESOil and gas sales
    
    $
    1,151,510
    
    
    $
    815,751Processing and other income
    
    
    15,091
    
    
    
    12,390Royalties, net of incentives
    
    
    (213,863
    )
    
    
    (160,351
    )952,738
    
    
    
    667,790Interest and other income
    
    
    2,596
    
    
    
    1,770Net Revenue
    
    
    955,334
    
    
    
    669,560EXPENSESOperating
    
    
    218,115
    
    
    
    159,742Transportation
    
    
    7,891
    
    
    
    8,274Amortization of injectants for miscible floods
    
    
    24,393
    
    
    
    19,669Interest
    
    
    21,642
    
    
    
    29,924General and administrative
    
    
    30,272
    
    
    
    24,448Management fee (Note 15)
    
    
    15,961
    
    
    
    12,874Foreign exchange gain (Note 12)
    
    
    (6,966
    )
    
    
    (17,300
    )Depletion and depreciation
    
    
    284,989
    
    
    
    247,332Accretion (Note 6)
    
    
    14,162
    
    
    
    10,642610,459
    
    
    
    495,605Income Before Taxes
    
    
    344,875
    
    
    
    173,955Income Tax Expense (Note 14)Capital
    
    
    6,273
    
    
    
    4,594Future
    
    
    12,276
    
    
    
    15,61618,549
    
    
    
    20,210NET INCOME
    
    $
    326,326
    
    
    $
    153,745Deficit, beginning of year
    
    
    (922,996
    )
    
    
    (713,680
    )Distributions paid or declared
    
    
    (445,977
    )
    
    
    (363,061
    )Deficit, End of Year
    
    $
    (1,042,647
    )
    
    $
    (922,996
    )Net Income Per Trust Unit (Note 16)Basic
    
    $
    2.077
    
    
    $
    1.153Diluted
    
    $
    2.066
    
    
    $
    1.147




---



##### 



Consolidated Statements of Cash Flow
 (Stated in thousands of dollars)Years ended December 31
    
    2005
    
    
    2004CASH PROVIDED BY (USED FOR):OperatingNet income
    
    $
    326,326
    
    
    $
    153,745Depletion, depreciation and accretion
    
    
    299,151
    
    
    
    257,974Future income taxes
    
    
    12,276
    
    
    
    15,616Contract liability amortization
    
    
    (5,795
    )
    
    
    (4,164
    )Amortization of injectants
    
    
    24,393
    
    
    
    19,669Purchase of injectants
    
    
    (34,658
    )
    
    
    (20,415
    )Expenditures on remediation
    
    
    (7,353
    )
    
    
    (4,440
    )Unrealized foreign exchange gain (Note 12)
    
    
    (7,800
    )
    
    
    (18,900
    )Trust unit based compensation (Note 10)
    
    
    2,932
    
    
    
    2,264Deferred charges (Note 11)
    
    
    (4,961
    )
    
    
    Amortization of deferred charges (Note 11)
    
    
    3,726
    
    
    
    1,893Gain on sale of marketable securities
    
    
    
    
    
    
    (248
    )Changes in non-cash operating working capital (Note 13)
    
    
    9,833
    
    
    
    1,173618,070
    
    
    
    404,167FinancingDistributions
    
    
    (436,450
    )
    
    
    (344,744
    )Change in long term debt, net
    
    
    10,030
    
    
    
    105,000Note payable (Note 7)
    
    
    (15,000
    )
    
    
    (10,000
    )Proceeds from issue of trust units
    
    
    42,544
    
    
    
    509,830(398,876
    )
    
    
    260,086InvestingExpenditures on property acquisitions
    
    
    (92,568
    )
    
    
    (572,980
    )Expenditures on property, plant and equipment
    
    
    (175,693
    )
    
    
    (161,141
    )Proceeds on property dispositions
    
    
    37,617
    
    
    
    Change in remediation trust fund
    
    
    (20
    )
    
    
    (917
    )Purchase of marketable securities
    
    
    
    
    
    
    (2,680
    )Proceeds from sale of marketable securities
    
    
    
    
    
    
    2,928Change in non-cash investing working capital (Note 13)
    
    
    1,117
    
    
    
    2,169(229,547
    )
    
    
    (732,621
    )Change in Cash and Term Deposits
    
    
    (10,353
    )
    
    
    (68,368
    )Cash and Term Deposits
(Bank Indebtedness) at Beginning of Year
    
    
    (4,214
    )
    
    
    64,154Cash and
Term Deposits (Bank Indebtedness) at End of Year
    
    $
    (14,567
    )
    
    $
    (4,214
    )




---



##### 



Notes to Consolidated
 Financial Statements
 (Tabular amounts are stated in thousands of dollars except per unit amounts.)
 1. Structure of the Trust




---



##### 



2. Significant Accounting Policies
 Basis of Presentation
   Joint Interest Operations
  Property, Plant and Equipment




---



##### 



Goodwill
   Injectant Costs
  Inventory
  Asset Retirement Obligations




---



##### 



Income Taxes
   Trust Unit Compensation Plans
   Risk Management




---



##### 



Measurement Uncertainty
   Earnings per unit
  Cash and term deposits
  Revenue recognition
  Comparative figures
  3. Remediation Trust Funds




---



##### 



2005
    
    
    2004Contributions to Judy Creek Remediation Trust Fund
    
    $
    778
    
    
    $
    906Contributions to SOEP Environmental Restoration Fund
    
    
    556
    
    
    
    548Expenditures related to Judy Creek Remediation Trust Fund
    
    
    (1,314
    )
    
    
    (537
    )20
    
    
    
    917Expenditures on ARO not covered by the trust funds
    
    
    6,039
    
    
    
    3,903Expenditures on ARO covered by the trust funds
    
    
    1,314
    
    
    
    5377,353
    
    
    
    4,440Total trust fund contributions and ARO expenditures not covered by the trust funds
    
    $
    7,373
    
    
    $
    5,357
 4. Acquisitions
 Corporate Acquisitions
  Allocation of purchase price:Working capital
    
    $
    1,655Property, plant, and equipment
    
    
    121,729Goodwill
    
    
    12,216Bank debt
    
    
    (20,459
    )Asset retirement obligations
    
    
    (4,038
    )Future income taxes
    
    
    (22,208
    )$
    88,895Cost of acquisition:Trust units issued
    
    $
    87,960Acquisition costs
    
    
    935$
    88,895




---



##### 



Allocation of purchase price:Working capital
    
    $
    9,310Property, plant, and equipment
    
    
    502,924Goodwill
    
    
    170,619Asset retirement obligations
    
    
    (43,876
    )Future income taxes
    
    
    (60,012
    )Contract liabilities
    
    
    (28,175
    )$
    550,790Cost of acquisition:Cash and term deposits
    
    $
    224,700Acquisition facility
    
    
    325,000Acquisition costs
    
    
    1,090$
    550,790




---



##### 



2004 Proforma
    
    
    2004 Actual(unaudited)
    
    (audited)Oil and gas sales
    
    $
    897,397
    
    
    $
    815,751Net income
    
    $
    180,101
    
    
    $
    153,745Net income per unit:Basic
    
    $
    1.206
    
    
    $
    1.153Diluted
    
    $
    1.201
    
    
    $
    1.147
 Property Acquisitions
   5. Property, Plant and Equipment and Other Assets
 2005
    
    
    2004Property, Plant and EquipmentProperty, Plant and Equipment, at cost
    
    $
    3,340,106
    
    
    $
    2,986,681Accumulated depletion and depreciation
    
    
    (1,307,424
    )
    
    
    (1,022,435
    )Net book value of property, plant and equipment
    
    
    2,032,682
    
    
    
    1,964,246Other AssetsDeferred injectant costs
    
    
    35,306
    
    
    
    25,042Net book value of property, plant and equipment and other assets
    
    $
    2,067,988
    
    
    $
    1,989,288




---



##### 



Foreign
    
    
    Edmonton LightWTI Oil
    
    
    Exchange Rate
    
    
    Crude Oil
    
    
    AECO GasYear
    
    (U.S.$/bbl)
    
    
    (U.S.$/Cdn)
    
    
    (Cdn$/bbl)
    
    
    (Cdn$/mmbtu)2006
    
    
    57.00
    
    
    
    0.85
    
    
    
    66.25
    
    
    
    10.602007
    
    
    55.00
    
    
    
    0.85
    
    
    
    64.00
    
    
    
    9.252008
    
    
    51.00
    
    
    
    0.85
    
    
    
    59.25
    
    
    
    8.002009
    
    
    48.00
    
    
    
    0.85
    
    
    
    55.75
    
    
    
    7.502010
    
    
    46.50
    
    
    
    0.85
    
    
    
    54.00
    
    
    
    7.202011
    
    
    45.00
    
    
    
    0.85
    
    
    
    52.25
    
    
    
    6.902012
    
    
    45.00
    
    
    
    0.85
    
    
    
    52.25
    
    
    
    6.902013
    
    
    46.00
    
    
    
    0.85
    
    
    
    53.25
    
    
    
    7.052014
    
    
    46.75
    
    
    
    0.85
    
    
    
    54.25
    
    
    
    7.202015
    
    
    47.75
    
    
    
    0.85
    
    
    
    55.50
    
    
    
    7.402016
    
    
    48.75
    
    
    
    0.85
    
    
    
    56.50
    
    
    
    7.55Escalate thereafter
    
    2.0% per year
    
    
    
    
    
    
    2.0% per year
    
    
    2.0% per year
 6. Asset Retirement Obligations
   2005
    
    
    2004Asset retirement obligations, beginning of year
    
    $
    171,866
    
    
    $
    102,528Increase (decrease) in liabilities during the year related to:Acquisitions
    
    
    6,347
    
    
    
    44,368Disposals
    
    
    (3,844
    )
    
    
    Additions
    
    
    1,972
    
    
    
    2,681Revisions
    
    
    1,549
    
    
    
    16,087Accretion expense
    
    
    14,162
    
    
    
    10,642Liabilities settled during the year
    
    
    (7,353
    )
    
    
    (4,440
    )Asset retirement obligations, end of year
    
    $
    184,699
    
    
    $
    171,866
 7. Note Payable




---



##### 



8. Long Term Debt
 2005
    
    
    2004U.S. dollar denominated debt:U.S. $150 million senior unsecured notes at 4.93 percent due April 2010
    
    $
    174,450
    
    
    $
    180,300U.S. $50 million senior unsecured notes at 5.47 percent due April 2013
    
    
    58,150
    
    
    
    60,100232,600
    
    
    
    240,400Pound sterling denominated £50 million unsecured notes at 5.46 percent due December 2015
    
    
    100,489
    
    
    
    Canadian dollar revolving credit borrowings
    
    
    35,000
    
    
    
    105,000$
    368,089
    
    
    $
    345,400




---



##### 



9. Deficit
 2005
    
    
    2004Accumulated earnings
    
    $
    1,053,383
    
    
    $
    727,057Accumulated distributions paid or declared
    
    
    (2,096,030
    )
    
    
    (1,650,053
    )$
    (1,042,647
    )
    
    $
    (922,996
    )
  10. Trust Units
  Total Trust Units:
 Year Ended

    
    Year EndedDecember 31, 2005

    
    December 31, 2004Number of
    
    
    
    
    
    
    Number ofTrust Units Issued
    
    Trust Units
    
    
    Amount
    
    
    Trust Units
    
    
    AmountBalance, beginning of period
    
    
    152,972,555
    
    
    $
    2,383,284
    
    
    
    123,873,651
    
    
    $
    1,872,924Issued for cash
    
    
    
    
    
    
    
    
    
    
    26,885,000
    
    
    
    499,480Less: issue expenses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (26,287
    )Issued for the Crispin acquisition (non-cash) (Note 4)
    
    
    4,225,313
    
    
    
    87,960
    
    
    
    
    
    
    
    Issued for cash on exercise of trust unit options and rights
    
    
    1,512,211
    
    
    
    21,818
    
    
    
    1,294,838
    
    
    
    20,251Issued for cash under Distribution Reinvestment Plan (DRIP)
    
    
    1,154,004
    
    
    
    20,726
    
    
    
    918,366
    
    
    
    16,386Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    1,209
    
    
    
    
    
    
    
    530Royalty units exchanged for trust units
    
    
    
    
    
    
    
    
    
    
    700
    
    
    
    Balance, end of period
    
    
    159,864,083
    
    
    $
    2,514,997
    
    
    
    152,972,555
    
    
    $
    2,383,284
 Class A Trust Units:
 Year Ended

    
    For the period from July 27, 2004December 31, 2005

    
    to December 31, 2004Number of
    
    
    
    
    
    Number ofTrust Units Issued
    
    Trust Units
    
    Amount
    
    
    Trust Units
    
    AmountBalance, beginning of period
    
    
    76,792,759
    
    
    $
    1,176,427
    
    
    
    
    
    
    $
    Issued for the Crispin acquisition (non-cash) (Note 4)
    
    
    686,732
    
    
    
    19,002
    
    
    
    
    
    
    
    Trust units converted
    
    
    45,182
    
    
    
    692
    
    
    
    76,792,759
    
    
    
    1,176,427Balance, end of period
    
    
    77,524,673
    
    
    $
    1,196,121
    
    
    
    76,792,759
    
    
    $
    1,176,427




---



##### 



Class B Trust Units:
 Year Ended

    
    For the period from July 27, 2004December 31, 2005

    
    to December 31, 2004Number of
    
    
    
    
    
    
    Number ofTrust Units Issued
    
    Trust Units
    
    
    Amount
    
    
    Trust Units
    
    
    AmountBalance, beginning of period
    
    
    76,106,471
    
    
    $
    1,205,734
    
    
    
    
    
    
    $
    Trust units converted
    
    
    (9,824
    )
    
    
    (151
    )
    
    
    59,000,129
    
    
    
    903,854Issued for cash
    
    
    
    
    
    
    
    
    
    
    15,985,000
    
    
    
    298,920Less: issue expenses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (15,577
    )Issued for the Crispin acquisition (non-cash) (Note 4)
    
    
    3,538,581
    
    
    
    68,958
    
    
    
    
    
    
    
    Issued for cash on exercise of trust unit options and rights
    
    
    1,512,211
    
    
    
    21,818
    
    
    
    746,864
    
    
    
    11,516Issued for cash under Distribution Reinvestment Plan (DRIP)
    
    
    1,154,004
    
    
    
    20,726
    
    
    
    374,478
    
    
    
    6,750Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    1,209
    
    
    
    
    
    
    
    271Balance, end of period
    
    
    82,301,443
    
    
    $
    1,318,294
    
    
    
    76,106,471
    
    
    $
    1,205,734
 Unclassified Trust Units:
 Year Ended

    
    Year EndedDecember 31, 2005

    
    December 31, 2004Number of
    
    
    
    
    
    
    Number ofTrust Units Issued
    
    Trust Units
    
    
    Amount
    
    
    Trust Units
    
    
    AmountBalance, beginning of year
    
    
    73,325
    
    
    $
    1,123
    
    
    
    123,873,651
    
    
    $
    1,872,924Issued for cash
    
    
    
    
    
    
    
    
    
    
    10,900,000
    
    
    
    200,560Less: issue expenses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10,710
    )Issued for cash on exercise of trust unit options and rights
    
    
    
    
    
    
    
    
    
    
    547,974
    
    
    
    8,735Issued for cash under Distribution Reinvestment Plan (DRIP)
    
    
    
    
    
    
    
    
    
    
    543,888
    
    
    
    9,636Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    259Royalty units exchanged for trust units
    
    
    
    
    
    
    
    
    
    
    700
    
    
    
    Balance, prior to conversion
    
    
    
    
    
    
    
    
    
    
    135,866,213
    
    
    
    2,081,404Converted to Class A or Class B trust units
    
    
    (35,358
    )
    
    
    (541
    )
    
    
    (135,792,888
    )
    
    
    (2,080,281
    )Balance, end of year
    
    
    37,967
    
    
    $
    582
    
    
    
    73,325
    
    
    $
    1,123




---



##### 



Distribution Reinvestment Plan




---



##### 



Contributed Surplus
 2005
    
    
    
    2004Balance, beginning of year
    
    
    $
    1,923
    
    
    
    $
    189Trust unit rights incentive plan (non-cash expensed)
    
    
    
    1,740
    
    
    
    
    2,264Deferred entitlement trust units
    
    
    
    1,192
    
    
    
    
    Trust unit rights incentive plan (non-cash exercised)
    
    
    
    (1,209
    )
    
    
    
    (530
    )Balance, end of year
    
    
    $
    3,646
    
    
    
    $
    1,923
 Trust Unit Option Plan
   Trust Unit Options
 2005
    
    
    2004Weighted
    
    
    
    
    
    
    
    
    WeightedNumber
    
    
    
    Average
    
    
    
    Number of
    
    
    
    Averageof Options
    
    
    
    Exercise Price
    
    
    
    Options
    
    
    
    Exercise PriceOutstanding at beginning of year
    
    
    
    845,374
    
    
    
    $
    16.97
    
    
    
    
    2,014,903
    
    
    
    $
    17.47Exercised
    
    
    
    (558,307
    )
    
    
    $
    16.74
    
    
    
    
    (838,789
    )
    
    
    $
    16.82Expired
    
    
    
    (27,750
    )
    
    
    $
    18.63
    
    
    
    
    (325,200
    )
    
    
    $
    20.44Cancelled
    
    
    
    
    
    
    
    
    
    
    
    
    
    (5,540
    )
    
    
    $
    16.53Outstanding at year end
    
    
    
    259,317
    
    
    
    $
    17.28
    
    
    
    
    845,374
    
    
    
    $
    16.97Exercisable at year end
    
    
    
    259,317
    
    
    
    $
    17.28
    
    
    
    
    845,374
    
    
    
    $
    16.97




---



##### 



Options Outstanding and Exercisable
 Weighted AverageNumber Outstanding
    
    
    Remaining Contractual
    
    
    Weighted AverageRange of Exercise Prices
    
    and Exercisable
    
    
    Life (years)
    
    
    Exercise Price$12.00 to $14.99
    
    
    30,193
    
    
    
    2.9
    
    
    $
    13.08$15.00 to $16.99
    
    
    38,139
    
    
    
    2.7
    
    
    $
    15.05$17.00 to $17.99
    
    
    82,772
    
    
    
    2.4
    
    
    $
    17.47$18.00 to $20.50
    
    
    108,213
    
    
    
    1.9
    
    
    $
    19.09$12.00 to $20.50
    
    
    259,317
    
    
    
    2.3
    
    
    $
    17.28
 Trust Unit Rights Incentive Plan
   Trust Unit Rights
 2005
    
    
    2004Weighted
    
    
    
    
    
    
    
    
    WeightedNumber of
    
    
    
    Average
    
    
    
    Number of
    
    
    
    AverageRights
    
    
    
    Exercise Price
    
    
    
    Rights
    
    
    
    Exercise PriceOutstanding at beginning of year
    
    
    
    2,011,451
    
    
    
    $
    14.23
    
    
    
    
    1,112,140
    
    
    
    $
    12.20Granted(1)
    
    
    
    606,575
    
    
    
    $
    18.34
    
    
    
    
    1,409,856
    
    
    
    $
    17.35Exercised
    
    
    
    (953,904
    )
    
    
    $
    12.81
    
    
    
    
    (456,049
    )
    
    
    $
    13.47Cancelled
    
    
    
    (222,385
    )
    
    
    $
    16.19
    
    
    
    
    (54,496
    )
    
    
    $
    14.19Outstanding at year end
    
    
    
    1,441,737
    
    
    
    $
    14.85
    
    
    
    
    2,011,451
    
    
    
    $
    14.23Exercisable at year end
    
    
    
    668,473
    
    
    
    $
    13.73
    
    
    
    
    1,037,078
    
    
    
    $
    12.48
 
 (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$8.97 to $13.99
    
    
    199,280
    
    
    
    1.9
    
    
    $
    9.03
    
    
    
    
    199,280
    
    
    $
    9.03$14.00 to $15.99
    
    
    549,620
    
    
    
    3.1
    
    
    $
    14.01
    
    
    
    
    223,339
    
    
    $
    14.01$16.00 to $17.99
    
    
    571,505
    
    
    
    3.9
    
    
    $
    16.89
    
    
    
    
    206,942
    
    
    $
    17.04$18.00 to $20.99
    
    
    121,332
    
    
    
    4.8
    
    
    $
    18.65
    
    
    
    
    38,912
    
    
    $
    18.68$8.97 to $20.99
    
    
    1,441,737
    
    
    
    3.1
    
    
    $
    14.85
    
    
    
    
    668,473
    
    
    $
    13.73
 Fair Value of Unit Based Compensation
  2004Net income
    
    $
    153,745Compensation expense related to rights incentive options granted in 2002
    
    
    (1,067
    )Pro forma net income
    
    $
    152,678Pro forma net income per unit:Basic
    
    $
    1.145Diluted
    
    $
    1.139




---



##### 



Long Term Incentive Program
   Number of DEUsOutstanding, beginning of period
    
    
    Granted
    
    
    194,229Cancelled
    
    
    (26,258
    )Deemed DRIP
    
    
    17,620Outstanding, end of period
    
    
    185,591
 Trust Unit Award Plan




---



##### 



Employee Savings Plans
  Trust Unit Margin Purchase Plan




---



##### 



Redemption Rights
  11. Deferred Charges
 2005
    
    
    
    2004Imputed interest on note payable
(net of accumulated amortization of $2,859, 2004  $1,587)
    
    
    $
    748
    
    
    
    $
    2,020U.S. debt
issue costs (net of accumulated amortization of $816, 2004  $510)
    
    
    
    1,325
    
    
    
    
    1,631Deferred compensation expense
(net of accumulated amortization of $2,143, 2004  nil)
    
    
    
    2,141
    
    
    
    
    U.K. debt issue costs (net of accumulated amortization of $5)
    
    
    
    672
    
    
    
    
    $
    4,886
    
    
    
    $
    3,651
 12. Foreign Exchange Loss (Gain)
 2005
    
    
    
    2004Unrealized foreign exchange gain on translation of U.S. dollar denominated debt
    
    
    $
    (7,800
    )
    
    
    $
    (18,900
    )Realized foreign exchange losses
    
    
    
    834
    
    
    
    
    1,600$
    (6,966
    )
    
    
    $
    (17,300
    )
  13. Other Cash Flow Disclosures
 Change in Non-Cash Operating Working Capital
 Cash provided by (used for):
    
    
    2005
    
    
    
    2004Accounts receivable
    
    
    $
    (21,511
    )
    
    
    $
    (22,515
    )Inventory
    
    
    
    439
    
    
    
    
    260Accounts payable and accrued liabilities
    
    
    
    29,953
    
    
    
    
    17,225Due to Pengrowth Management Limited
    
    
    
    952
    
    
    
    
    6,203$
    9,833
    
    
    
    $
    1,173




---



##### 



Change in Non-Cash Investing Working Capital
 Cash provided by:
    
    
    2005
    
    
    
    2004Accounts payable for capital accruals
    
    
    $
    1,117
    
    
    
    $
    2,169
 Cash payments
 2005
    
    
    
    2004Cash payments made for taxes(1)
    
    
    $
    6,424
    
    
    
    $
    4,729Cash payments made for interest
    
    
    $
    21,779
    
    
    
    $
    28,119
 
 (1)
    
    Capital and resource taxes 14. Income Taxes
   2005
    
    
    
    2004Income before taxes
    
    
    $
    344,875
    
    
    
    $
    173,955Combined federal and provincial tax rate
    
    
    
    37.6
    %
    
    
    
    38.6
    %Expected income tax
    
    
    
    129,673
    
    
    
    
    67,147Net income of the Trust
    
    
    
    (122,698
    )
    
    
    
    (59,346
    )Resource allowance
    
    
    
    (10,985
    )
    
    
    
    (8,807
    )Non-deductible crown charges
    
    
    
    22,756
    
    
    
    
    16,476Unrealized foreign exchange gain
    
    
    
    (1,623
    )
    
    
    
    (3,648
    )Attributed Canadian royalty income
    
    
    
    (3,541
    )
    
    
    
    (3,113
    )Effect of proposed tax changes
    
    
    
    
    
    
    
    
    3,850Future tax rate difference
    
    
    
    (1,402
    )
    
    
    
    (1,585
    )Change in valuation allowance
    
    
    
    
    
    
    
    
    3,035Other
    
    
    
    96
    
    
    
    
    1,607Future income taxes
    
    
    
    12,276
    
    
    
    
    15,616Capital taxes
    
    
    
    6,273
    
    
    
    
    4,594$
    18,549
    
    
    
    $
    20,210




---



##### 



2005
    
    
    
    2004Future income tax liabilities:Property, plant, equipment and other assets
    
    
    $
    114,256
    
    
    
    $
    79,774Unrealized foreign exchange gain
    
    
    
    9,689
    
    
    
    
    8,378Other
    
    
    
    110
    
    
    
    
    124,055
    
    
    
    
    88,152Future income tax assets:Attributed Canadian royalty income
    
    
    
    (7,819
    )
    
    
    
    (4,418
    )Contract liabilities
    
    
    
    (6,124
    )
    
    
    
    (8,072
    )Other
    
    
    
    
    
    
    
    
    (34
    )$
    110,112
    
    
    
    $
    75,628
  15. Related Party Transactions
  16. Amounts Per Trust Unit




---



##### 



17. Financial Instruments
 Interest Rate Risk
   Foreign Currency Exchange Risk
    Credit Risk
  Forward and Futures Contracts
   Crude Oil:
 Remaining Term
    
    Volume(bbl per day)
    
    
    Reference Point
    
    
    Price per bblFinancial:Jan 1, 2006
 Dec 31, 2006
    
    
    4,000
    
    
    WTI (1)
    
    
    $64.08 Cdn




---



##### 



Natural Gas:
 Remaining Term
    Volume (mmbtu per day)
    
    
    Reference Point
    
    Price per mmbtuFinancial:Jan 1, 2006  Mar 31, 2006
    
    
    2,500
    
    
    NYMEX (1)
    
    $14.56 CdnJan 1, 2006  Dec 31, 2006
    
    
    2,500
    
    
    Transco Z6(1)
    
    $10.63 CdnJan 1, 2006  Dec 31, 2006
    
    
    2,370
    
    
    AECO
    
    $8.03 Cdn
 
 (1)
    
    Associated Cdn$ / U.S.$ foreign exchange rate has been fixed.  Natural Gas Fixed Price Sales Contract:
  Remaining Term
    
    Volume (mmbtu per day)
    
    
    Price per mmbtu (1)2006 to 2009Jan 1, 2006  Oct 31, 2006
    
    
    3,886
    
    
    $2.23 CdnNov 1, 2006  Oct 31, 2007
    
    
    3,886
    
    
    $2.29 CdnNov 1, 2007  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
  As at December 31, 2005
    
    
    As at December 31, 2004Net
    
    
    
    
    
    
    
    
    NetFair Value
    
    
    
    Book Value
    
    
    
    Fair Value
    
    
    
    Book ValueRemediation Funds
    
    
    $
    9,071
    
    
    
    $
    8,329
    
    
    
    $
    8,366
    
    
    
    $
    8,309U.S. dollar denominated debt
    
    
    
    220,187
    
    
    
    
    232,600
    
    
    
    
    238,726
    
    
    
    
    240,400£ denominated debt
    
    
    
    101,257
    
    
    
    
    100,489
    
    
    
    
    
    
    
    
    
    




---



##### 



18. Commitments
 2 (1)
 2006
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    2010
    
    
    Thereafter
    
    
    TotalPipeline transportation
    
    $
    43,839
    
    
    $
    38,197
    
    
    $
    34,981
    
    
    $
    29,813
    
    
    $
    11,748
    
    
    $
    53,525
    
    
    $
    212,103Capital expenditures
    
    
    33,323
    
    
    
    7,098
    
    
    
    294
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    40,715CO2 purchases
    
    
    5,119
    
    
    
    4,357
    
    
    
    4,198
    
    
    
    4,232
    
    
    
    4,267
    
    
    
    18,728
    
    
    
    40,901Other commitments
    
    
    3,132
    
    
    
    3,096
    
    
    
    3,950
    
    
    
    3,610
    
    
    
    3,377
    
    
    
    32,779
    
    
    
    49,944$
    85,413
    
    
    $
    52,748
    
    
    $
    43,423
    
    
    $
    37,665
    
    
    $
    19,392
    
    
    $
    105,032
    
    
    $
    343,663
 (1)
    
    Contract prices for
CO2 are denominated in U.S. dollars and
have been translated at the year end foreign exchange rate. 19. Subsequent Event
  20. Reconciliation
of Financial Statements to
 United States Generally Accepted Accounting Principles
 
 (a)
    
    As required annually under U.S. GAAP, the carrying value of petroleum and natural gas
properties and related facilities, net of future or deferred income taxes, is limited to the
present value of after tax future net revenue from proven reserves, discounted at ten percent
(based on prices and costs at the balance sheet date), plus the lower of cost and fair value of
unproven properties. At December 31, 1998 and 1997 the application of the full cost ceiling test
under U.S. GAAP resulted in a write-down of capitalized costs of $328.6 million and $49.8 million,
respectively. At December 31, 2005 and 2004, the application of the full cost ceiling test under
U.S. GAAP did not result in a write-down of capitalized costs.Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of
the write-down under U.S. GAAP, the charge for depletion will differ in subsequent years.(b)
    
    Under U.S. GAAP, interest and other income would not be included as a component of Net Revenue.(c)
    
    Effective January 1, 2003, Pengrowth prospectively adopted U.S. standards relating to
recognizing the compensation expense associated with trust unit based compensation plans. Under
U.S. GAAP Pengrowth adopted the following:




---



##### 



Year ended December 31,
    
    2004Net income
(loss)  U.S. GAAP, as reported
    
    $
    180,045Compensation expense related to rights incentive options granted prior to January 1, 2003
    
    
    (1,067
    )Pro forma
net income  U.S. GAAP
    
    $
    178,978Pro forma
net income  U.S. GAAP per unit:Basic
    
    $
    1.34Diluted
    
    $
    1.34
 (d)
    
    Statement of Financial Accounting Standards (SFAS) 130 requires the reporting of
comprehensive income in addition to net income. Comprehensive income includes net income plus other
comprehensive income; specifically, all changes in equity of a company during a period arising from
non-owner sources.(e)
    
    SFAS 133, Accounting for Derivative Instruments and Hedging Activities establishes accounting
and reporting standards for derivative instruments and for hedging activities. This statement
requires an entity to establish, at the inception of a hedge, the method it will use for assessing
the effectiveness of the hedging derivative and the measurement approach for determining the
ineffective aspect of the hedge. Those methods must be consistent with the entitys approach to
managing risk.At December 31, 2005, $18.4 million has been recorded as a current liability in respect of the
fair value of financial crude oil and natural gas hedges outstanding at year end with a
corresponding change in accumulated other comprehensive income. At December 31, 2004, $7.3 million
has been recorded as a current asset in respect of the fair value of the financial crude oil and
natural gas hedges outstanding at year end with a corresponding change in accumulated other
comprehensive income. These amounts will be recognized against crude oil and natural gas sales over
the remaining terms of the related hedges.




---



##### 



At December 31, 2005, $0.3 million has been recorded as a current liability with respect to
the ineffective portion of crude oil and natural gas hedges outstanding at year end, with a
corresponding change in net income. At December 31, 2004, the ineffective portion of crude oil and
natural gas hedges outstanding at year end was not significant.At December 31, 2005, Pengrowth recorded a loss of $2.2 million relating to the foreign
currency swap associated with the issuance of the £ denominated debt. As of February 14, 2006,
Pengrowth had adequate documentation in place to account for the foreign currency contract as a
hedge under U.S. GAAP.At December 31, 2004, there were no foreign exchange swaps outstanding.(f)
    
    Under U.S. GAAP the Trusts equity is classified as redeemable equity as the Trust units
are redeemable at the option of the holder. The redemption price is equal to the lesser of 95
percent of the market trading price of the Class B trust units traded on the TSX for the 10 trading
days after the trust units have been surrendered for redemption and the closing market price of the
Class B trust units quoted on the TSX on the date the trust units have been surrendered for
redemption. Prior to the reclassification of trust units into Class A or Class B trust units, the
trust units were redeemable as described above except the redemption price was based on the market
trading price of the original trust units. Trust units can be redeemed for cash to a maximum of
$25,000 per month. Redemptions in excess of the cash limit must be satisfied by way of a
distribution in Specie of a pro-rata share of royalty units and other assets, excluding facilities,
pipelines or other assets associated with oil and natural gas production, which are held by the
Trust at the time the trust units are to be redeemed.(g)
    
    Under U.S. standards, an entity that is subject to income tax in multiple jurisdictions is
required to disclose income tax expense at each jurisdiction. Pengrowth is subject to tax at the
federal and provincial level. The portion of income tax expense taxed at the federal level is $12.9
million (2004  $14.8 million). The portion of income tax expense taxed at the provincial level is $5.7 million (2004
 $5.4 million).(h)
    
    In December 2004, the FASB issued SFAS 153 which deals with the accounting for the
exchanges of non-monetary assets. SFAS 153 is an amendment of APB Opinion 29. APB Opinion 29
requires that exchanges of non-monetary assets should be measured based on the fair value of the
assets exchanged. SFAS 153 amends APB Opinion 29 to eliminate the exception from using fair market value for
non-monetary exchanges of similar productive assets and introduce a broader exception for
exchanges of non-monetary assets that do not have commercial substance. SFAS 153 is effective
for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005.
Adopting the provisions of SFAS 153 is not expected to impact the U.S. GAAP financial
statements.In December 2004, the FASB issued SFAS 123R which deals with the accounting for transactions
in which an entity exchanges its equity instruments for goods or services. SFAS 123R also addresses
transactions in which an entity incurs liabilities in exchange for goods or services that are based
on the fair value of the entitys equity instruments or that may be settled by the issuance of
those equity instruments. SFAS 123R focuses primarily on
accounting for transactions in which an entity obtains employee services in share-based payment
transactions. SFAS 123R is a revision of SFAS 123. SFAS 123R




---



##### 



Consolidated Statements of Income
 Stated in thousands of Canadian Dollars, except per unit amountsYears ended December 31,
    
    
    2005
    
    
    
    2004Net income for the year, as reported
    
    
    $
    326,326
    
    
    
    $
    153,745Adjustments:Depletion and depreciation (a)
    
    
    
    24,723
    
    
    
    
    26,000Unrealized gain (loss) on ineffective portion of oil and natural gas hedges (e)
    
    
    
    (255
    )
    
    
    
    300Realized loss on foreign exchange contract (e)
    
    
    
    (2,204
    )
    
    
    
    Net income
 U.S. GAAP
    
    
    $
    348,590
    
    
    
    $
    180,045Other comprehensive income:Realized gain on foreign exchange swap (d)(e)
    
    
    
    
    
    
    
    
    (2,169
    )Unrealized hedging gains (loss) (d)(e)
    
    
    
    (25,470
    )
    
    
    
    21,186Comprehensive income  U.S. GAAP
    
    
    $
    323,120
    
    
    
    $
    199,062Net income
 U.S. GAAPBasic
    
    
    $
    2.22
    
    
    
    $
    1.35Diluted
    
    
    $
    2.21
    
    
    
    $
    1.34




---



##### 



Consolidated Balance Sheets
  Stated in thousands of Canadian
Dollars
    
    As
    
    
    IncreaseDecember 31, 2005
    
    Reported
    
    
    (Decrease)
    
    U.S. GAAPAssets:Capital assets (a)
    
    $
    2,067,988
    
    
    $
    (192,219
    )
    
    $
    1,875,769$
    (192,219
    )LiabilitiesAccounts payable (e)
    
    $
    111,493
    
    
    $
    255
    
    
    $
    111,748Current portion of unrealized hedging loss (e)
    
    
    
    
    
    
    18,153
    
    
    
    18,153Current portion of unrealized foreign currency contract (e)
    
    
    
    
    
    
    2,204
    
    
    
    2,204Unitholders equity (f):Accumulated other comprehensive income (d)(e)
    
    $
    
    
    
    $
    (18,153
    )
    
    $
    (18,153
    )Trust unitholders equity (a)
    
    
    1,475,996
    
    
    
    (194,678
    )
    
    
    1,281,318$
    (192,219
    )
 Stated in thousands of Canadian Dollars
    
    As
    
    
    IncreaseDecember 31, 2004
    
    Reported
    
    
    (Decrease)
    
    U.S. GAAPAssets:Current portion of unrealized hedging gain (e)
    
    $
    
    
    
    $
    7,317
    
    
    $
    7,317Capital assets (a)
    
    
    1,989,288
    
    
    
    (216,942
    )
    
    
    1,772,346$
    (209,625
    )Unitholders equity (f):Accumulated other comprehensive income (d)(e)
    
    $
    
    
    
    $
    7,317
    
    
    $
    7,317Trust unitholders equity (a)
    
    
    1,462,211
    
    
    
    (216,942
    )
    
    
    1,245,269$
    (209,625
    )
 Additional disclosures required under U.S. GAAP
  As at December 31,
    
    2005
    
    
    2004Trade
    
    $
    103,619
    
    
    $
    77,778Prepaids
    
    
    20,230
    
    
    
    15,378Other
    
    
    3,545
    
    
    
    11,072$
    127,394
    
    
    $
    104,228
  As at December 31,
    
    2005
    
    
    2004Accounts payable
    
    $
    50,756
    
    
    $
    37,588Accrued liabilities
    
    
    60,737
    
    
    
    42,835$
    111,493
    
    
    $
    80,423




---



##### 



APPENDIX D
 FIVE YEAR REVIEW  PENGROWTH ENERGY TRUST CONSOLIDATED
FINANCIAL RESULTS (INCLUDED ON PAGES 115 THROUGH 119 OF THE
PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)




---



##### 



Five Year Review
 Consolidated Balance Sheets
 (Stated in thousands of dollars)As at December 31
        
    2005
           
   2004
           
   2003
           
   2002
           
   2001ASSETSCurrent assetsCash and term deposits
    
    
    
    
    
    
    
    
    
    
    64,154
    
    
    
    8,292
    
    
    
    3,797Other current assets
    
    
    127,394
    
    
    
    104,667
    
    
    
    66,269
    
    
    
    44,633
    
    
    
    30,546127,394
    
    
    
    104,667
    
    
    
    130,423
    
    
    
    52,925
    
    
    
    34,343Goodwill
    
    
    182,835
    
    
    
    170,619
    
    
    
    
    
    
    
    
    
    
    
    Property, plant and equipment
    
    
    2,067,988
    
    
    
    1,989,288
    
    
    
    1,530,359
    
    
    
    1,493,047
    
    
    
    1,229,395Other long term assets
    
    
    13,215
    
    
    
    11,960
    
    
    
    12,936
    
    
    
    6,679
    
    
    
    6,4702,391,432
    
    
    
    2,276,534
    
    
    
    1,673,718
    
    
    
    1,552,651
    
    
    
    1,270,208LIABILITIES AND
UNITHOLDERS EQUITYCurrent liabilitiesBank indebtedness
    
    
    14,567
    
    
    
    4,214
    
    
    
    
    
    
    
    
    
    
    
    Other current liabilities
    
    
    225,032
    
    
    
    178,999
    
    
    
    117,457
    
    
    
    89,493
    
    
    
    54,089239,599
    
    
    
    183,213
    
    
    
    117,457
    
    
    
    89,493
    
    
    
    54,089Long term debt
    
    
    368,089
    
    
    
    345,400
    
    
    
    259,300
    
    
    
    316,501
    
    
    
    345,456Other long term liabilities
    
    
    307,748
    
    
    
    285,710
    
    
    
    137,528
    
    
    
    73,493
    
    
    
    42,123Trust unitholders equityTrust unitholders capital
    
    
    2,514,997
    
    
    
    2,383,284
    
    
    
    1,872,924
    
    
    
    1,662,726
    
    
    
    1,280,599Contributed surplus
    
    
    3,646
    
    
    
    1,923
    
    
    
    189
    
    
    
    
    
    
    
    Deficit
    
    
    (1 ,042,647
    )
    
    
    (922,996
    )
    
    
    (713,680
    )
    
    
    (589,562
    )
    
    
    (452,059
    )1,475,996
    
    
    
    1,462,211
    
    
    
    1,159,433
    
    
    
    1,073,164
    
    
    
    828,5402,391,432
    
    
    
    2,276,534
    
    
    
    1,673,718
    
    
    
    1,552,651
    
    
    
    1,270,208




---



##### 



Five Year Review
 Consolidated Statements of Income and Deficit
 (Stated in thousands of dollars)Years ended December 31
    
  2005
        
  2004
        
  2003
        
  2002
        
  2001REVENUESOil and gas sales (1)
    
    
    1,151,510
    
    
    
    815,751
    
    
    
    702,732
    
    
    
    490,472
    
    
    
    479,845Processing and other income
    
    
    15,091
    
    
    
    12,390
    
    
    
    9,726
    
    
    
    6,936
    
    
    
    7,071Royalties, net of incentives (1)
    
    
    (213,863
    )
    
    
    (160,351
    )
    
    
    (126,617
    )
    
    
    (88,777
    )
    
    
    (81,876
    )952,738
    
    
    
    667,790
    
    
    
    585,841
    
    
    
    408,631
    
    
    
    405,040Interest and other income
    
    
    2,596
    
    
    
    1,770
    
    
    
    840
    
    
    
    274
    
    
    
    1,348Net revenues
    
    
    955,334
    
    
    
    669,560
    
    
    
    586,681
    
    
    
    408,905
    
    
    
    406,388EXPENSESOperating
    
    
    218,115
    
    
    
    159,742
    
    
    
    149,032
    
    
    
    129,802
    
    
    
    104,943Transportation
    
    
    7,891
    
    
    
    8,274
    
    
    
    8,225
    
    
    
    
    
    
    
    Amortization of injectants
for miscible floods
    
    
    24,393
    
    
    
    19,669
    
    
    
    32,541
    
    
    
    44,330
    
    
    
    47,448Interest
    
    
    21,642
    
    
    
    29,924
    
    
    
    18,153
    
    
    
    15,213
    
    
    
    18,806General and administrative
    
    
    30,272
    
    
    
    24,448
    
    
    
    15,997
    
    
    
    10,992
    
    
    
    7,467Management fee
    
    
    15,961
    
    
    
    12,874
    
    
    
    10,181
    
    
    
    6,567
    
    
    
    7,120Foreign exchange loss (gain)
    
    
    (6,966
    )
    
    
    (17,300
    )
    
    
    (29,911
    )
    
    
    182
    
    
    
    0Depletion and depreciation
    
    
    284,989
    
    
    
    247,332
    
    
    
    185,270
    
    
    
    140,775
    
    
    
    126,409Accretion
    
    
    14,162
    
    
    
    10,642
    
    
    
    6,039
    
    
    
    3,566
    
    
    
    3,293610,459
    
    
    
    495,605
    
    
    
    395,527
    
    
    
    351,427
    
    
    
    315,486Income before taxes
    
    
    344,875
    
    
    
    173,955
    
    
    
    191,154
    
    
    
    57,478
    
    
    
    90,902Income tax expenseCapital
    
    
    6,273
    
    
    
    4,594
    
    
    
    1,857
    
    
    
    523
    
    
    
    2,717Future
    
    
    12,276
    
    
    
    15,616
    
    
    
    
    
    
    
    
    
    
    
    18,549
    
    
    
    20,210
    
    
    
    1,857
    
    
    
    523
    
    
    
    2,717NET INCOME
    
    
    326,326
    
    
    
    153,745
    
    
    
    189,297
    
    
    
    56,955
    
    
    
    88,185Deficit, beginning of year
    
    
    (922,996
    )
    
    
    (713,680
    )
    
    
    (589,562
    )
    
    
    (452,059
    )
    
    
    (324,457
    )Distributions paid or declared
    
    
    (445,977
    )
    
    
    (363,061
    )
    
    
    (313,415
    )
    
    
    (194,458
    )
    
    
    (215,787
    )Deficit, end of year
    
    
    ( 1,042,647
    )
    
    
    (922,996
    )
    
    
    (713,680
    )
    
    
    (589,562
    )
    
    
    (452,059
    )Net income per trust unitBasic
    
    
    2.08
    
    
    
    1.15
    
    
    
    1.63
    
    
    
    0.63
    
    
    
    1.24Diluted
    
    
    2.07
    
    
    
    1.15
    
    
    
    1.63
    
    
    
    0.63
    
    
    
    1.24
 (1)Prior years restated to conform to presentation adopted in current year.




---



##### 



Five Year Review
 Consolidated Statements of Cash Flow
 (Stated in thousands of dollars)Years ended December 31
    
    2005
    
    2004
    
2003
    
2002
     
2001CASH PROVIDED BY (USED FOR):OperatingNet income
    
    
    326,326
    
    
    
    153,745
    
    
    
    189,297
    
    
    
    56,955
    
    
    
    88,185Depletion and depreciation
    
    
    284,989
    
    
    
    247,332
    
    
    
    185,270
    
    
    
    140,775
    
    
    
    126,409Accretion
    
    
    14,162
    
    
    
    10,642
    
    
    
    6,039
    
    
    
    3,566
    
    
    
    3,293Future income taxes
    
    
    12,276
    
    
    
    15,616
    
    
    
    
    
    
    
    
    
    
    
    Amortization of injectants
    
    
    24,393
    
    
    
    19,669
    
    
    
    32,541
    
    
    
    44,330
    
    
    
    47,448Purchase of injectants
    
    
    (34,658
    )
    
    
    (20,415
    )
    
    
    (23,037
    )
    
    
    (15,107
    )
    
    
    (56,352
    )Other non-cash items
    
    
    (19,251
    )
    
    
    (23,595
    )
    
    
    (33,696
    )
    
    
    (1,783
    )
    
    
    (1,223
    )Changes in non-cash
operating working capital
    
    
    9,833
    
    
    
    1,173
    
    
    
    (9,863
    )
    
    
    120
    
    
    
    (2,919
    )618,070
    
    
    
    404,167
    
    
    
    346,551
    
    
    
    228,856
    
    
    
    204,841FinancingDistributions
    
    
    (436,450
    )
    
    
    (344,744
    )
    
    
    (306,591
    )
    
    
    (171,350
    )
    
    
    (241,590
    )Changes in long term debt
and note payable
    
    
    (4,970
    )
    
    
    95,000
    
    
    
    15,132
    
    
    
    (28,955
    )
    
    
    58,080Proceeds from issue of trust units
    
    
    42,544
    
    
    
    509,830
    
    
    
    210,198
    
    
    
    382,127
    
    
    
    305,875(398,876
    )
    
    
    260,086
    
    
    
    (81,261
    )
    
    
    181,822
    
    
    
    122,365InvestingExpenditures on property acquisitions
    
    
    (92,568
    )
    
    
    (572,980
    )
    
    
    (122,964
    )
    
    
    (391,761
    )
    
    
    (280,058
    )Expenditures on property,
plant and equipment
    
    
    (175,693
    )
    
    
    (161,141
    )
    
    
    (85,718
    )
    
    
    (55,631
    )
    
    
    (74,026
    )Other items
    
    
    38,714
    
    
    
    1,500
    
    
    
    (746
    )
    
    
    41,209
    
    
    
    26,142(229,547
    )
    
    
    (732,621
    )
    
    
    (209,428
    )
    
    
    (406,183
    )
    
    
    (327,942
    )Change in cash and term deposits
    
    
    (10,353
    )
    
    
    (68,368
    )
    
    
    55,862
    
    
    
    4,495
    
    
    
    (736
    )Cash and term deposits
(bank indebtedness)
at beginning of year
    
    
    (4,214
    )
    
    
    64,154
    
    
    
    8,292
    
    
    
    3,797
    
    
    
    4,533Cash and term deposits
(bank indebtedness) at year end
    
    
    (14,567
    )
    
    
    (4,214
    )
    
    
    64,154
    
    
    
    8,292
    
    
    
    3,797




---



##### 



Five Year Review
 Operating Measures
 Years ended December 31
    
    2005
        
    2004
        
    2003
        
    2002
        
        2001PRODUCTIONCrude Oil (bbl per day)
    
    
    20,799
    
    
    
    20,817
    
    
    
    23,337
    
    
    
    19,914
    
    
    
    19,726Heavy Oil (bbl per day)
    
    
    5,623
    
    
    
    3,558
    
    
    
    
    
    
    
    
    
    
    
    Natural Gas (mcf per day)
    
    
    161,056
    
    
    
    144,277
    
    
    
    119,842
    
    
    
    111,713
    
    
    
    91,764Natural gas liquids (bbl per day)
    
    
    6,093
    
    
    
    5,281
    
    
    
    5,722
    
    
    
    5,252
    
    
    
    5,258Total (boe per day)
    
    
    59,357
    
    
    
    53,702
    
    
    
    49,033
    
    
    
    43,785
    
    
    
    40,320Annual (mmboe)
    
    
    21.7
    
    
    
    19.7
    
    
    
    17.9
    
    
    
    16.0
    
    
    
    14.7% natural gas
    
    
    45
    
    
    
    45
    
    
    
    41
    
    
    
    43
    
    
    
    38Production per weighted average
trust unit outstanding (boe)
    
    
    0.14
    
    
    
    0.15
    
    
    
    0.15
    
    
    
    0.18
    
    
    
    0.21BENCHMARK PRICESWTI (U.S. $  per bbl)
    
    $
    56.70
    
    
    $
    41.47
    
    
    $
    30.99
    
    
    $
    26.08
    
    
    $
    25.90NYMEX (U.S. $  per mmbtu)
    
    $
    8.62
    
    
    $
    6.16
    
    
    $
    5.39
    
    
    $
    3.22
    
    
    $
    4.27AECO (Cdn $  per mcf)
    
    $
    8.48
    
    
    $
    6.79
    
    
    $
    6.70
    
    
    $
    4.07
    
    
    $
    6.30Currency (U.S. $  per Cdn $)
    
    $
    0.83
    
    
    $
    0.77
    
    
    $
    0.71
    
    
    $
    0.64
    
    
    $
    0.65AVERAGE REALIZED PRICESOil ($  per bbl)
    
    $
    58.59
    
    
    $
    43.21
    
    
    $
    40.85
    
    
    $
    38.06
    
    
    $
    37.26Heavy Oil ($  per bbl)
    
    $
    33.32
    
    
    $
    32.45
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    n/aNatural Gas ( $  per mcf)
    
    $
    8.76
    
    
    $
    6.80
    
    
    $
    6.35
    
    
    $
    3.85
    
    
    $
    4.48Natural gas liquids ($  per bbl)
    
    $
    54.22
    
    
    $
    42.21
    
    
    $
    35.54
    
    
    $
    28.11
    
    
    $
    30.68Average price per boe (1)
    
    $
    53.02
    
    
    $
    41.33
    
    
    $
    39.12
    
    
    $
    30.50
    
    
    $
    32.47AVERAGE NETBACKLight oil
netback ( $ per bbl)
    
    $
    35.01
    
    
    $
    24.38
    
    
    $
    23.40
    
    
    
    n/a
    
    
    
    n/aHeavy oil netback ($ per bbl)
    
    $
    13.50
    
    
    $
    17.73
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    n/aNatural gas
netback ( $ per mcf)
    
    $
    5.95
    
    
    $
    4.47
    
    
    $
    3.89
    
    
    
    n/a
    
    
    
    n/aNGL netback
( $ per bbl)
    
    $
    27.52
    
    
    $
    18.74
    
    
    $
    13.09
    
    
    
    n/a
    
    
    
    n/aOperating netback ($  per boe)
    
    $
    32.54
    
    
    $
    24.51
    
    
    $
    22.17
    
    
    $
    14.70
    
    
    $
    17.25Property acquisitions ($ millions)
    
    $
    175.1
    
    
    $
    569.7
    
    
    $
    126.5
    
    
    $
    389.3
    
    
    $
    277.1Capital expenditures ($ millions)
    
    $
    175.7
    
    
    $
    161.1
    
    
    $
    85.7
    
    
    $
    55.6
    
    
    $
    74.0Reserves (proved plus probable)Reserves acquired in the year (mmboe)
    
    
    16.7
    
    
    
    47.9
    
    
    
    n/a
    
    
    
    37.7
    
    
    
    48.4Reserves at year end (mmboe)
    
    
    219.4
    
    
    
    218.6
    
    
    
    184.4
    
    
    
    214.8
    
    
    
    210.5Acquisition cost per boe (1)
    
    $
    10.49
    
    
    $
    11.89
    
    
    
    n/a
    
    
    $
    10.33
    
    
    $
    5.72Reserves per year end
trust units outstanding
    
    
    1.37
    
    
    
    1.43
    
    
    
    1.49
    
    
    
    1.94
    
    
    
    2.56
 (1)Prior years restated to conform to presentation adopted in current year.




---



##### 



Five Year Review
 Financial Measures
 (Stated in thousands of dollars, except per trust unit amounts)Years ended December 31
    
    2005
      
    2004
      
    2003
      
    2002
      
    2001Expenses(per boe)Royalties
    
    $
    9.87
    
    
    $
    8.16
    
    
    $
    7.07
    
    
    $
    5.56
    
    
    $
    5.56Operating
    
    $
    10.07
    
    
    $
    8.13
    
    
    $
    8.33
    
    
    $
    8.12
    
    
    $
    7.13Transportation
    
    $
    0.36
    
    
    $
    0.42
    
    
    $
    0.46
    
    
    $
    
    
    
    $
    Amortization of injectants for
miscible floods
    
    $
    1.13
    
    
    $
    1.00
    
    
    $
    1.82
    
    
    $
    2.77
    
    
    $
    3.22Interest
    
    $
    1.00
    
    
    $
    1.52
    
    
    $
    1.01
    
    
    $
    0.95
    
    
    $
    1.28General and administrative
    
    $
    1.40
    
    
    $
    1.24
    
    
    $
    0.89
    
    
    $
    0.69
    
    
    $
    0.51Management fee
    
    $
    0.74
    
    
    $
    0.66
    
    
    $
    0.57
    
    
    $
    0.41
    
    
    $
    0.48Depletion and depreciation
    
    $
    13.15
    
    
    $
    12.58
    
    
    $
    10.35
    
    
    $
    8.81
    
    
    $
    8.59Accretion
    
    $
    0.65
    
    
    $
    0.54
    
    
    $
    0.34
    
    
    $
    0.22
    
    
    $
    0.22Net income
    
    $
    326,326
    
    
    $
    153,745
    
    
    $
    189,297
    
    
    $
    56,955
    
    
    $
    88,185Net income per trust unit
    
    $
    2.08
    
    
    $
    1.15
    
    
    $
    1.63
    
    
    $
    0.63
    
    
    $
    1.24Distributable CashCash Generated from Operations
    
    $
    618,070
    
    
    $
    404,167
    
    
    $
    346,551
    
    
    $
    228,856
    
    
    $
    204,841Cash Generated from Operations
per trust unit
    
    $
    3.93
    
    
    $
    3.03
    
    
    $
    2.99
    
    
    $
    2.55
    
    
    $
    2.89Distributable cash (1)
    
    $
    619,739
    
    
    $
    401,178
    
    
    $
    345,911
    
    
    $
    199,480
    
    
    $
    215,787Distributable cash per trust unit (1)
    
    $
    3.94
    
    
    $
    3.01
    
    
    $
    2.98
    
    
    $
    2.22
    
    
    $
    3.04Actual distributions paid or declared
    
    $
    445,977
    
    
    $
    363,061
    
    
    $
    313,415
    
    
    $
    194,458
    
    
    $
    215,787Actual distributions paid or
declared per trust unit
    
    $
    2.82
    
    
    $
    2.63
    
    
    $
    2.68
    
    
    $
    2.07
    
    
    $
    3.01Payout Ratio (%)
    
    
    72
    
    
    
    90
    
    
    
    90
    
    
    
    85
    
    
    
    105Number of trust units outstandingWeighted average
    
    
    157,127
    
    
    
    133,395
    
    
    
    115,912
    
    
    
    89,923
    
    
    
    70,911Total at year end
    
    
    159,864
    
    
    
    152,973
    
    
    
    123,874
    
    
    
    110,562
    
    
    
    82,240Total assets
    
    $
    2,391,432
    
    
    $
    2,276,534
    
    
    $
    1,673,718
    
    
    $
    1,552,651
    
    
    $
    1,270,208Total assets per trust unit
    
    $
    14.96
    
    
    $
    14.88
    
    
    $
    13.51
    
    
    $
    14.04
    
    
    $
    15.45Long term debt
    
    $
    368,089
    
    
    $
    345,400
    
    
    $
    259,300
    
    
    $
    316,501
    
    
    $
    345,456Long term debt per trust unit
    
    $
    2.30
    
    
    $
    2.26
    
    
    $
    2.09
    
    
    $
    2.86
    
    
    $
    4.20Unitholders equity
    
    $
    1,475,996
    
    
    $
    1,462,211
    
    
    $
    1,159,433
    
    
    $
    1,073,164
    
    
    $
    828,540Unitholders equity per trust unit
    
    $
    9.23
    
    
    $
    9.56
    
    
    $
    9.36
    
    
    $
    9.71
    
    
    $
    10.07Net asset value at 10%
    
    $
    2,834,663
    
    
    $
    1,708,012
    
    
    $
    1,124,433
    
    
    $
    1,239,322
    
    
    $
    914,970Net asset value per trust unit
    
    $
    17.73
    
    
    $
    11.17
    
    
    $
    9.08
    
    
    $
    11.21
    
    
    $
    11.13Capitalization highlightsNet debt (net of working capital)
    
    $
    480,294
    
    
    $
    443,946
    
    
    $
    281,334
    
    
    $
    353,069
    
    
    $
    365,202Unitholders equity
    
    $
    1,475,996
    
    
    $
    1,462,211
    
    
    $
    1,159,433
    
    
    $
    1,073,164
    
    
    $
    828,540Total book capitalization
    
    $
    1,956,290
    
    
    $
    1,906,157
    
    
    $
    1,440,767
    
    
    $
    1,426,233
    
    
    $
    1,193,742Equity Market capitalization
    
    $
    3,989,939
    
    
    $
    3,323,770
    
    
    $
    2,632,315
    
    
    $
    1,628,583
    
    
    $
    1,169,454Enterprise value
    
    $
    4,358,028
    
    
    $
    3,669,170
    
    
    $
    2,891,615
    
    
    $
    1,945,084
    
    
    $
    1,514,910Return on average equity (%)
    
    
    22.2
    
    
    
    11.7
    
    
    
    17.0
    
    
    
    6.0
    
    
    
    11.9Cash flow return on average equity (%)
    
    
    30.3
    
    
    
    27.7
    
    
    
    28.1
    
    
    
    20.5
    
    
    
    29.2Average cost of debt capital (%)(1)
    
    
    4.6
    
    
    
    5.1
    
    
    
    5.1
    
    
    
    4.6
    
    
    
    5.2
 (1)Prior years restated to conform to presentation adopted in current year.




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APPENDIX E
 CORPORATE GOVERNANCE (INCLUDED ON PAGES 48 THROUGH 53 OF THE
PENGROWTH ENERGY TRUST 2005 ANNUAL REPORT)




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Corporate Governance
 
 Board of Directors
 From left to right
              Back row:
    Michael Parrett
          Terry Poole
      Kirby Hedrick
 Seated:
           Stan Wong
     John Zaozirny
        Jim Kinnear
     Tom Cumming
 Board Of Directors
 Thomas A. Cumming, B.A.Sc., P.Eng.
  Kirby L. Hedrick, B.Sc, P.Eng.




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##### 



James S. Kinnear, B.Sc., CFA, Chairman, President and Chief Executive Officer,
  Michael S. Parrett, B.A. Econ., CA
  A. Terence Poole, B.Comm., CA
  Stanley H. Wong, B.Sc., P.Eng.
  John B. Zaozirny, Q.C., B.Comm., LL.B., LL.M., Lead Director




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Corporate Governance
        Audit Committee




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Corporate Governance Committee




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Compensation Committee
  Reserves Committee




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Board of Directors
  The Manager




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




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




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##### 



RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
  2005
    
    
    2004(thousands of dollars)RevenueSales
    
    $
    952,738
    
    
    $
    667,790DeductProduction costs
    
    
    208,140
    
    
    
    152,400Transportation costs
    
    
    7,891
    
    
    
    8,274Amortization of injectant costs
    
    
    24,393
    
    
    
    19,669Technical support and other
    
    
    9,975
    
    
    
    7,342Depletion, depreciation and amortization
    
    
    260,266
    
    
    
    221,332Results of operations from producing activities
    
    $
    442,073
    
    
    $
    258,773
 
 1.
    
    The costs in this schedule exclude corporate overhead, interest expense and other operating
costs which are not directly related to producing activities.




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COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
  2005
    
    
    2004(thousands of dollars)Property Acquisition CostsProved
    
    $
    208,424
    
    
    $
    512,348Unproved
    
    
    18,697
    
    
    
    12,766Development Costs
    
    
    169,314
    
    
    
    161,141Injectant Costs
    
    
    34,658
    
    
    
    20,415$
    431,093
    
    
    $
    706,670
      CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
  2005
    
    
    2004(thousands of dollars)Oil and gas properties
    
    $
    3,375,412
    
    
    $
    3,011,723Less accumulated depletion, depreciation and amortization
    
    
    (1,499,643
    )
    
    
    (1,239,377
    )Net capitalized costs
    
    $
    1,875,769
    
    
    $
    1,772,346




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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 2003
    
    
    77.3
    
    
    
    271.4Revision of previous estimates
    
    
    1.7
    
    
    
    16.0Purchase of reserves in place
    
    
    17.0
    
    
    
    97.1Sales of reserves in place
    
    
    
    
    
    
    Discoveries and extensions
    
    
    0.1
    
    
    
    1.8Production
    
    
    (8.8
    )
    
    
    (42.7
    )End of year 2004
    
    
    87.3
    
    
    
    343.6Revision of previous estimates
    
    
    3.1
    
    
    
    11.6Purchase of reserves in place
    
    
    8.0
    
    
    
    15.2Sales of reserves in place
    
    
    (1.2
    )
    
    
    (3.9
    )Discoveries and extensions
    
    
    0.6
    
    
    
    15.6Production
    
    
    (9.6
    )
    
    
    (48.6
    )End of year 2005
    
    
    88.2
    
    
    
    333.5NET PROVED DEVELOPED RESERVES AFTER ROYALTIESEnd of year 2003
    
    
    60.6
    
    
    
    219.9End of year 2004
    
    
    70.5
    
    
    
    305.7End of year 2005
    
    
    70.4
    
    
    
    309.3
 
 Notes:1.
    
    Net after royalty reserves are the Trusts lessor royalty, overriding royalty, and
working interest share of the gross remaining reserves, after deduction of any crown,
freehold and overriding royalties. 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
  2005
    
    
    2004(millions of dollars)Future cash inflows
    
    $
    8,591
    
    
    $
    5,869Future costsFuture production and development costs
    
    
    (2,892
    )
    
    
    (2,494
    )Future net cash flows
    
    
    5,699
    
    
    
    3,375Deduct: 10% annual discount factor
    
    
    (2,355
    )
    
    
    (1,383
    )Standardized measure of discounted future net cash flows
    
    $
    3,344
    
    
    $
    1,992




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CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS RESERVES
  2005
    
    
    2004(2)(millions of dollars)Future discounted net cash flows at beginning of year
    
    $
    1,992
    
    
    $
    1,604Sales and transfer, net of production costs
    
    
    (706
    )
    
    
    (480
    )Net change in sales and transfer prices, net of production costs
    
    
    1,450
    
    
    
    176Development costs during the year
    
    
    169
    
    
    
    161Change in future development costs
    
    
    (139
    )
    
    
    (166
    )Changes due to extensions and discoveries
    
    
    74
    
    
    
    5Changes due to revisions (including infill drilling and improved recovery)
    
    
    109
    
    
    
    58Accretion of discount
    
    
    199
    
    
    
    160Sales of reserves in place
    
    
    (26
    )
    
    
    Purchase of reserves in place
    
    
    196
    
    
    
    459Changes in timing of future net cash flows and other
    
    
    26
    
    
    
    15End of Year
    
    $
    3,344
    
    
    $
    1,992
 
 Notes: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.2.
    
    Certain prior year amounts have been restated to conform to presentation adopted in current
year.