##### 



U.S. SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, D.C. 20549
 FORM 40-F
 o
    
    REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE
SECURITIES EXCHANGE ACT OF 1934.
 þ
    
    ANNUAL REPORT PURSUANT TO SECTION 13(a) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended: December 31, 2006
 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  4 th Avenue S.W.  Calgary, Alberta Canada T2P 4H4  (403) 233-0224
 CT Corporation System
111-8 th Avenue, New York, New York 10011  (212) 894-8940
 
  Brad D. Markel 
Bennett Jones LLP 
4500 Bankers Hall East 
855  2ndStreet SW 
Calgary, Alberta T2P 4K7 Canada
(403) 298-3100
    
    Edwin S. Maynard
Paul, Weiss, Rifkind, Wharton & Garrison
LLP
1285 Avenue of the Americas
New York, New York 10019-6064 USA
(212) 373-3000
 Securities registered or to be registered pursuant to Section 12(b) of the Act.
 Title of each class
    
    Name of each exchange on which registeredTrust Units
    
    New York Stock Exchange
 Securities registered or to be registered pursuant to Section 12(g) of the Act.
 None
  Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
 None
   þ þ
    o þ
  þ o




---



##### 



DOCUMENTS FILED AS PART OF THIS ANNUAL REPORT
  Appendix
    
    DocumentsA
    
    Pengrowth Energy Trust Annual Information Form for the year ended
December 31, 2006.B
    
    Managements Discussion and Analysis.C
    
    Consolidated Financial Statements of Pengrowth Energy Trust,
including Managements Report to Unitholders, the Auditors
Report and note 23 thereof which includes a reconciliation of the
Consolidated Financial Statements to United States generally
accepted accounting principles.D
    
    Oil and Gas Producing Activities Prepared in Accordance with SFAS
No. 69  Disclosures about Oil and Gas Producing Activities.E
    
    Pengrowth Energy Trust Code of
Business Conduct and Ethics dated December 2006.
 CERTIFICATIONS AND DISCLOSURE REGARDING CONTROLS AND PROCEDURES
 Certifications
 Disclosure Controls and Procedures
 Managements Annual Report on Internal Control Over Financial Reporting
 Attestation Report of the Registered Public Accounting Firm
 Changes in Internal Control Over Financial Reporting
 NOTICES PURSUANT TO REGULATION BTR
  IDENTIFICATION OF THE AUDIT COMMITTEE




---



##### 



AUDIT COMMITTEE FINANCIAL EXPERT
  ADDITIONAL DISCLOSURE
  UNDERTAKING




---



##### 



SIGNATURES
  Date: March 30, 2007
    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, 2006




---



##### 



PENGROWTH ENERGY TRUST
 ANNUAL INFORMATION FORM
 For the year ended December 31, 2006
 March 30, 2007




---



##### 



TABLE OF CONTENTS
 GLOSSARY OF TERMS AND ABBREVIATIONS
    
    
    1Corporate
    
    
    1CONVERSION
    
    
    4PRESENTATION OF OUR FINANCIAL INFORMATION
    
    
    5PRESENTATION OF OUR RESERVE INFORMATION
    
    
    5FORWARD-LOOKING STATEMENTS
    
    
    5PENGROWTH ENERGY TRUST
    
    
    7Introduction
    
    
    7The Trust
    
    
    7The Corporation
    
    
    7The Trusts Subsidiaries
    
    
    7The Corporations Subsidiaries
    
    
    8The Manager
    
    
    8Intercorporate Relationships
    
    
    10Business Strategy and Strengths
    
    
    10Historical Developments
    
    
    12Recent Acquisitions, Financings and Developments
    
    
    14Trends
    
    
    17PENGROWTH MANAGEMENT LIMITED
    
    
    18Business
    
    
    18Management Agreement
    
    
    18Management Fee
    
    
    20Management Agreement Second Term
    
    
    20PENGROWTH  OPERATIONAL INFORMATION
    
    
    21Principle Properties
    
    
    21Statement of Oil and Gas Reserves and Reserves Data
    
    
    29Additional Information Relating to Reserves Data
    
    
    42Future Development Costs
    
    
    43Finding, Development and Acquisition Costs
    
    
    44Other Oil and Gas Information
    
    
    47Replacement of Properties
    
    
    53Borrowing
    
    
    53TRUST UNITS
    
    
    53The Trust Indenture
    
    
    53The Trustee
    
    
    54Stock Exchange Listings
    
    
    54Ownership Restrictions
    
    
    54Redemption Right
    
    
    54Conversion Rights
    
    
    55Voting at Meetings of Unitholders
    
    
    55Voting at Meetings of Corporation
    
    
    55Termination of the Trust
    
    
    55Unitholder Limited Liability
    
    
    56THE ROYALTY INDENTURE
    
    
    56Royalty Units
    
    
    56The Royalty
    
    
    56The Trustee
    
    
    57EXCHANGEABLE SHARES
    
    
    58DISTRIBUTIONS
    
    
    59TRUST TAXATION
    
    
    59




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##### 



CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
    
    
    60Status of the Trust
    
    
    61Taxation of the Trust
    
    
    62Taxation of Unitholders Resident in Canada
    
    
    62Taxation of Unitholders who are Non-Residents of Canada (Non-Resident Unitholders)
    
    
    62UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
    
    
    64Classification of Pengrowth Energy Trust as a Partnership
    
    
    64Possible Classification as a Corporation; PFIC Rules
    
    
    65Consequences of Possible PFIC Classification
    
    
    65Tax Consequences of Trust Unit Ownership
    
    
    66Tax Treatment of Trust Operations
    
    
    68Disposition of Trust Units
    
    
    69Disposition of Trust Units by Redemption
    
    
    71Uniformity of Trust Units
    
    
    71Tax-Exempt Organizations
    
    
    71Administrative Matters
    
    
    72Reportable Transactions
    
    
    72Foreign Partnership Reporting
    
    
    73INDUSTRY CONDITIONS
    
    
    73Government Regulation
    
    
    73Pricing and Marketing  Oil
    
    
    73Pricing and Marketing  Natural Gas
    
    
    73Pricing and Marketing  Natural Gas Liquids
    
    
    74Environmental Regulation
    
    
    75MARKET FOR SECURITIES
    
    
    76DIRECTORS AND OFFICERS
    
    
    77Directors and Officers of Pengrowth Management Limited
    
    
    77Principal Holders of Shares of Pengrowth Management
    
    
    78Directors and Officers of the Corporation
    
    
    78Corporate Cease Trade Orders or Bankruptcies
    
    
    80Personal Bankruptcies
    
    
    80Penalties or Sanctions
    
    
    80AUDIT COMMITTEE
    
    
    80Principal Accountant Fees and Services
    
    
    81Pre-approval Policies and Procedures
    
    
    82RISK FACTORS
    
    
    82CONFLICTS OF INTEREST
    
    
    95LEGAL PROCEEDINGS
    
    
    96INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    
    
    96INTERESTS OF EXPERTS
    
    
    97AUDITORS, TRANSFER AGENT AND REGISTRAR
    
    
    97MATERIAL CONTRACTS
    
    
    97CODE OF ETHICS
    
    
    97OFF-BALANCE SHEET ARRANGEMENTS
    
    
    98DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE
    
    
    98ADDITIONAL INFORMATION
    
    
    99
  Unless otherwise indicated, all of the information provided in this Annual Information Form
is as at December 31, 2006.




---



##### 



GLOSSARY OF TERMS AND ABBREVIATIONS
  
 Corporate
 
    
    Boardor Board of Directorsrefers to the board of directors of the Corporation;
    
    Class A Trust Unitsrefers to the class A trust units of the Trust created and
issued pursuant to the Trust Indenture;
    
    Class B Trust Unitsrefers to the class B trust units of the Trust issued and
outstanding prior to the Consolidation;
    
    Common Sharesrefers to the common shares in the capital of the Corporation;
    
    Computersharerefers to Computershare Trust Company of Canada;
    
    Consolidationhas the meaning ascribed thereto under Recent Acquisitions,
Financings and Developments  Trust Unit Consolidation;
    
    Corporationrefers to Pengrowth Corporation, the administrator of the Trust;
    
    Managerrefers to Pengrowth Management Limited, the manager of the Trust and the
Corporation;
    
    October 31 Proposalshas the meaning ascribed thereto under Canadian Federal Income
Tax Considerations;
    
    Pengrowth, we, usand ourrefers to the Trust and all of its wholly-owned direct and
indirect subsidiary entities on a consolidated basis;
    
    Royalty Indenturerefers to the amended and restated royalty indenture of the
Corporation, dated July 27, 2006;
    
    Royalty Unitholderrefers to holders of Royalty Units;
    
    Royalty Unitsrefers to the royalty units of the Corporation created and issued
pursuant to the Royalty Indenture;
    
    Trustrefers to Pengrowth Energy Trust;
    
    Trust Indenturerefers to the amended and restated trust indenture of the Trust,
dated July 27, 2006;
    
    Trust Unitsrefers to the Trust Units of the Trust created and issued pursuant to
the Trust Indenture;
    
    Unitholdersrefers to holders of Trust Units and Class A Trust Units.




---



##### 



Engineering
 
    
    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 Reportsrefers to the reports prepared by GLJ, with respect to Pengrowths
properties, dated February 1, 2007, and with respect to the CP Properties, dated March
5, 2007, each having an effective date of December 31, 2006;
    
    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 Pengrowth Gross Interest plus Pengrowth
Royalty Interest. That is, the working interest share of production or reserves prior
to the deduction of royalties plus the interest in production made from gross
production or reserves at the wellhead;
    
    Pengrowth Gross Interestrefers to Pengrowths working interest share of reserves
prior to the deduction of royalties. Pengrowth Royalty Interest reserves are not
included in the Pengrowth Gross Interest reserves;
    
    Pengrowth Net Interestrefers to Pengrowths working interest share of production or
reserves, as the case may be, after the deduction of royalties and including Pengrowth
Royalty Interest reserves, and, with respect to land and wells, refers to Pengrowths
working interest share therein;
    
    Pengrowth Royalty Interestrefers to Pengrowths 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;
    
    Pengrowth Total Proved Plus Probable Reservesmeans Pengrowth Company Interest share
of the Total Proved Plus Probable Reserves;
 -2-




---



##### 




    
    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 estimated reserves of a property from the GLJ Reports by the estimated
production per year from such property using estimated production associated with the
reserves from the GLJ Report for the year 2007 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 recovered 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 reserves classification (proved, probable) to which they are assigned; and
    
    working interestrefers to the percentage of undivided interest, excluding royalty
interest, held by Pengrowth in an oil and gas property.
 Abbreviations
 
    
    APIrefers to the American Petroleum Institute;
    
    °APIrefers to an indication of the specific gravity of crude oil measured on the API
gravity scale;
    
    bbl, bbls, mbbls,and mmbblsrefers to barrel, barrels, thousands of barrels and
millions of barrels, respectively;
    
    bblpdrefers to barrels per day;
    
    boe, mboeand 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;
 -3-




---



##### 




    
    boepdrefers to barrels of oil equivalent per day;
    
    CBMrefers to coal bed methane;
    
    $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;
    
    TSXrefers to the Toronto Stock Exchange; and
    
    WTIrefers to West Texas Intermediate.
 Disclosure provided herein in respect of a boe may be misleading, particularly if used in
isolation. A boe conversation ratio of six mcf of natural gas to one barrel of crude oil
equivalent is based on an energy equivalency conversion method primarily applicable at the burner
tip and does not represent a value equivalency at the wellhead.
 
 CONVERSION
  To Convert From
    
    To
    
    Multiply bymcf
    
    cubic metre
    
    28.174cubic metre
    
    cubic feet
    
    35.494bbls
    
    cubic metre
    
    0.159cubic metre
    
    bbls
    
    6.290feet
    
    metre
    
    0.305metre
    
    feet
    
    3.281miles
    
    kilometre
    
    1.609kilometre
    
    miles
    
    0.621acres
    
    hectares
    
    0.405hectares
    
    acres
    
    2.471
  -4-




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##### 



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




---



##### 



Risk Factors
  -6-




---



##### 



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




---



##### 



Recent Acquisitions, Financings
and Developments  Esprit Merger
 
 The Corporations Subsidiaries
  Recent Acquisitions, Financings and
Developments  Carson Creek Acquisition
 Recent
Acquisitions, Financings and Developments  CP Acquisition
 
 The Manager
  -8-




---



##### 



Pengrowth Management Limited
 -9-




---



##### 



Intercorporate Relationships
  
 
 Business Strategy and Strengths
  -10-




---



##### 



Financial
 
    
    Acquisitions should be accretive on a per Trust Unit basis based upon current
economics and forecast parameters.
    
    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. Pengrowth gives priority to properties with:
 
    
    low anticipated capital expenditures relative to the cash
generation potential of the properties;
    
    relatively low operating costs or high netbacks;
    
    experienced, well regarded industry operators or where
operatorship may be assumed by Pengrowth;
    
    favourable production history;
    
    upside potential through infill drilling, improved field
operations and other development activities;
    
    potential synergies with our current properties and areas of our core expertise; and
    
    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.
 Trust Taxation Canadian Federal Income Tax
Considerations Risk Factors  The October 31 Proposals, if enacted, are expected to
materially and adversely affect the Trust, the Unitholders and the value of the Trust Units
 -11-




---



##### 



Historical Developments
         -12-




---



##### 



Business Corporations Act
 -13-




---



##### 



Recent
Acquisitions, Financings and Developments
 
 Recent Acquisitions, Financings and Developments
 Monterey Transaction
   Dunvegan Acquisition
  Borrowing
   -14-




---



##### 



Trust Unit Consolidation
 Trust Units  Redemption Right Trust Units  Conversion
Rights
 Carson Creek Acquisition
  Esprit Merger
    -15-




---



##### 



Convertible Debentures
   CP Acquisition
      2007 Forecast Capital, Production and Operating Costs
  -16-




---



##### 



Planned Capital Expenditures
    
    $ Millions
    
    % of TotalDrilling and Completion Expenditures
    
    
    198
    
    
    
    66Facilities and Maintenance
    
    
    59
    
    
    
    20Land and Seismic
    
    
    18
    
    
    
    6Office Building
    
    
    25
    
    
    
    8Total
    
    
    300
    
    
    
    100Average daily production volume (boepd)
    
    
    83,000 -- 87,500
    (1)Operating costs per boe
    
    $
    13.00
    (2)
 Notes:
 (1)
    
    Includes anticipated divestitures with approximately
7,700 boepd of associated current production, expected to close in the
first and second quarters of 2007 with anticipated proceeds of
$300 million to $450 million, prior to any adjustments.
There can be no assurance regarding the completion of such divestitures, the timing thereof,
or the proceeds therefrom. The volume of current production divested may or may not exceed
7,700 boepd.
The 2007 estimate excludes potential additions through acquisitions other than the CP Acquisition.(2)
    
    Assuming production targets for 2007 are achieved.
 
 Trends
    Trust
Taxation Canadian Federal Income
Tax Considerations Risk Factors  The October 31 Proposals, if enacted, are expected to
materially and adversely affect the Trust, the Unitholders and the value of the Trust Units
  -17-




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##### 



Industry
Conditions  Environmental Regulation
  
 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:
 
    
    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
 
    
    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.
 -18-




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##### 



For these purposes, Income means the aggregate of net production revenue of
the Corporation and any other income earned from permitted investments of the
Trust (excluding interest on cash or near-cash deposits or similar investments).
 
    
    a performance based fee based on total returns received by Unitholders which
essentially compensates the Manager for total annual returns which average in excess of
8 percent per annum over a 3-year period;
    
    a ceiling on total fees payable determined in reference to a percentage of the fees
paid under the previous management agreement: 80 percent each year in the first
three-year contract term and 60 percent each year in the second three-year contract
term and subject to a further ceiling essentially equivalent to $12 million annually
during the second three-year contract term;
    
    requirement for the Manager to pay certain expenses of the Corporation and the Trust
of approximately $2 million per year;
    
    an annual minimum management fee of $3.6 million comprised of $1.6 million of
management fees and $2.0 million of expenses;
    
    key man provisions in respect of James S. Kinnear, the President of the Manager;
    
    an annual bonus pool based on 10 percent of the Managers base fee and performance
fee for employees of, and special consultants to, the Corporation; and
    
    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
 -19-




---



##### 




    
    conducting general Unitholder services, including investor relations, maintaining
regulatory compliance, providing information to Unitholders in respect of material
changes in the business of the Corporation or the Trust and all other reports required
by law, and calling, holding and distributing material in respect of meetings of
Unitholders and Royalty Unitholders.
  
 Management Fee
  Bonus Pool
  
 Management Agreement Second Term
    
    
    The termination fee payable to the Manager on termination of the Management
Agreement;
 -20-




---



##### 




    
    The estimated cost of internal management, until June 30, 2009, in the event of a
termination of the Management Agreement;
    
    The estimated maximum management fees that would be payable to the Manager over the
final three years of the term of the Management Agreement;
    
    The advice of its financial advisor;
    
    The management fee ceiling applicable during the final three years of the Management
Agreement, which will result in lower management fees in the second term of the
Management Agreement ending June 30, 2009 as compared to the first term of the
Management Agreement ended June 30, 2006; and
    
    The commitment by the Manager to certain key governance standards relating to the
conduct of the affairs of the Trust and a continuing commitment to overall corporate
governance practices (as such practices would apply to Pengrowth in an internalized
management structure); and a further commitment to assist and work with the Board in
establishing a plan for the orderly transition to a traditional corporate management
structure at the end of the final term of the Management Agreement on June 30, 2009.
  
 PENGROWTH  OPERATIONAL INFORMATION
  
 Principle Properties
   Summary
of Pengrowth Company Interest
at December 31, 2006 (1)  Forecast Prices and Costs
 Company Interest
    
    
    
    
    
    2006 Actual OilRemaining
    
    
    
    
    
    Total Proved Plus
    
    Value at 10%
    
    EquivalentReserve Life
    
    Reserve Life Index
    
    Probable Reserves
    
    Discount
    
    ProductionField
    
    (Years)
    
    (Years)
    
    (mboe)
    
    ($M)
    
    (boepd)Judy Creek BHL Unit
    
    
    44
    
    
    
    11.4
    
    
    
    34,279
    
    
    
    558,895
    
    
    
    9,613Olds Gas Field Unit No. 1 (2)
    
    
    47
    
    
    
    18.3
    
    
    
    22,270
    
    
    
    217,850
    
    
    
    786Weyburn Unit
    
    
    36
    
    
    
    18.3
    
    
    
    21,954
    
    
    
    298,319
    
    
    
    2,894Swan Hills Unit No. 1
    
    
    50
    
    
    
    20.1
    
    
    
    18,655
    
    
    
    207,237
    
    
    
    2,884Carson Creek North BHL Unit No. 1
(2)
    
    
    37
    
    
    
    11.6
    
    
    
    15,598
    
    
    
    231,727
    
    
    
    1,227Sable Offshore Energy Project
    
    
    9
    
    
    
    4.1
    
    
    
    13,080
    
    
    
    292,062
    
    
    
    6,428
 -21-




---



##### 



Company Interest
    
    
    
    
    
    2006 Actual OilRemaining
    
    Reserve
    
    Total Proved Plus
    
    Value at 10%
    
    EquivalentReserve Life
    
    Life Index
    
    Probable Reserves
    
    Discount
    
    Production(Years)
    
    (Years)
    
    (mboe)
    
    ($M)
    
    (boepd)Judy Creek West BHL Unit
    
    
    50
    
    
    
    23.6
    
    
    
    9,298
    
    
    
    100,048
    
    
    
    1,146Monogram Gas Unit
    
    
    38
    
    
    
    10.9
    
    
    
    7,769
    
    
    
    127,039
    
    
    
    2,017Dunvegan Gas Unit No. 1
    
    
    34
    
    
    
    9.5
    
    
    
    6,354
    
    
    
    91,648
    
    
    
    1,802Olds Non-Unit (2)
    
    
    38
    
    
    
    8.6
    
    
    
    6,305
    
    
    
    103,547
    
    
    
    680Tangleflags North EOR
    
    
    26
    
    
    
    6.9
    
    
    
    5,727
    
    
    
    41,796
    
    
    
    1,632Quirk Creek
    
    
    33
    
    
    
    11.6
    
    
    
    5,492
    
    
    
    74,695
    
    
    
    883East Bodo
    
    
    46
    
    
    
    21.6
    
    
    
    5,193
    
    
    
    48,691
    
    
    
    701Twining
    
    
    50
    
    
    
    13.6
    
    
    
    4,864
    
    
    
    67,109
    
    
    
    1,745McLeod River
    
    
    42
    
    
    
    8.3
    
    
    
    4,240
    
    
    
    65,320
    
    
    
    1,365Twining CBM
    
    
    36
    
    
    
    9.8
    
    
    
    4,149
    
    
    
    53,916
    
    
    
    133Kaybob Notikewin Unit No. 1
    
    
    40
    
    
    
    13.5
    
    
    
    4,146
    
    
    
    49,557
    
    
    
    875Blackstone (2)
    
    
    26
    
    
    
    10.7
    
    
    
    3,956
    
    
    
    56,293
    
    
    
    267Oak
    
    
    42
    
    
    
    9.4
    
    
    
    3,631
    
    
    
    68,693
    
    
    
    1,082Princess
    
    
    50
    
    
    
    9.5
    
    
    
    3,572
    
    
    
    61,327
    
    
    
    1,050Tilley Milk River Unit
    
    
    49
    
    
    
    15.9
    
    
    
    3,151
    
    
    
    37,791
    
    
    
    600Enchant
    
    
    48
    
    
    
    14.6
    
    
    
    2,986
    
    
    
    39,229
    
    
    
    610Other (3)
    
    
    50
    
    
    
    8.0
    
    
    
    91,105
    
    
    
    1,540,583
    
    
    
    22,401Total
    
    
    50
    
    
    
    10.1
    
    
    
    297,774
    
    
    
    4,433,372
    
    
    
    62,821
 Notes:
 (1)
    
    The estimates of reserves and future net revenue for individual properties may not reflect
the same confidence level as estimates of reserves and future net revenue for all properties,
due to the effects of aggregation.(2)
    
    Acquired late in 2006. Production based on three months averaged over the year.(3)
    
    Other includes Pengrowths working and royalty interests in approximately 170 other
properties.(4)
    
    Natural Gas has been converted to barrels of oil equivalent on the basis of six mcf of
natural gas being equal to one boe.
 Judy Creek Beaverhill Lake Unit and Judy Creek West Beaverhill Lake Unit
  Development Activity
   -22-




---



##### 



CO2 Pilot
 2 2 2
 Olds Gas Unit No. 1
   Development Activity
  Olds Non-Unit
  Development Activity
   -23-




---



##### 



Weyburn Unit
 2
 Development Activity
 2 2
 2 2
 Swan Hills Unit No. 1
  Development Activity
   2
  -24-




---



##### 



Carson Creek
   Development Activity
   Sable Offshore Energy Project
   Development Activity
    -25-




---



##### 



Monogram Gas Unit
  Development Activity
  Dunvegan Gas Unit No. 1
  Development Activity
  Tangleflags
   -26-




---



##### 



Development Activity
  Quirk Creek
   Development Activity
  East Bodo
  Development Activity
  -27-




---



##### 



Twining
   Development Activity
   McLeod River
   Development Activity
  Twining CBM
  Development Activity
  -28-




---



##### 



Kaybob Notikewin Unit No. 1
  Development Activity
  
 Statement of Oil and Gas Reserves and Reserves Data
 Disclosure of Reserves Data
    -29-




---



##### 



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.
  
    
    the GLJ Report does not estimate general and administrative expenses, interest,
management fees and holdbacks;
    
    the GLJ Report does not estimate all abandonment or any reclamation liabilities;
    
    for purposes of calculating distributable cash, 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 ($34.6 million in 2006) in operating costs
in the year incurred; and
    
    Pengrowth withholds certain amounts from distributable cash to fund capital.
  -30-




---



##### 



Reserves Data (Constant Prices and Costs)  Pengrowth without CP Properties
 Summary
of Oil And Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Constant Prices and Costs
 Light 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
    
    
    67,347
    
    
    
    37,136
    
    
    
    58,001
    
    
    
    11,368
    
    
    
    11,360
    
    
    
    9,975
    
    
    
    537.7
    
    
    
    534.4
    
    
    
    425.2Proved Developed Non-Producing
    
    
    436
    
    
    
    436
    
    
    
    348
    
    
    
    992
    
    
    
    992
    
    
    
    837
    
    
    
    36.7
    
    
    
    36.5
    
    
    
    27.9Proved Undeveloped
    
    
    18,040
    
    
    
    18,028
    
    
    
    15,302
    
    
    
    1,908
    
    
    
    1,908
    
    
    
    1,649
    
    
    
    48.8
    
    
    
    48.7
    
    
    
    38.8Total Proved Reserves
    
    
    85,823
    
    
    
    85,599
    
    
    
    73,651
    
    
    
    14,268
    
    
    
    14,260
    
    
    
    12,461
    
    
    
    623.2
    
    
    
    619.6
    
    
    
    491.9Probable Reserves
    
    
    26,877
    
    
    
    26,826
    
    
    
    22,788
    
    
    
    4,088
    
    
    
    4,086
    
    
    
    3,466
    
    
    
    200.0
    
    
    
    199.0
    
    
    
    155.9Total Proved Plus Probable Reserves
    
    
    112,700
    
    
    
    112,425
    
    
    
    96,440
    
    
    
    18,356
    
    
    
    18,346
    
    
    
    15,927
    
    
    
    823.2
    
    
    
    818.7
    
    
    
    647.8
 Natural 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
    
    
    20,339
    
    
    
    20,290
    
    
    
    14,531
    
    
    
    188,672
    
    
    
    187,857
    
    
    
    153,381Proved Developed Non-Producing
    
    
    631
    
    
    
    630
    
    
    
    451
    
    
    
    8,175
    
    
    
    8,138
    
    
    
    6,285Proved Undeveloped
    
    
    1,463
    
    
    
    1,463
    
    
    
    1,089
    
    
    
    29,538
    
    
    
    29,519
    
    
    
    24,507Total Proved Reserves
    
    
    22,433
    
    
    
    22,383
    
    
    
    16,071
    
    
    
    226,385
    
    
    
    225,514
    
    
    
    184,173Probable Reserves
    
    
    6,606
    
    
    
    6,595
    
    
    
    4,795
    
    
    
    70,903
    
    
    
    70,681
    
    
    
    57,033Total Proved Plus Probable Reserves
    
    
    29,039
    
    
    
    28,978
    
    
    
    20,866
    
    
    
    297,288
    
    
    
    296,195
    
    
    
    241,206
 Net Present Values of Future Net RevenueConstant Prices and Costs Before Income TaxesDiscounted at (%/year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed
Producing
    
    
    4,417.1
    
    
    
    3,363.3
    
    
    
    2,746.3
    
    
    
    2,341.5
    
    
    
    2,054.5Proved Developed
Non-Producing
    
    
    152.9
    
    
    
    119.3
    
    
    
    97.3
    
    
    
    81.8
    
    
    
    70.5Proved Undeveloped
    
    
    746.2
    
    
    
    474.2
    
    
    
    321.9
    
    
    
    227.3
    
    
    
    164.1Total Proved Reserves
    
    
    5,316.2
    
    
    
    3,956.8
    
    
    
    3,165.5
    
    
    
    2,650.6
    
    
    
    2,289.1Probable Reserves
    
    
    1,872.0
    
    
    
    1,070.6
    
    
    
    709.6
    
    
    
    513.8
    
    
    
    393.8Total Proved Plus
Probable Reserves
    
    
    7,188.2
    
    
    
    5,027.4
    
    
    
    3,875.1
    
    
    
    3,164.4
    
    
    
    2,682.9
 -31-




---



##### 



Reserves Data (Constant Prices and Costs)  CP Properties
 Summary of Oil And Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Constant Prices and Costs
 Light 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
    
    
    12,954
    
    
    
    12,931
    
    
    
    11,658
    
    
    
    5,804
    
    
    
    5,801
    
    
    
    5,446
    
    
    
    137.6
    
    
    
    136.3
    
    
    
    117.9Proved Developed
Non-Producing
    
    
    254
    
    
    
    254
    
    
    
    216
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    2.2
    
    
    
    2.2
    
    
    
    1.7Proved Undeveloped
    
    
    1,449
    
    
    
    1,449
    
    
    
    1,096
    
    
    
    341
    
    
    
    341
    
    
    
    297
    
    
    
    22.2
    
    
    
    21.9
    
    
    
    20.0Total Proved Reserves
    
    
    14,657
    
    
    
    14,634
    
    
    
    12,970
    
    
    
    6,145
    
    
    
    6,142
    
    
    
    5,743
    
    
    
    162.0
    
    
    
    160.4
    
    
    
    139.6Probable Reserves
    
    
    4,946
    
    
    
    4,940
    
    
    
    4,320
    
    
    
    1,508
    
    
    
    1,507
    
    
    
    1,360
    
    
    
    39.6
    
    
    
    39.0
    
    
    
    34.2Total Proved Plus
Probable Reserves
    
    
    19,603
    
    
    
    19,574
    
    
    
    17,291
    
    
    
    7,653
    
    
    
    7,649
    
    
    
    7,103
    
    
    
    201.6
    
    
    
    199.4
    
    
    
    173.8
 Natural Gas Liquids
    
    Total Oil Equivalent BasisPengrowth Company
    
    Pengrowth Gross
    
    Pengrowth Net
    
    Pengrowth Company
    
    Pengrowth Gross
    
    Pengrowth NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)Proved ReservesProved Developed
Producing
    
    
    2,922
    
    
    
    2,914
    
    
    
    2,060
    
    
    
    44,619
    
    
    
    44,357
    
    
    
    38,810Proved Developed
Non-Producing
    
    
    53
    
    
    
    53
    
    
    
    33
    
    
    
    678
    
    
    
    670
    
    
    
    526Proved Undeveloped
    
    
    130
    
    
    
    130
    
    
    
    87
    
    
    
    5,616
    
    
    
    5,576
    
    
    
    4,822Total Proved Reserves
    
    
    3,105
    
    
    
    3,097
    
    
    
    2,179
    
    
    
    50,913
    
    
    
    50,603
    
    
    
    44,158Probable Reserves
    
    
    727
    
    
    
    725
    
    
    
    506
    
    
    
    13,773
    
    
    
    13,673
    
    
    
    11,887Total Proved Plus
Probable Reserves
    
    
    3,831
    
    
    
    3,822
    
    
    
    2,685
    
    
    
    64,685
    
    
    
    64,276
    
    
    
    56,045
 Net Present Values of Future Net RevenueConstant Prices and Costs Before Income TaxesDiscounted at (%/year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
Proved Developed
Producing
    
    
    868.0
    
    
    
    718.2
    
    
    
    614.6
    
    
    
    538.8
    
    
    
    481.1Proved Developed
Non-Producing
    
    
    16.2
    
    
    
    11.1
    
    
    
    8.3
    
    
    
    6.5
    
    
    
    5.3Proved Undeveloped
    
    
    74.0
    
    
    
    43.0
    
    
    
    25.5
    
    
    
    14.6
    
    
    
    7.4Total Proved Reserves
    
    
    958.2
    
    
    
    772.4
    
    
    
    648.3
    
    
    
    559.9
    
    
    
    493.9Probable Reserves
    
    
    311.6
    
    
    
    198.0
    
    
    
    137.7
    
    
    
    101.8
    
    
    
    78.6Total Proved Plus
Probable Reserves
    
    
    1,269.8
    
    
    
    970.4
    
    
    
    786.0
    
    
    
    661.7
    
    
    
    572.5
 -32-




---



##### 



Reserves Data (Constant Prices and Costs)  Proforma Pengrowth and CP Properties
 Summary of Oil and Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Constant Prices and Costs
 Light 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
    
    
    80,301
    
    
    
    80,066
    
    
    
    69,660
    
    
    
    17,172
    
    
    
    17,160
    
    
    
    15,420
    
    
    
    675.3
    
    
    
    670.7
    
    
    
    543.1Proved Developed
Non-Producing
    
    
    689
    
    
    
    689
    
    
    
    565
    
    
    
    992
    
    
    
    992
    
    
    
    837
    
    
    
    38.9
    
    
    
    38.7
    
    
    
    29.6Proved Undeveloped
    
    
    19,489
    
    
    
    19,477
    
    
    
    16,397
    
    
    
    2,249
    
    
    
    2,249
    
    
    
    1,946
    
    
    
    70.9
    
    
    
    70.7
    
    
    
    58.9Total Proved Reserves
    
    
    100,480
    
    
    
    100,233
    
    
    
    86,622
    
    
    
    20,413
    
    
    
    20,402
    
    
    
    18,204
    
    
    
    785.2
    
    
    
    780.0
    
    
    
    631.5Probable Reserves
    
    
    31,823
    
    
    
    31,766
    
    
    
    27,108
    
    
    
    5,596
    
    
    
    5,593
    
    
    
    4,826
    
    
    
    239.5
    
    
    
    238.0
    
    
    
    190.1Total Proved Plus
Probable Reserves
    
    
    132,303
    
    
    
    131,999
    
    
    
    113,730
    
    
    
    26,009
    
    
    
    25,995
    
    
    
    23,030
    
    
    
    1024.7
    
    
    
    1018.1
    
    
    
    821.6
 Natural Gas Liquids
    
    Total Oil Equivalent BasisPengrowth
    
    
    
    
    
    
    
    
    
    PengrowthPengrowth Company
    
    Pengrowth Gross
    
    Net
    
    Pengrowth Company
    
    Pengrowth Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)Proved ReservesProved Developed
Producing
    
    
    23,260
    
    
    
    23,204
    
    
    
    16,591
    
    
    
    233,291
    
    
    
    232,214
    
    
    
    192,191Proved Developed
Non-Producing
    
    
    684
    
    
    
    683
    
    
    
    484
    
    
    
    8,853
    
    
    
    8,808
    
    
    
    6,811Proved Undeveloped
    
    
    1,593
    
    
    
    1,593
    
    
    
    1,176
    
    
    
    35,154
    
    
    
    35,095
    
    
    
    29,329Total Proved Reserves
    
    
    25,538
    
    
    
    25,480
    
    
    
    18,250
    
    
    
    277,298
    
    
    
    276,177
    
    
    
    228,331Probable Reserves
    
    
    7,333
    
    
    
    7,320
    
    
    
    5,301
    
    
    
    84,675
    
    
    
    84,353
    
    
    
    68,920Total Proved Plus
Probable Reserves
    
    
    32,871
    
    
    
    32,800
    
    
    
    23,551
    
    
    
    361,973
    
    
    
    360,471
    
    
    
    297,251
 Net Present Values of Future Net RevenueConstant Prices and Costs Before Income TaxesDiscounted at (%/year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed
Producing
    
    
    5,285.1
    
    
    
    4,081.5
    
    
    
    3,360.9
    
    
    
    2,880.3
    
    
    
    2,535.6Proved Developed
Non-Producing
    
    
    169.1
    
    
    
    130.4
    
    
    
    105.6
    
    
    
    88.4
    
    
    
    75.8Proved Undeveloped
    
    
    820.2
    
    
    
    517.2
    
    
    
    347.4
    
    
    
    241.9
    
    
    
    171.6Total Proved Reserves
    
    
    6,274.4
    
    
    
    4,729.2
    
    
    
    3,813.8
    
    
    
    3,210.5
    
    
    
    2,783.0Probable Reserves
    
    
    2,183.6
    
    
    
    1,268.7
    
    
    
    847.3
    
    
    
    615.6
    
    
    
    472.4Total Proved Plus
Probable Reserves
    
    
    8,458.0
    
    
    
    5,997.9
    
    
    
    4,661.1
    
    
    
    3,826.1
    
    
    
    3,255.4
 -33-




---



##### 



Pengrowth without CP Properties
Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2006
Constant Prices and Costs
 Capital
    
    
    
    
    
    FutureDevelopment
    
    Abandonment
    
    Net RevenueRevenue
    
    Royalties
    
    Operating Costs
    
    Costs
    
    Costs(1)
    
    Before Income TaxReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    11,334
    
    
    
    1,991
    
    
    
    3,485
    
    
    
    415
    
    
    
    127
    
    
    
    5,316Total Proved Plus Probable Reserves
    
    
    14,879
    
    
    
    2,664
    
    
    
    4,283
    
    
    
    611
    
    
    
    133
    
    
    
    7,188
 
 Notes:
 (1)
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See
Abandonment & Reclamation Costs. Pengrowth without CP Properties
Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2006
Constant Prices and Costs
 Future NetRevenue BeforeIncome Taxes(discountedReserves Category
    
    Production Group
    
    at 10% yr) ($M)Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products) (1)
    
    
    1,721,961Heavy Oil (including solution gas and other by-products)(1)
    
    
    162,713Natural Gas (including by-products but excluding solution gas from oil wells)
(2)
    
    
    1,280,832Total Proved Plus Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products)(1)
    
    
    2,074,957Heavy Oil (including solution gas and other by-products) (1)
    
    
    201,572Natural Gas (including by-products but excluding solution gas from oil wells)
(2)
    
    
    1,598,559
 
 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. -34-




---



##### 



Reserves Data (Forecast Prices and Costs)  Pengrowth without CP Properties
 Summary of Oil and Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Forecast Prices and Costs
 Light 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
    
    
    67,070
    
    
    
    66,861
    
    
    
    57,753
    
    
    
    11,364
    
    
    
    11,356
    
    
    
    9,973
    
    
    
    540.9
    
    
    
    537.6
    
    
    
    427.8Proved Developed Non-Producing
    
    
    436
    
    
    
    436
    
    
    
    348
    
    
    
    990
    
    
    
    990
    
    
    
    836
    
    
    
    36.8
    
    
    
    36.6
    
    
    
    27.9Proved Undeveloped
    
    
    17,363
    
    
    
    17,352
    
    
    
    14,781
    
    
    
    1,891
    
    
    
    1,891
    
    
    
    1,634
    
    
    
    48.2
    
    
    
    48.2
    
    
    
    38.4Total Proved Reserves
    
    
    84,869
    
    
    
    84,649
    
    
    
    72,882
    
    
    
    14,245
    
    
    
    14,237
    
    
    
    12,443
    
    
    
    625.9
    
    
    
    622.4
    
    
    
    494.1Probable Reserves
    
    
    27,518
    
    
    
    27,468
    
    
    
    23,451
    
    
    
    4,091
    
    
    
    4,089
    
    
    
    3,469
    
    
    
    201.6
    
    
    
    200.6
    
    
    
    157.2Total Proved Plus
Probable Reserves
    
    
    112,387
    
    
    
    112,117
    
    
    
    96,333
    
    
    
    18,336
    
    
    
    18,326
    
    
    
    15,912
    
    
    
    827.5
    
    
    
    823.0
    
    
    
    651.4
 Natural Gas Liquids
    
    Total Oil Equivalent BasisPengrowth
    
    Pengrowth
    
    Pengrowth
    
    Pengrowth
    
    
    
    
    
    PengrowthCompany
    
    Gross
    
    Net
    
    Company
    
    Pengrowth Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)Proved ReservesProved Developed Producing
    
    
    20,380
    
    
    
    20,332
    
    
    
    14,569
    
    
    
    188,961
    
    
    
    188,146
    
    
    
    153,592Proved Developed Non-Producing
    
    
    631
    
    
    
    630
    
    
    
    452
    
    
    
    8,187
    
    
    
    8,154
    
    
    
    6,291Proved Undeveloped
    
    
    1,439
    
    
    
    1,439
    
    
    
    1,075
    
    
    
    28,726
    
    
    
    28,707
    
    
    
    23,895Total Proved Reserves
    
    
    22,450
    
    
    
    22,400
    
    
    
    16,096
    
    
    
    225,875
    
    
    
    225,007
    
    
    
    183,777Probable Reserves
    
    
    6,693
    
    
    
    6,682
    
    
    
    4,862
    
    
    
    71,899
    
    
    
    71,677
    
    
    
    57,986Total Proved Plus
Probable Reserves
    
    
    29,143
    
    
    
    29,082
    
    
    
    20,958
    
    
    
    297,774
    
    
    
    296,684
    
    
    
    241,763
 Net Present Values of Future Net RevenueForecast Prices and Costs Before Income TaxesDiscounted at (%/year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    5,165.4
    
    
    
    3,858.4
    
    
    
    3,121.7
    
    
    
    2,649.8
    
    
    
    2,320.3Proved Developed Non-Producing
    
    
    203.3
    
    
    
    155.5
    
    
    
    125.3
    
    
    
    104.7
    
    
    
    89.8Proved Undeveloped
    
    
    794.5
    
    
    
    499.2
    
    
    
    336.2
    
    
    
    236.2
    
    
    
    170.3Total Proved Reserves
    
    
    6,163.1
    
    
    
    4,513.1
    
    
    
    3,583.2
    
    
    
    2,990.8
    
    
    
    2,580.5Probable Reserves
    
    
    2,418.8
    
    
    
    1,317.0
    
    
    
    850.2
    
    
    
    607.6
    
    
    
    462.8Total Proved Plus
Probable Reserves
    
    
    8,581.9
    
    
    
    5,830.1
    
    
    
    4,433.4
    
    
    
    3,598.4
    
    
    
    3,043.3
 -35-




---



##### 



Reserves Data (Forecast Prices and Costs)  CP Properties
 Summary of Oil and Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Forecast Prices and Costs
 Light 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
    
    
    12,577
    
    
    
    12,555
    
    
    
    11,302
    
    
    
    5,673
    
    
    
    5,669
    
    
    
    5,318
    
    
    
    142.2
    
    
    
    140.8
    
    
    
    121.9Proved Developed Non-Producing
    
    
    261
    
    
    
    261
    
    
    
    223
    
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    2.3
    
    
    
    2.2
    
    
    
    1.7Proved Undeveloped
    
    
    1,455
    
    
    
    1,455
    
    
    
    1,101
    
    
    
    341
    
    
    
    341
    
    
    
    297
    
    
    
    22.0
    
    
    
    21.8
    
    
    
    19.9Total Proved Reserves
    
    
    14,293
    
    
    
    14,271
    
    
    
    12,626
    
    
    
    6,014
    
    
    
    6,011
    
    
    
    5,616
    
    
    
    166.5
    
    
    
    164.8
    
    
    
    143.5Probable Reserves
    
    
    4,838
    
    
    
    4,832
    
    
    
    4,217
    
    
    
    1,542
    
    
    
    1,542
    
    
    
    1,394
    
    
    
    41.2
    
    
    
    40.6
    
    
    
    35.6Total Proved Plus
Probable Reserves
    
    
    19,131
    
    
    
    19,103
    
    
    
    16,843
    
    
    
    7,556
    
    
    
    7,553
    
    
    
    7,010
    
    
    
    207.7
    
    
    
    205.4
    
    
    
    179.2
 Natural Gas Liquids
    
    Total Oil Equivalent BasisPengrowth
    
    
    
    
    
    Pengrowth
    
    
    
    
    
    
    
    
    
    PengrowthCompany
    
    Pengrowth Gross
    
    Net
    
    Pengrowth Company
    
    Pengrowth Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)Proved ReservesProved Developed Producing
    
    
    2,934
    
    
    
    2,926
    
    
    
    2,070
    
    
    
    44,878
    
    
    
    44,609
    
    
    
    39,009Proved Developed Non-Producing
    
    
    55
    
    
    
    55
    
    
    
    34
    
    
    
    693
    
    
    
    685
    
    
    
    539Proved Undeveloped
    
    
    131
    
    
    
    131
    
    
    
    87
    
    
    
    5,600
    
    
    
    5,561
    
    
    
    4,808Total Proved Reserves
    
    
    3,119
    
    
    
    3,111
    
    
    
    2,191
    
    
    
    51,171
    
    
    
    50,855
    
    
    
    44,356Probable Reserves
    
    
    729
    
    
    
    727
    
    
    
    507
    
    
    
    13,971
    
    
    
    13,869
    
    
    
    12,059Total Proved Plus
Probable Reserves
    
    
    3,848
    
    
    
    3,839
    
    
    
    2,698
    
    
    
    65,142
    
    
    
    64,724
    
    
    
    56,415
 Net Present Values of Future Net RevenueForecast Prices and Costs Before Income TaxesDiscounted at (%/year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    1,011.2
    
    
    
    830.6
    
    
    
    706.7
    
    
    
    617.1
    
    
    
    549.5Proved Developed Non-Producing
    
    
    19.5
    
    
    
    13.5
    
    
    
    10.1
    
    
    
    8.1
    
    
    
    6.6Proved Undeveloped
    
    
    112.3
    
    
    
    68.6
    
    
    
    43.9
    
    
    
    28.6
    
    
    
    18.6Total Proved Reserves
    
    
    1,143.1
    
    
    
    912.7
    
    
    
    760.8
    
    
    
    653.8
    
    
    
    574.7Probable Reserves
    
    
    393.6
    
    
    
    239.8
    
    
    
    161.7
    
    
    
    117.1
    
    
    
    89.2Total Proved Plus Probable Reserves
    
    
    1,536.7
    
    
    
    1,152.5
    
    
    
    922.5
    
    
    
    770.9
    
    
    
    664.0
 -36-




---



##### 



Reserves Data (Forecast Prices and Costs)  Proforma Pengrowth and CP Properties
 Summary of Oil and Gas Reserves
Net Present Value of Future Net Revenue
as of December 31, 2006
Forecast Prices and Costs
 Light 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
    
    
    79,647
    
    
    
    79,416
    
    
    
    69,055
    
    
    
    17,037
    
    
    
    17,025
    
    
    
    15,292
    
    
    
    683.0
    
    
    
    678.3
    
    
    
    549.7Proved Developed Non-Producing
    
    
    66
    
    
    
    696
    
    
    
    571
    
    
    
    990
    
    
    
    990
    
    
    
    836
    
    
    
    39.1
    
    
    
    38.8
    
    
    
    29.6Proved Undeveloped
    
    
    18,819
    
    
    
    18,807
    
    
    
    15,882
    
    
    
    2,232
    
    
    
    2,232
    
    
    
    1,931
    
    
    
    70.2
    
    
    
    70.0
    
    
    
    58.4Total Proved Reserves
    
    
    99,162
    
    
    
    98,919
    
    
    
    85,508
    
    
    
    20,258
    
    
    
    20,247
    
    
    
    18,059
    
    
    
    792.3
    
    
    
    787.1
    
    
    
    637.7Probable Reserves
    
    
    32,356
    
    
    
    32,300
    
    
    
    27,667
    
    
    
    5,634
    
    
    
    5,631
    
    
    
    4,863
    
    
    
    242.8
    
    
    
    241.2
    
    
    
    192.9Total Proved Plus
Probable Reserves
    
    
    131,518
    
    
    
    131,218
    
    
    
    113,175
    
    
    
    25,892
    
    
    
    25,878
    
    
    
    22,921
    
    
    
    1,035.1
    
    
    
    1,028.3
    
    
    
    830.5
 Natural Gas Liquids
    
    Total Oil Equivalent BasisPengrowth
    
    
    
    
    
    
    
    
    
    PengrowthPengrowth Company
    
    Pengrowth Gross
    
    Net
    
    Pengrowth Company
    
    Pengrowth Gross
    
    NetInterest
    
    Interest
    
    Interest
    
    Interest
    
    Interest
    
    InterestReserves Category
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)
    
    (mboe)
    
    (mboe)
    
    (mboe)Proved ReservesProved Developed Producing
    
    
    23,314
    
    
    
    23,258
    
    
    
    16,640
    
    
    
    233,839
    
    
    
    232,756
    
    
    
    192,601Proved Developed Non-Producing
    
    
    685
    
    
    
    684
    
    
    
    485
    
    
    
    8,881
    
    
    
    8,838
    
    
    
    6,830Proved Undeveloped
    
    
    1,569
    
    
    
    1,569
    
    
    
    1,162
    
    
    
    34,326
    
    
    
    34,268
    
    
    
    28,703Total Proved Reserves
    
    
    25,569
    
    
    
    25,511
    
    
    
    18,287
    
    
    
    277,046
    
    
    
    275,862
    
    
    
    228,133Probable Reserves
    
    
    7,422
    
    
    
    7,409
    
    
    
    5,370
    
    
    
    85,870
    
    
    
    85,546
    
    
    
    70,045Total Proved Plus
Probable Reserves
    
    
    32,991
    
    
    
    32,920
    
    
    
    23,657
    
    
    
    362,915
    
    
    
    361,408
    
    
    
    298,177
 Net Present Values of Future Net RevenueForecast Prices and Costs Before Income TaxesDiscounted at (%/year)0%
    
    5%
    
    10%
    
    15%
    
    20%Reserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved ReservesProved Developed Producing
    
    
    6,177
    
    
    
    4,689
    
    
    
    3,828
    
    
    
    3,267
    
    
    
    2,870Proved Developed Non-Producing
    
    
    223
    
    
    
    169
    
    
    
    135
    
    
    
    113
    
    
    
    96Proved Undeveloped
    
    
    907
    
    
    
    568
    
    
    
    380
    
    
    
    265
    
    
    
    189Total Proved Reserves
    
    
    7,306
    
    
    
    5,426
    
    
    
    4,344
    
    
    
    3,645
    
    
    
    3,155Probable Reserves
    
    
    2,812
    
    
    
    1,557
    
    
    
    1,012
    
    
    
    725
    
    
    
    552Total Proved Plus
Probable Reserves
    
    
    10,119
    
    
    
    6,983
    
    
    
    5,356
    
    
    
    4,369
    
    
    
    3,707
 -37-




---



##### 



Pengrowth without CP Properties  Additional Information Concerning Future Net Revenue
(undiscounted)
as of December 31, 2006
Forecast Prices and Costs
 Capital
    
    
    
    
    
    Future NetOperating
    
    Development
    
    Abandonment
    
    Revenue BeforeRevenue
    
    Royalties
    
    Costs
    
    Costs
    
    Costs(1)
    
    Income TaxesReserves Category
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Proved Reserves
    
    
    13,257
    
    
    
    2,337
    
    
    
    4,144
    
    
    
    443
    
    
    
    170
    
    
    
    6,163Total Proved Plus Probable Reserves
    
    
    18,049
    
    
    
    3,212
    
    
    
    5,410
    
    
    
    654
    
    
    
    191
    
    
    
    8,582
 
 Notes:(1)
    
    Includes downhole abandonment cost but does not include surface reclamation costs. See
Abandonment & Reclamation Costs. Pengrowth without CP Properties
Net Present Value of Future Net Revenue
By Production Group
as of December 31, 2006
Forecast Prices and Costs
 Future NetRevenue BeforeIncome Taxes(discountedReserves Category
    
    Production Group
    
    at 10% yr) ($M)Proved Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products) (1)
    
    
    1,686,163Heavy Oil (including solution gas and other by-products) (1)
    
    
    180,039Natural Gas (including by-products but excluding solution gas from oil wells) (2)
    
    
    1,717,001Total Proved Plus Probable Reserves
    
    Light and Medium Crude Oil (including solution gas and other by-products) (1)
    
    
    2,046,436Heavy Oil (including solution gas and other by-products) (1)
    
    
    225,703Natural Gas (including by-products but excluding solution gas from oil wells) (2)
    
    
    2,161,233
 
 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. -38-




---



##### 



Pricing Assumptions
 Constant Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)Edmonton
    
    Cromer
    
    LLB CrudeWTI Cushing
    
    Par Price
    
    Medium
    
    Oil at
    
    AECO Gas
    
    
    
    
    
    
    
    
    
    Pentanes
    
    ExchangeOklahoma
    
    400API
    
    29.30API
    
    Hardisty
    
    Price
    
    Propane
    
    Butane
    
    Plus
    
    Rate(2)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/mmbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($US/Cdn)Historical at
December 31, 2006
    
    
    60.85
    
    
    
    67.58
    
    
    
    59.47
    
    
    
    47.62
    
    
    
    6.07
    
    
    
    43.25
    
    
    
    54.06
    
    
    
    71.55
    
    
    
    0.8581
 
 Notes:(1)
    
    FOB Edmonton.(2)
    
    The exchange rate used to generate the benchmark reference prices in this table. Forecast Prices used in Estimates
  Oil
    
    Natural Gas
    
    Natural Gas Liquids(1)CromerWTI
    
    Edmonton
    
    Medium
    
    HardistyCushing
    
    Par Price
    
    29.30
    
    Heavy
    
    AECO
    
    
    
    
    
    Pentanes
    
    Inflation
    
    ExchangeOklahoma
    
    400API
    
    API
    
    120API
    
    Gas Price
    
    Propane
    
    Butane
    
    Plus
    
    Rates(2)
    
    Rate(3)Year
    
    ($US/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/mmbtu)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    ($Cdn/bbl)
    
    (%/Year)
    
    ($US/Cdn)2006(4)
    
    
    66.22
    
    
    
    73.16
    
    
    
    62.24
    
    
    
    41.87
    
    
    
    7.02
    
    
    
    43.97
    
    
    
    66.64
    
    
    
    75.69
    
    
    
    2.10
    %
    
    
    0.8822007
    
    
    62.00
    
    
    
    70.25
    
    
    
    61.25
    
    
    
    39.25
    
    
    
    7.20
    
    
    
    45.00
    
    
    
    56.25
    
    
    
    71.75
    
    
    
    2.00
    %
    
    
    0.8702008
    
    
    60.00
    
    
    
    68.00
    
    
    
    59.25
    
    
    
    40.00
    
    
    
    7.45
    
    
    
    43.50
    
    
    
    50.25
    
    
    
    69.25
    
    
    
    2.00
    %
    
    
    0.8702009
    
    
    58.00
    
    
    
    65.75
    
    
    
    57.25
    
    
    
    39.75
    
    
    
    7.75
    
    
    
    42.00
    
    
    
    48.75
    
    
    
    67.00
    
    
    
    2.00
    %
    
    
    0.8702010
    
    
    57.00
    
    
    
    64.50
    
    
    
    56.00
    
    
    
    39.75
    
    
    
    7.80
    
    
    
    41.25
    
    
    
    47.75
    
    
    
    65.75
    
    
    
    2.00
    %
    
    
    0.8702011
    
    
    57.00
    
    
    
    64.50
    
    
    
    56.00
    
    
    
    40.25
    
    
    
    7.85
    
    
    
    41.25
    
    
    
    47.75
    
    
    
    65.75
    
    
    
    2.00
    %
    
    
    0.8702012
    
    
    57.50
    
    
    
    65.00
    
    
    
    56.50
    
    
    
    41.50
    
    
    
    8.15
    
    
    
    41.50
    
    
    
    48.00
    
    
    
    66.25
    
    
    
    2.00
    %
    
    
    0.8702013
    
    
    58.50
    
    
    
    66.25
    
    
    
    57.75
    
    
    
    42.50
    
    
    
    8.30
    
    
    
    42.50
    
    
    
    49.00
    
    
    
    67.50
    
    
    
    2.00
    %
    
    
    0.8702014
    
    
    59.75
    
    
    
    67.75
    
    
    
    59.00
    
    
    
    43.50
    
    
    
    8.50
    
    
    
    43.25
    
    
    
    50.25
    
    
    
    69.00
    
    
    
    2.00
    %
    
    
    0.8702015
    
    
    61.00
    
    
    
    69.00
    
    
    
    60.00
    
    
    
    44.25
    
    
    
    8.70
    
    
    
    44.25
    
    
    
    51.00
    
    
    
    70.50
    
    
    
    2.00
    %
    
    
    0.8702016
    
    
    62.25
    
    
    
    70.50
    
    
    
    61.25
    
    
    
    45.25
    
    
    
    8.90
    
    
    
    45.00
    
    
    
    52.25
    
    
    
    72.00
    
    
    
    2.00
    %
    
    
    0.8702017
    
    
    63.50
    
    
    
    71.75
    
    
    
    62.50
    
    
    
    46.00
    
    
    
    9.10
    
    
    
    46.00
    
    
    
    53.00
    
    
    
    73.25
    
    
    
    2.00
    %
    
    
    0.870Thereafter
    
    +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
    %
    
    
    0.870
 
 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 2006. -39-




---



##### 



Reconciliation of Changes in Reserves and Future Net Revenue  Pengrowth
 Reserves Reconciliation
  Reserves Reconciliation
By Principle 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)
    
    (mmcf)
    
    (mmcf)
    
    (mmcf)
    
    (mbbls)
    
    (mbbls)
    
    (mbbls)December 31, 2005
    
    
    65,993
    
    
    
    17,937
    
    
    
    83,929
    
    
    
    331,675
    
    
    
    72,635
    
    
    
    404,310
    
    
    
    10,600
    
    
    
    2,618
    
    
    
    13,218Extensions
    
    
    123
    
    
    
    85
    
    
    
    208
    
    
    
    18,831
    
    
    
    11,197
    
    
    
    30,027
    
    
    
    143
    
    
    
    89
    
    
    
    232Improved Recovery
    
    
    1,937
    
    
    
    2,388
    
    
    
    4,325
    
    
    
    8,801
    
    
    
    8,884
    
    
    
    17,683
    
    
    
    63
    
    
    
    182
    
    
    
    243Technical Revisions
    
    
    505
    
    
    
    186
    
    
    
    691
    
    
    
    4,833
    
    
    
    (1,280
    )
    
    
    3,553
    
    
    
    553
    
    
    
    (257
    )
    
    
    295Discoveries
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,044
    
    
    
    3,857
    
    
    
    8,901
    
    
    
    195
    
    
    
    157
    
    
    
    352Acquisitions
    
    
    10,865
    
    
    
    2,999
    
    
    
    13,864
    
    
    
    184,678
    
    
    
    64,090
    
    
    
    248,767
    
    
    
    6,789
    
    
    
    2,129
    
    
    
    8,918Dispositions
    
    
    (222
    )
    
    
    (144
    )
    
    
    (366
    )
    
    
    (7,959
    )
    
    
    (2,156
    )
    
    
    (10,115
    )
    
    
    (180
    )
    
    
    (54
    )
    
    
    (234
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (6,318
    )
    
    
    
    
    
    
    (6,318
    )
    
    
    (51,765
    )
    
    
    
    
    
    
    (51,765
    )
    
    
    (2,067
    )
    
    
    
    
    
    
    (2,067
    )December 31, 2006
    
    
    72,882
    
    
    
    23,451
    
    
    
    96,333
    
    
    
    494,136
    
    
    
    157,226
    
    
    
    651,362
    
    
    
    16,096
    
    
    
    4,863
    
    
    
    20,958
 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, 2005
    
    
    11,098
    
    
    
    2,616
    
    
    
    13,714
    
    
    
    142,970
    
    
    
    35,276
    
    
    
    178,246Extensions
    
    
    368
    
    
    
    160
    
    
    
    528
    
    
    
    3,772
    
    
    
    2,201
    
    
    
    5,973Improved Recovery
    
    
    1,196
    
    
    
    527
    
    
    
    1,723
    
    
    
    4,661
    
    
    
    4,577
    
    
    
    9,238Technical Revisions
    
    
    956
    
    
    
    (45
    )
    
    
    911
    
    
    
    2,819
    
    
    
    (329
    )
    
    
    2,490Discoveries
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,036
    
    
    
    800
    
    
    
    1,836Acquisitions
    
    
    528
    
    
    
    209
    
    
    
    737
    
    
    
    48,962
    
    
    
    16,018
    
    
    
    64,980Dispositions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,728
    )
    
    
    (557
    )
    
    
    (2,285
    )Economic Factors
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (1,703
    )
    
    
    
    
    
    
    (1,703
    )
    
    
    (18,715
    )
    
    
    
    
    
    
    (18,715
    )December 31, 2006
    
    
    12,443
    
    
    
    3,468
    
    
    
    15,911
    
    
    
    183,777
    
    
    
    57,986
    
    
    
    241,763
 -40-




---



##### 



Reserves Reconciliation
on Total Oil Equivalent Basis
Forecast Prices and Costs
 DevelopedProducing
    
    Proved
    
    Total Proved PlusReserves
    
    Reserves
    
    Probable Reserves(mboe)
    
    (mboe)
    
    (mboe)December 31, 2005
    
    
    143,741
    
    
    
    175,599
    
    
    
    219,396Exploration and Development
    
    
    3,479
    
    
    
    6,187
    
    
    
    10,196Improved Recovery and Infill Drilling
    
    
    5,792
    
    
    
    5,181
    
    
    
    10,176Revisions
    
    
    5,808
    
    
    
    2,786
    
    
    
    2,334Acquisitions
    
    
    55,012
    
    
    
    61,215
    
    
    
    81,451Dispositions
    
    
    (1,941
    )
    
    
    (2,163
    )
    
    
    (2,849
    )Production
    
    
    (22,930
    )
    
    
    (22,930
    )
    
    
    (22,930
    )December 31, 2006
    
    
    188,961
    
    
    
    225,875
    
    
    
    297,774
  
    
    Acquisitions, primarily from the Esprit Merger and purchase of the Carson Creek
assets, accounted for approximately 80 percent of the Total Proved Plus Probable
reserves added in 2006.
    
    New reserves were added from development activity. Most significant were infill
drilling and drilling extensions for Horseshoe Canyon CBM, infill drilling and
increased CO2 miscible flood recovery in the Weyburn Unit, an exploration
discovery at Quirk Creek and infill drilling at Tangleflags and Monogram. Reserve
increases in the Proved Producing category also resulted from reclassification of
Proved Undeveloped Reserves primarily for infill drilling and improved recovery in the
Weyburn, Judy Creek and Swan Hills miscible flood projects.
    
    Various performance related revisions were made to previous estimates resulting in a
net positive change. The largest revisions to Proved Reserves occurred at Tangleflags
(+834 mboe), Judy Creek BHL Unit (+802 mboe), Judy Creek West BHL Unit (+489 mboe),
Monogram Gas Unit (+408 mboe), Olds Gas Unit (-1,272 mboe) and West Pembina (-506
mboe).
    
    Numerous small, non-core properties were sold in a transaction which closed early in
2006.
 -41-




---



##### 



Future Net Revenue Reconciliation
  Future Net Revenue Reconciliation
Total Net Proved Reserves Discounted at Ten Percent Per Year
Constant Prices and Costs
 Period and Factor
    
    Before Tax 2006($M)December 31, 2005
    
    
    3,344,494Oil and Gas Sales During the Period Net of Production Costs and
Royalties(1)
    
    
    (675,454
    )Net Change due to Prices and Royalties Related to Forecast Production(2)
    
    
    (637,211
    )Change in Development Costs During the Period(3)
    
    
    282,900Change in Forecast Development Costs(4)
    
    
    (354,534
    )Change Resulting from Extensions, Infill Drilling and Improved Recovery(5)
    
    
    144,963Net Change Resulting from Discoveries(5)
    
    
    17,809Change Resulting from Acquisitions of Reserves(5)
    
    
    841,657Change Resulting from Dispositions of Reserves(6)
    
    
    (40,193
    )Accretion of Discount(7)
    
    
    334,449Net Change in Income Taxes(8)
    
    
    Change Resulting from Technical Reserves Revisions(5)
    
    
    48,459All Other Changes
    
    
    (141,832
    )December 31, 2006
    
    
    3,165,507
 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
   -42-




---



##### 



Proved Undeveloped Reserves
  2 2
  Probable Undeveloped Reserves
  
 Future Development Costs
  Undiscounted (year ended December 31, 2006)DiscountedUndiscounted
    
    at 10%2007(1)
    
    2008(1)
    
    2009(1)
    
    2010(1)
    
    2011(1)
    
    Remainder(1)
    
    Total(1)
    
    Total(2)($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)
    
    ($MM)Reserve CategoryProved Reserves
(Constant Prices and Costs)
    
    
    152
    
    
    
    73
    
    
    
    51
    
    
    
    28
    
    
    
    15
    
    
    
    96
    
    
    
    415
    
    
    
    318Proved Reserves
(Forecast Prices and Costs)
    
    
    152
    
    
    
    75
    
    
    
    53
    
    
    
    30
    
    
    
    16
    
    
    
    117
    
    
    
    443
    
    
    
    330Proved & Probable Reserves
(Forecast Prices and Costs)
    
    
    194
    
    
    
    134
    
    
    
    82
    
    
    
    43
    
    
    
    29
    
    
    
    172
    
    
    
    654
    
    
    
    482
 -43-




---



##### 



Notes:
 (1)
    
    Undiscounted.(2)
    
    Discounted at 10 percent.
  
 Finding, Development and Acquisition Costs
 Finding and Development Costs
 2
     2
   -44-




---



##### 



Acquisitions and Divestitures
      Future Development Capital
  FD&A Costs  Pengrowth Company Interest Reserves
 Proforma Pengrowth with CPPengrowth
    
    PropertiesTotal
    
    Proved plus
    
    Total
    
    Proved plusFinding, Development & Acquisition Costs Excluding FDC
    
    Proved
    
    Probable
    
    Proved
    
    ProbableExploration and Development Capital Expenditures (thousands)
    
    $
    300,800
    
    
    $
    300,800
    
    
    $
    300,800
    
    
    $
    300,800Exploration and Development Reserve Additions including
Revisions (mboe)
    
    
    14,155
    
    
    
    22,706
    
    
    
    14,155
    
    
    
    22,706Finding and Development Cost ($/boe)
    
    $
    21.25
    
    
    $
    13.25
    
    
    $
    21.25
    
    
    $
    13.25Net Acquisition Capital (thousands)(1)
    
    $
    1,839,900
    
    
    $
    1,839,900
    
    
    $
    2,869,221
    
    
    $
    2,869,221Net Acquisition Reserve Additions (mboe)
    
    
    59,051
    
    
    
    78,602
    
    
    
    110,222
    
    
    
    143,744Net Acquisition Cost ($/boe)
    
    $
    31.16
    
    
    $
    23.41
    
    
    $
    26.03
    
    
    $
    19.96Total Capital Expenditures including Net Acquisitions (thousands)
    
    $
    2,140,700
    
    
    $
    2,140,700
    
    
    $
    3,170,021
    
    
    $
    3,170,021Reserve Additions including Net Acquisitions (mboe)
    
    
    73,206
    
    
    
    101,307
    
    
    
    124,377
    
    
    
    166,450Finding, Development and Acquisition Cost ($/boe)
    
    $
    29.24
    
    
    $
    21.13
    
    
    $
    25.49
    
    
    $
    19.04
 -45-




---



##### 



Proforma Pengrowth with CPPengrowth
    
    PropertiesTotal
    
    Proved plus
    
    Total
    
    Proved plusFinding, Development & Acquisition Costs Excluding FDC
    
    Proved
    
    Probable
    
    Proved
    
    ProbableExploration and Development Capital Expenditures (thousands)
    
    $
    300,800
    
    
    $
    300,800
    
    
    $
    300,800
    
    
    $
    300,800Exploration and Development Change in FDC (thousands)
    
    $
    6,000
    
    
    $
    93,100
    
    
    $
    6,000
    
    
    $
    93,100Exploration and Development Capital including Change in FDC
(thousands)
    
    $
    306,800
    
    
    $
    393,900
    
    
    $
    306,800
    
    
    $
    393,900Exploration and Development Reserve Additions including
Revisions (mboe)
    
    
    14,155
    
    
    
    22,706
    
    
    
    14,155
    
    
    
    22,706Finding and Development Cost ($/boe)
    
    $
    21.67
    
    
    $
    17.35
    
    
    $
    21.67
    
    
    $
    17.35Net Acquisition Capital (thousands)(1)
    
    $
    1,839,900
    
    
    $
    1,839,900
    
    
    $
    2,869,221
    
    
    $
    2,869,221Net Acquisition FDC (thousands)
    
    $
    101,600
    
    
    $
    158,900
    
    
    $
    216,919
    
    
    $
    303,541Net Acquisition Capital including FDC (thousands)
    
    $
    1,941,500
    
    
    $
    1,998,800
    
    
    $
    3,086,140
    
    
    $
    3,172,762Net Acquisition Reserve Additions (mboe)
    
    
    59,051
    
    
    
    78,602
    
    
    
    110,222
    
    
    
    143,744Net Acquisition Cost ($/boe)
    
    $
    32.88
    
    
    $
    25.43
    
    
    $
    28.00
    
    
    $
    22.07Total Capital Expenditures including Net Acquisitions (thousands)
    
    $
    2,140,700
    
    
    $
    2,140,700
    
    
    $
    3,170,021
    
    
    $
    3,170,021Total Change in FDC (thousands)
    
    $
    107,600
    
    
    $
    252,000
    
    
    $
    222,919
    
    
    $
    396,641Total Capital including Change in FDC (thousands)
    
    $
    2,248,300
    
    
    $
    2,392,700
    
    
    $
    3,392,940
    
    
    $
    3,566,662Reserve Additions including Net Acquisitions (mboe)
    
    
    73,206
    
    
    
    101,307
    
    
    
    124,377
    
    
    
    166,450Finding, Development and Acquisition Cost including FDC ($/boe)
    
    $
    30.71
    
    
    $
    23.62
    
    
    $
    27.28
    
    
    $
    21.43
 Note:
 (1)
    
    Includes all assumed debt and working capital deficiency from the Esprit Merger. -46-




---



##### 



Other Oil and Gas Information
 Oil and Gas Wells
  Producing
    
    Non-producingGross
    
    Net
    
    Gross
    
    NetCrude Oil WellsAlberta
    
    
    1,637
    
    
    
    848
    
    
    
    494
    
    
    
    304British Columbia
    
    
    147
    
    
    
    103
    
    
    
    47
    
    
    
    43Saskatchewan
    
    
    1,173
    
    
    
    345
    
    
    
    199
    
    
    
    89Nova Scotia
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0Natural Gas WellsAlberta
    
    
    3,934
    
    
    
    1,672
    
    
    
    541
    
    
    
    287British Columbia
    
    
    128
    
    
    
    73
    
    
    
    34
    
    
    
    30Saskatchewan
    
    
    56
    
    
    
    47
    
    
    
    91
    
    
    
    50Nova Scotia
    
    
    19
    
    
    
    1
    
    
    
    0
    
    
    
    0Other(1)Alberta
    
    
    66
    
    
    
    64
    
    
    
    156
    
    
    
    106British Columbia
    
    
    0
    
    
    
    0
    
    
    
    50
    
    
    
    46Nova Scotia
    
    
    0
    
    
    
    0
    
    
    
    0
    
    
    
    0Saskatchewan
    
    
    21
    
    
    
    15
    
    
    
    22
    
    
    
    19Total
    
    
    7,181
    
    
    
    3,168
    
    
    
    1,634
    
    
    
    974
 
 Note:
 (1)
    
    Pengrowth cannot classify these wells as either oil or gas. Properties with No Attributed Reserves
  Pengrowth without CP Properties
Unproved Properties
as at December 31, 2006
 Gross
    
    Net
    
    Net Area to Expire DuringLocation
    
    Acres
    
    Acres
    
    2007(1)Alberta
    
    
    715,788
    
    
    
    448,884
    
    
    
    65,199British Columbia
    
    
    298,248
    
    
    
    132,248
    
    
    
    8,287Saskatchewan
    
    
    115,058
    
    
    
    94,746
    
    
    
    9,197Montana
    
    
    3,520
    
    
    
    3,520
    
    
    
    0Nova Scotia
    
    
    157,960
    
    
    
    12,381
    
    
    
    0Total
    
    
    1,290,574
    
    
    
    691,779
    
    
    
    82,683
 Note:
 (1)
    
    Excluding the CP Properties. -47-




---



##### 



CP Properties
Unproved Properties
as at December 31, 2006
 Net Area toGross
    
    Net
    
    Expire DuringLocation
    
    Acres
    
    Acres
    
    2007Alberta
    
    
    429,259
    
    
    
    285,199
    
    
    
    47,453Saskatchewan
    
    
    63,680
    
    
    
    61,030
    
    
    
    0Other
    
    
    0
    
    
    
    0
    
    
    
    0Total
    
    
    492,939
    
    
    
    346,229
    
    
    
    47,453
  Additional Information Concerning Abandonment & Reclamation Costs
    Pengrowth without CP Properties
Asset Retirement Obligation
 2007
    
    2008
    
    2009
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment, Reclamation,
Remediation & Dismantling
    
    
    11,131
    
    
    
    13,005
    
    
    
    12,409
    
    
    
    1,493,621
    
    
    
    1,530,166Discounted at 10%
    
    
    10,613
    
    
    
    11,273
    
    
    
    9,779
    
    
    
    163,267
    
    
    
    194,932
 CP Properties
Asset Retirement Obligation
 2007
    
    2008
    
    2009
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment, Reclamation,
Remediation & Dismantling
    
    
    5,769
    
    
    
    5,674
    
    
    
    6,002
    
    
    
    655,234
    
    
    
    672,679Discounted at 10%
    
    
    5,000
    
    
    
    4,471
    
    
    
    4,229
    
    
    
    47,783
    
    
    
    61,553
 -48-




---



##### 



Pro Forma  Pengrowth with CP Properties
Asset Retirement Obligation
 2007
    
    2008
    
    2009
    
    Remainder
    
    Total($M)
    
    ($M)
    
    ($M)
    
    ($M)
    
    ($M)Total Abandonment, Reclamation,
Remediation & Dismantling
    
    
    16,900
    
    
    
    18,679
    
    
    
    18,411
    
    
    
    2,148,855
    
    
    
    2,202,845Discounted at 10%
    
    
    15,613
    
    
    
    15,744
    
    
    
    14,008
    
    
    
    211,050
    
    
    
    256,485
 Income Tax
  Costs Incurred
  AmountNature of Cost
    
    ($MM)Acquisition Costs(1)Proved
    
    
    1,334Unproved
    
    
    440Exploration Costs
    
    
    9Development Costs
    
    
    276Total
    
    
    2,059
 
 Note:(1)
    
    Based on the values assigned to property, plant and equipment in
the purchase price allocations for the Esprit Merger and the Carson Creek
Acquisition. Development Activities
  Gross
    
    NetDevelopment WellsGas
    
    
    205
    
    
    
    123.5Oil
    
    
    76
    
    
    
    27.9Service
    
    
    5
    
    
    
    4.2Dry
    
    
    12
    
    
    
    7.3Total Wells
    
    
    298
    
    
    
    162.9
 Production Estimates
  -49-




---



##### 



Pengrowth (Excluding CP Properties)
 Total Proved
    
    Total Proved Plus
    
    Total Proved
    
    Total Proved PlusConstant Prices and
    
    Probable Constant
    
    Forecast Prices and
    
    Probable ForecastCosts
    
    Prices and Costs
    
    Costs
    
    Prices and CostsLight and Medium Crude (bblpd)
    
    
    23,298
    
    
    
    24,357
    
    
    
    23,300
    
    
    
    24,357Heavy Oil (bblpd)
    
    
    5,834
    
    
    
    6,114
    
    
    
    5,834
    
    
    
    6,114Natural Gas (mcfpd)
    
    
    235,720
    
    
    
    247,255
    
    
    
    235,787
    
    
    
    247,332Natural Gas Liquids (bblpd)
    
    
    8,480
    
    
    
    8,837
    
    
    
    8,479
    
    
    
    8,836Oil Equivalent (boepd)
    
    
    76,899
    
    
    
    80,518
    
    
    
    76,911
    
    
    
    80,530
 Pengrowth (Including CP Properties)
 Total Proved
    
    Total Proved Plus
    
    Total Proved
    
    Total Proved PlusConstant Prices and
    
    Probable Constant
    
    Forecast Prices and
    
    Probable ForecastCosts
    
    Prices and Costs
    
    Costs
    
    Prices and CostsLight and Medium Crude (bblpd)
    
    
    28,241
    
    
    
    29,362
    
    
    
    28,242
    
    
    
    29,361Heavy Oil (bblpd)
    
    
    8,822
    
    
    
    9,182
    
    
    
    8,822
    
    
    
    9,182Natural Gas (mcfpd)
    
    
    296,651
    
    
    
    309,331
    
    
    
    296,718
    
    
    
    309,408Natural Gas Liquids (bblpd)
    
    
    9,716
    
    
    
    10,087
    
    
    
    9,716
    
    
    
    10,087Oil Equivalent (boepd)
    
    
    96,221
    
    
    
    100,186
    
    
    
    96,223
    
    
    
    100,198
 Production History (Netback)
  -50-




---



##### 



Quarter EndedMarch 31,
    
    June 30,
    
    September 30,
    
    December 31,2006
    
    2006
    
    2006
    
    2006Light Crude OilAverage Daily Oil Production(1) (bblpd)
    
    
    21,262
    
    
    
    20,342
    
    
    
    20,651
    
    
    
    25,000Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    63.31
    
    
    
    72.67
    
    
    
    72.61
    
    
    
    60.35Processing and other income ($/bbl)
    
    
    0.65
    
    
    
    1.57
    
    
    
    0.41
    
    
    
    0.33Royalties ($/bbl)
    
    
    (7.23
    )
    
    
    (11.27
    )
    
    
    (12.19
    )
    
    
    (11.65
    )Amortization of injectants ($/bbl)
    
    
    (4.17
    )
    
    
    (4.61
    )
    
    
    (4.61
    )
    
    
    (4.08
    )Production Costs(2)($/bbl)
    
    
    (11.17
    )
    
    
    (12.44
    )
    
    
    (13.46
    )
    
    
    (18.16
    )Operating Netback ($/bbl)
    
    
    41.39
    
    
    
    45.92
    
    
    
    42.76
    
    
    
    26.79Heavy OilAverage Daily Oil Production(1) (bblpd)
    
    
    5,018
    
    
    
    4,869
    
    
    
    5,272
    
    
    
    4,695Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    29.18
    
    
    
    50.07
    
    
    
    51.47
    
    
    
    37.61Processing and other income ($/bbl)
    
    
    0.38
    
    
    
    0.16
    
    
    
    0.38
    
    
    
    0.80Royalties ($/bbl)
    
    
    (1.55
    )
    
    
    (4.75
    )
    
    
    (6.27
    )
    
    
    (5.44
    )Production Costs(2)($/bbl)
    
    
    (14.16
    )
    
    
    (16.03
    )
    
    
    (16.28
    )
    
    
    (14.06
    )Operating Netback ($/bbl)
    
    
    13.85
    
    
    
    29.45
    
    
    
    29.30
    
    
    
    18.91NGLsAverage Daily NGL Production(1) (bblpd)
    
    
    6,252
    
    
    
    5,952
    
    
    
    5,961
    
    
    
    8,910Sales Price (net of hedging gains/losses) ($/bbl)
    
    
    58.23
    
    
    
    58.92
    
    
    
    60.76
    
    
    
    52.69Royalties ($/bbl)
    
    
    (26.10
    )
    
    
    (17.67
    )
    
    
    (21.84
    )
    
    
    (16.61
    )Production Costs(2)($/bbl)
    
    
    (8.65
    )
    
    
    (10.20
    )
    
    
    (10.26
    )
    
    
    (14.00
    )Operating Netback ($/bbl)
    
    
    23.48
    
    
    
    31.05
    
    
    
    28.66
    
    
    
    22.08Natural GasAverage Daily Gas Production(1) (mcfpd)
    
    
    157,876
    
    
    
    150,976
    
    
    
    158,757
    
    
    
    234,050Sales Price (net of hedging gains/losses) ($/mcf)
    
    
    8.76
    
    
    
    6.76
    
    
    
    6.29
    
    
    
    7.12Processing and other income ($/mcf)
    
    
    0.20
    
    
    
    0.24
    
    
    
    0.23
    
    
    
    0.20Royalties ($/mcf)
    
    
    (2.54
    )
    
    
    (0.93
    )
    
    
    (1.34
    )
    
    
    (1.41
    )Production Costs(2)($/mcf)
    
    
    (1.63
    )
    
    
    (1.75
    )
    
    
    (1.47
    )
    
    
    (1.99
    )Operating Netback ($/mcf)
    
    
    4.79
    
    
    
    4.32
    
    
    
    3.71
    
    
    
    3.92Barrels
of Oil Equivalent Basis(3)Average
Daily Production(1)(boepd)
    
    
    58,845
    
    
    
    56,325
    
    
    
    58,344
    
    
    
    77,614Sales Price (net of hedging gains/losses) ($/boe)
    
    
    55.04
    
    
    
    54.91
    
    
    
    53.67
    
    
    
    49.24Processing and other income ($/boe)
    
    
    0.78
    
    
    
    1.21
    
    
    
    0.82
    
    
    
    0.77Royalties ($/boe)
    
    
    (12.34
    )
    
    
    (8.84
    )
    
    
    (10.77
    )
    
    
    (10.23
    )Amortization of injectants ($/boe)
    
    
    (1.51
    )
    
    
    (1.67
    )
    
    
    (1.63
    )
    
    
    (1.31
    )Production
Costs(2)($/boe)
    
    
    (10.53
    )
    
    
    (11.67
    )
    
    
    (11.27
    )
    
    
    (14.30
    )Operating Netback ($/boe)
    
    
    31.44
    
    
    
    33.94
    
    
    
    30.82
    
    
    
    24.17
 
 Notes:
 (1)
    
    Before the deduction of royalties.(2)
    
    Includes transportation costs. Net of processing and other income.(3)
    
    Natural gas has been converted to barrels of oil equivalent on the basis of six mcf of
natural gas being equal to one boe.
 -51-




---



##### 



Production
History (Production Type by Field)
  Pengrowth Company Interest Production
 Light/ MediumOil
    
    Heavy Oil
    
    Natural Gas Liquids
    
    Natural Gas
    
    TotalField
    
    (bblpd)
    
    (bblpd)
    
    (bblpd)
    
    (mcfpd)
    
    (boepd)Judy Creek BHL Unit
    
    
    7,298
    
    
    
    
    
    
    
    1,432
    
    
    
    5,300
    
    
    
    9,613Olds Gas Field Unit No. 1 (1)
    
    
    
    
    
    
    
    
    
    
    119
    
    
    
    4,000
    
    
    
    786Weyburn Unit
    
    
    2,894
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,894Swan Hills Unit No. 1
    
    
    2,214
    
    
    
    
    
    
    
    370
    
    
    
    1,800
    
    
    
    2,884Carson Creek North BHL Unit No. 1
(1)
    
    
    554
    
    
    
    
    
    
    
    273
    
    
    
    2,400
    
    
    
    1,227Sable Offshore Energy Project
    
    
    
    
    
    
    
    
    
    
    1,628
    
    
    
    28,800
    
    
    
    6,428Judy Creek West BHL Unit
    
    
    1,002
    
    
    
    
    
    
    
    144
    
    
    
    
    
    
    
    1,146Monogram Gas Unit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,100
    
    
    
    2,017Dunvegan Gas Unit No. 1
    
    
    13
    
    
    
    
    
    
    
    456
    
    
    
    8,000
    
    
    
    1,802Olds Non-Unit (1)
    
    
    3
    
    
    
    
    
    
    
    260
    
    
    
    2,500
    
    
    
    680Tangleflags North EOR
    
    
    
    
    
    
    1,615
    
    
    
    
    
    
    
    100
    
    
    
    1,632Quirk Creek
    
    
    
    
    
    
    
    
    
    
    183
    
    
    
    4,200
    
    
    
    883East Bodo
    
    
    
    
    
    
    651
    
    
    
    
    
    
    
    300
    
    
    
    701Twining
    
    
    330
    
    
    
    
    
    
    
    215
    
    
    
    7,200
    
    
    
    1,745McLeod River
    
    
    9
    
    
    
    
    
    
    
    223
    
    
    
    6,800
    
    
    
    1,365Twining CBM
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    800
    
    
    
    133Kaybob Notikewin Unit No. 1
    
    
    
    
    
    
    
    
    
    
    58
    
    
    
    4,900
    
    
    
    875Blackstone (2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,600
    
    
    
    267Oak
    
    
    814
    
    
    
    
    
    
    
    18
    
    
    
    1,500
    
    
    
    1,082Princess
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,300
    
    
    
    1,050Tilley Milk River Unit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,600
    
    
    
    600Enchant
    
    
    552
    
    
    
    
    
    
    
    25
    
    
    
    200
    
    
    
    610Other (2)
    
    
    6,138
    
    
    
    2,698
    
    
    
    1,370
    
    
    
    73,178
    
    
    
    22,401Total
    
    
    21,821
    
    
    
    4,964
    
    
    
    6,774
    
    
    
    175,578
    
    
    
    62,821
 Notes:
 (1)
    
    Acquired late in 2006. Production based on 3 months averaged over the year.(2)
    
    Other includes Pengrowths working and royalty interests in approximately 170 other
properties.
 -52-




---



##### 



Replacement of Properties
  
 Borrowing
   
 TRUST UNITS
 
 The Trust Indenture
  2 3
 -53-




---



##### 



The 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, the 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 business of a trust company.
 
 The Trustee
    
 Stock Exchange Listings
  
 Ownership Restrictions
  
 Redemption Right
  -54-




---



##### 



in specie
 
 Conversion Rights
  
 Voting at Meetings of Unitholders
    
 Voting at Meetings of Corporation
  
 Termination of the Trust
  -55-




---



##### 



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




---



##### 



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




---



##### 



EXCHANGEABLE SHARES
 Tax Act
      -58-




---



##### 



DISTRIBUTIONS
   ACTUAL DISTRIBUTIONS PAID OR DECLARED PER TRUST UNIT
 (Canadian $)2006
    
    2005
    
    2004
    
    2003
    
    2002
    
    2001First Quarter
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.63
    
    
    
    0.75
    
    
    
    0.41
    
    
    
    1.14Second Quarter
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.64
    
    
    
    0.67
    
    
    
    0.54
    
    
    
    0.83Third Quarter
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.67
    
    
    
    0.63
    
    
    
    0.52
    
    
    
    0.63Fourth Quarter
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.69
    
    
    
    0.63
    
    
    
    0.60
    
    
    
    0.41Total
    
    $
    3.00
    
    
    $
    2.82
    
    
    $
    2.63
    
    
    $
    2.68
    
    
    $
    2.07
    
    
    $
    3.01Taxable Income
    
    $
    2.40
    
    
    $
    2.22
    
    
    $
    1.43
    
    
    $
    1.47
    
    
    $
    0.43
    
    
    $
    1.80Taxable Percentage
    
    
    80.0
    %
    
    
    80.0
    %
    
    
    55.3
    %
    
    
    55.2
    %
    
    
    22.0
    %
    
    
    51.4
    %
   
 TRUST TAXATION
    -59-




---



##### 



CANADIAN FEDERAL INCOME TAX CONSIDERATIONS
  -60-




---



##### 



No assurance can be provided that
the October 31 Proposals will not apply to the Trust prior to 2011.
  
 Status of the Trust
  -61-




---



##### 



Taxation of the Trust
    
 Taxation of Unitholders Resident in Canada
    
 Taxation of Unitholders who are Non-Residents of Canada (Non-Resident Unitholders)
  -62-




---



##### 



This Annual
Information Form may not describe the United States tax consequences of the purchase, holding or
disposition of the Trust Units fully. Non-Resident Unitholders should obtain independent tax
advice as necessary.
 If enacted, the October 31 Proposals will likely have a material and adverse impact on the Trust
and its Unitholders. In the absence of final legislation implementing the October 31 Proposals,
the implications of the October 31 Proposals are difficult to fully evaluate and no assurance can
be provided as to the extent and timing of their application to the Trust and its Unitholders.
Prospective Unitholders are urged to consult their own tax advisors having regard to their own
particular circumstances including the impact of the October 31 Proposals on the Trust and
Unitholders. See  Risk Factors  The October 31 Proposals, if enacted, are expected to materially
and adversely affect the Trust, the Unitholders and the value of the Trust Units .
 -63-




---



##### 



UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
      
 Classification of Pengrowth Energy Trust as a Partnership
   -64-




---



##### 



Possible Classification as a Corporation; PFIC Rules
   
 Consequences of Possible PFIC Classification
  -65-




---



##### 




    
    the excess distribution or gain will be allocated ratably over the United States
holders holding period;
    
    the amount allocated to the current taxable year and any year prior to the first
year in which we were a PFIC will be taxed as ordinary income in the current year;
    
    the amount allocated to each of the other taxable years in the United States
holders holding period will be subject to tax at the highest rate of tax in effect for
the applicable class of taxpayer for that year; and
    
    an interest charge for the deemed deferral benefit will be imposed with respect to
the resulting tax attributable to each such other taxable year.
    
 Tax Consequences of Trust Unit Ownership
 Flow-through of Taxable Income
    -66-




---



##### 



Treatment of Distributions
  Basis of Trust Units
  Limitations on Deductibility of Losses
   Limitations on Interest Deductions
  Foreign Tax Credits
  -67-




---



##### 



Tax Treatment of Trust Operations
 Accounting Method and Taxable Year
  Depletion
    Depreciation
  Valuation of Our Properties
  -68-




---



##### 



Section 754 Election
   Transfers of Trust Units to Employees or Directors of Pengrowth Corporation and Pengrowth
Management
  
 Disposition of Trust Units
 Recognition of Gain or Loss
    -69-




---



##### 



Allocations between Transferors and Transferees
  Notification Requirements
  Constructive Termination
  Treatment of Trust Unit Lending and Short Sales
  -70-




---



##### 



Disposition of Trust Units by Redemption
  
 Uniformity of Trust Units
   
 Tax-Exempt Organizations
   -71-




---



##### 



Administrative Matters
 Trust Information Returns
  Registration as a Tax Shelter
     
 Reportable Transactions
  -72-




---



##### 



Foreign Partnership Reporting
  
 INDUSTRY CONDITIONS
 
 Government Regulation
  
 Pricing and Marketing  Oil
  
 Pricing and Marketing  Natural Gas
   -73-




---



##### 



Pricing and Marketing  Natural Gas Liquids
    Alberta
    British Columbia
  -74-




---



##### 



Saskatchewan
   Nova
Scotia
  
 Environmental Regulation
    -75-




---



##### 



MARKET FOR SECURITIES
  Toronto Stock Exchange
 CLASS A TRUST UNITS(PGF.A)
    
    
    
    
    
    CLASS B TRUST UNITS(PGF.B)Share Price Range
    
    
    
    
    
    
    
    
    
    Share Price RangeHigh
    
    Low
    
    Close
    
    Volume
    
    
    
    
    
    High
    
    Low
    
    Close
    
    Volume(Canadian $ per Trust Unit)
    
    (thousands)
    
    
    
    
    
    (Canadian $ per Trust Unit)
    
    (thousands)2006January
    
    
    28.96
    
    
    
    27.13
    
    
    
    28.57
    
    
    
    400
    
    
    
    
    
    
    
    23.35
    
    
    
    22.40
    
    
    
    23.20
    
    
    
    4,978February
    
    
    28.57
    
    
    
    24.96
    
    
    
    26.76
    
    
    
    253
    
    
    
    
    
    
    
    23.58
    
    
    
    20.71
    
    
    
    21.99
    
    
    
    5,460March
    
    
    28.22
    
    
    
    25.25
    
    
    
    26.88
    
    
    
    591
    
    
    
    
    
    
    
    24.50
    
    
    
    21.65
    
    
    
    23.32
    
    
    
    7,900April
    
    
    28.50
    
    
    
    26.40
    
    
    
    27.22
    
    
    
    174
    
    
    
    
    
    
    
    24.80
    
    
    
    23.26
    
    
    
    23.87
    
    
    
    4,482May
    
    
    28.24
    
    
    
    24.68
    
    
    
    26.07
    
    
    
    623
    
    
    
    
    
    
    
    24.80
    
    
    
    22.85
    
    
    
    24.80
    
    
    
    7,481June
    
    
    27.00
    
    
    
    24.20
    
    
    
    26.70
    
    
    
    1,013
    
    
    
    
    
    
    
    26.05
    
    
    
    22.41
    
    
    
    26.05
    
    
    
    7,020July
    
    
    28.25
    
    
    
    24.95
    
    
    
    25.30
    
    
    
    4,297
    
    
    
    
    
    
    
    27.25
    
    
    
    24.84
    
    
    
    25.31
    
    
    
    14,227August
    
    Not Traded after
    
    
    
    
    
    Not Traded afterSeptember
    
    July 27, 2006 at 5:00 PM MDT
    
    
    
    
    
    July 27, 2006 at 5:00 PM MDTOctoberNovemberDecember
 -76-




---



##### 



Toronto Stock Exchange
    
    New York Stock ExchangeTRUST UNITS (PGF.UN)
    
    TRUST UNITS (PGH)Share Price Range
    
    
    
    
    
    Share Price RangeHigh
    
    Low
    
    Close
    
    Volume
    
    High
    
    Low
    
    Close
    
    Volume(Canadian $ per Trust Unit)
    
    (thousands)
    
    (U.S. $ per Trust Unit)
    
    (thousands)2006January
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    25.15
    
    
    
    23.30
    
    
    
    24.96
    
    
    
    4,046February
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    25.03
    
    
    
    21.50
    
    
    
    23.65
    
    
    
    4,976March
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    24.10
    
    
    
    21.82
    
    
    
    23.10
    
    
    
    4,400April
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    24.99
    
    
    
    22.85
    
    
    
    24.45
    
    
    
    3,654May
    
    Not Traded before
    
    
    25.00
    
    
    
    21.85
    
    
    
    23.76
    
    
    
    5,107June
    
    July 27, 2006 at 5:00 PM MDT
    
    
    24.10
    
    
    
    22.00
    
    
    
    24.09
    
    
    
    5,517July
    
    
    25.35
    
    
    
    25.05
    
    
    
    25.30
    
    
    
    1585
    
    
    
    24.95
    
    
    
    21.84
    
    
    
    22.38
    
    
    
    10,342August
    
    
    26.11
    
    
    
    25.16
    
    
    
    25.96
    
    
    
    13,052
    
    
    
    23.50
    
    
    
    22.26
    
    
    
    23.19
    
    
    
    6,654September
    
    
    25.74
    
    
    
    21.02
    
    
    
    21.94
    
    
    
    14,625
    
    
    
    23.22
    
    
    
    18.90
    
    
    
    19.62
    
    
    
    10,363October
    
    
    22.69
    
    
    
    19.42
    
    
    
    21.90
    
    
    
    21,358
    
    
    
    20.25
    
    
    
    17.25
    
    
    
    19.60
    
    
    
    11,502November
    
    
    20.80
    
    
    
    16.81
    
    
    
    19.39
    
    
    
    33,396
    
    
    
    18.30
    
    
    
    14.78
    
    
    
    17.04
    
    
    
    28,191December
    
    
    20.50
    
    
    
    18.99
    
    
    
    19.94
    
    
    
    20,822
    
    
    
    17.75
    
    
    
    16.57
    
    
    
    17.21
    
    
    
    15,415
 
 DIRECTORS AND OFFICERS
  
 Directors and Officers of the Manager
  Name and Jurisdiction
    
    Position withof Residence
    
    Pengrowth Management
    
    Principal OccupationJames S. Kinnear
Alberta, Canada
    
    President and Director (since 1982)
    
    President,
Pengrowth Management LimitedGordon M. Anderson
Alberta, Canada
    
    Vice President, Financial Services (since 2001)
Vice President, Treasurer (1998-2001)
Treasurer (1995-1998)
    
    Vice President, Financial Services
Pengrowth Management LimitedCharles V. Selby
Alberta, Canada
    
    Corporate Secretary (since 1993)
    
    Lawyer, Selby Professional Corporation
Lawyer and Corporate Financial Advisor
 -77-




---



##### 



Principal Holders of Shares of the Manager
  
 Directors and Officers of the Corporation
  Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)James S. Kinnear(2)
Alberta, Canada
    
    President, Chairman, Director and
Chief Executive Office (since 1988)
    
    President, Pengrowth Management
Limited
    
    
    5,954,780Stanley H. Wong(3)
Alberta, Canada
    
    Director (since 1988)
    
    President, Carbine Resources Ltd.
a private oil and gas producing
and engineering consulting company
    
    
    49,864John B. Zaozirny(4)(5)
Alberta, Canada
    
    Director (since 1988)
    
    Counsel, McCarthy Tétrault,
Barristers and Solicitors
    
    
    44,362Thomas A.
Cumming(4)(5)(6)
Calgary, Alberta
    
    Director (since 2000)
    
    Business Consultant
    
    
    8,678Michael S. Parrett(4)(5)(6)
Ontario, Canada
    
    Director (since 2004)
    
    Business Consultant
    
    
    4,000Kirby L. Hedrick(3)(6)
Wyoming, United States of America
    
    Director (since 2005)
    
    Business Consultant
    
    
    4,000A. Terence Poole(4)(6)
Alberta, Canada
    
    Director (since 2005)
    
    Business Consultant
    
    
    20,000Wayne
K. Foo
(3)
Alberta, Canada
    
    Director (since 2006)
    
    President of Petro Andina
Resources Ind.
    
    
    3,843D. Michael G. Stewart(3)(5)
Alberta, Canada
    
    Director (since 2006)
    
    Principal of the Ballinacurra Group
    
    
    13,370Gordon M. Anderson
Alberta, Canada
    
    Vice President (since 2001)
Vice President, Treasurer (1997-2001)
Treasurer (1995-1997)
Chief Financial Officer (1991-1998)
    
    Vice President, Financial
Services, Pengrowth Management
Limited
    
    
    17,649Charles
V. Selby
Alberta, Canada
    
    Vice President and Corporate Secretary
(since 2005)
Corporate Secretary (since 1993)
    
    Lawyer, Selby Professional
Corporation Lawyer and Corporate
Financial Advisor
    
    
    142,342Christopher G. Webster
Alberta, Canada
    
    Chief Financial Officer (since 2005)
Treasurer (2000  2005)
    
    Chief Financial Officer Pengrowth
Corporation
    
    
    29,028
 -78-




---



##### 



Trust UnitsControlled orName and Jurisdiction
    
    Position with
    
    
    
    Beneficiallyof Residence
    
    Pengrowth Corporation
    
    Principal Occupation
    
    Owned(1)Larry B. Strong
Alberta, Canada
    
    Vice President, Geosciences (since 2005)
    
    Vice President, Geosciences
Pengrowth Corporation
    
    
    28,312
    

William G. Christensen
Alberta, Canada
    
    Vice President, Strategic Planning and
Reservoir Exploitation (since 2005)
    
    Vice President, Strategic Planning
and Reservoir Exploitation
Pengrowth Corporation
    
    
    11,242James E.A. Causgrove
Alberta, Canada
    
    Vice President, Production and
Operations (since 2005)
    
    Vice President, Production and
Operations Pengrowth Corporation
    
    
    16,139Douglas C. Bowles
Alberta, Canada
    
    Vice President and Controller
(since March 1, 2006)
Controller (since 2005)
    
    Vice President and Controller
Pengrowth Corporation
    
    
    8,441Peter Cheung 
Alberta, Canada
    
    Treasurer (since 2005)
    
    Treasurer
Pengrowth Corporation
    
    
    11,233
 
 Notes:(1)
    
    As at March 23, 2007 and excluding Trust Units issuable upon the exercise of outstanding
options, rights or deferred entitlement units.(2)
    
    In addition, Mr. Kinnear exercises control over 13,152 royalty units which are held by
Pengrowth Management Limited.(3)
    
    Member of Reserves, Options and Environment, Health and Safety Committee.(4)
    
    Member of Corporate Governance Committee.(5)
    
    Member of Compensation Committee.(6)
    
    Member of Audit Committee.    -79-




---



##### 



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
  (i)
    
    been subject to any penalties or sanctions imposed by a court relating to
securities legislation or by a securities regulatory authority or has entered into a
settlement agreement with a securities regulatory authority, other than penalties for
late filing of insider reports; or(ii)
    
    been subject to any other penalties or sanctions imposed by a court or
regulatory body that would likely be considered important to a reasonable investor in
making an investment decision.
 
 AUDIT COMMITTEE
 Audit Committees
 -80-




---



##### 



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 and the Alberta Capital
Market Foundation. He is also a
past president of the Calgary
Chamber of Commerce. Mr. Cumming
is a professional engineer and
holds a Bachelor of Applied
Science degree in Engineering
and Business.Michael S. Parrett
    
    Yes
    
    Yes
    
    Mr. Parrett is currently an
independent consultant providing
advisory service to various
companies in Canada and the
United States. Mr. Parrett is
Chairman of Gabriel Resources
Limited, a member of the board
of Fording Inc. and is serving
as a Trustee for Fording
Canadian Coal Trust. He was
formerly President of Rio Algom
Limited and prior to that Chief
Financial Officer of Rio Algom
and Falconbridge Limited. Mr.
Parrett is a chartered
accountant and holds a Bachelor
of Arts in Economics from York
University.A. Terence Poole
    
    Yes
    
    Yes
    
    Mr. Poole brings extensive
senior financial management,
accounting, capital and debt
market experience to Pengrowth.
He retired from Nova Chemicals
Corporation in 2006 where he had
held various senior management
positions including Executive
Vice-President, Corporate
Strategy and Development. Mr.
Poole currently serves on the
board of directors for Methanex
Corporation and Synenco Energy
Inc. Mr. Poole received a
Bachelor of Commerce degree from
Dalhousie University and holds a
Chartered Accountant
designation.Kirby L. Hedrick
    
    Yes
    
    Yes
    
    Mr. Hedrick has extensive
engineering and senior
management experience in the
United States and
internationally, retiring in
2000 as Executive
Vice-President, Upstream of
Phillips Petroleum. He
currently serves on the board of
directors of Noble Energy Inc.
and has recently been appointed
to the Wyoming Environmental
Quality Council. Mr. Hedrick
received a Bachelor of Science
and Mechanical Engineering
degree from the University of
Evansville, Indiana in 1975. He
completed the Stanford Executive
Program in 1997 and the Stanford
Corporate Governance Program in
2003.
 
 Principal Accountant Fees and Services
  2006
    
    2005Category
    
    (thousands of dollars)Audit Fees
    
    
    980
    
    
    
    305Audit Related Fees
    
    
    
    
    
    
    Tax Fees
    
    
    138
    
    
    
    104All Other Fees
    
    
    
    
    
    
    6Total
    
    
    1,118
    
    
    
    415
 Audit Fees.
 -81-




---



##### 



Audit-Related Fees.
 Tax Fees.
 All Other Fees.
 
 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 for the year ended December 31, 2006.
 The October 31 Proposals, if enacted, are expected to materially and adversely affect the Trust,
the Unitholders and the value of the Trust Units.
  -82-




---



##### 



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




---



##### 



Actual reserves will vary from reserve estimates, and those variations could be material, and
negatively affect the market price of the Trust Units and distributions to our Unitholders.
  
    
    historical production from the area compared with production rates from similar
producing areas;
    
    the assumed effect of government regulation;
    
    assumptions about future commodity prices, exchange rates, production and
development costs, capital expenditures, abandonment costs, environmental liabilities,
and applicable royalty regimes;
    
    initial production rates;
    
    production decline rates;
    
    ultimate recovery of reserves;
    
    marketability of production; and
    
    other government levies that may be imposed over the producing life of reserves.
   -84-




---



##### 



If the Corporation is unable to acquire additional reserves, the value of the Trust Units and
distributions to our Unitholders may decline.
  Our operation of oil and natural gas wells could subject us to environmental claims and liability
which would be funded out of our cash flow and could therefore reduce distributable cash payable to
our Unitholders.
  We may be unable to successfully compete with other companies in our industry, which could
negatively affect the market price of the Trust Units and distributions to our Unitholders.
  Incorrect assessments of value at the time of acquisitions could adversely affect the value of our
Trust Units and distributions to our Unitholders.
  Our indebtedness may limit the amount of distributions that we are able to pay our Unitholders, and
if we default on our debt, the net proceeds of any foreclosure sale would be allocated to the
repayment of
 -85-




---



##### 



our lenders and other creditors and only the remainder, if any, would be available for distribution
to our Unitholders.
   We are dependent on our management and the loss of our key management and other personnel could
negatively impact our business.
  A decline in the Corporations ability to market its oil and natural gas production could have a
material adverse effect on production levels or on the price received for production, which, in
turn, could reduce distributions to our Unitholders and affect the market price of the Trust Units.
  The operation of a significant portion of our properties is largely dependent on the ability of
third party operators, and harm to their business could cause delays and additional expenses in our
receiving revenues, which could negatively affect the market price of the Trust Units and
distributions to our Unitholders.
  -86-




---



##### 



Our distributions could be adversely affected by unforeseen title defects, which could reduce
distributions to our Unitholders.
  Fluctuations in foreign currency exchange rates could adversely affect our business, and adversely
affect the market price of the Trust Units as well as distributions to our Unitholders.
   Being a limited purpose trust makes the Trust largely dependent upon the operations and assets of
the Corporation if the oil and natural gas reserves associated with the Corporations resource
properties are not supplemented through additional development or the acquisition of oil and
natural gas properties, the ability of the Corporation to continue to generate cash flow for
distribution to Unitholders may be adversely affected.
  The Manager may have conflicts of interest that may create incentives for the Manager to act
contrary to or in competition with the interests of our Unitholders.
 -87-




---



##### 



We may incur material costs as a result of compliance with health, safety and environmental laws
and regulations which could negatively affect our financial condition and, therefore, reduce
distributions to our Unitholders and decrease the market price of the Trust Units.
  Lower oil and gas prices increase the risk of write-downs of our oil and gas property investments
which could be viewed unfavourably in the market or could limit our ability to borrow funds or
comply with covenants contained in our current or future credit agreements or other debt
instruments.
  Changes in Canadian legislation could adversely affect the value of our Trust Units.
  If the Trust ceases to qualify as a mutual fund trust it would adversely affect the value of our
Trust Units.
  -88-




---



##### 




    
    The Trust Units would cease to be a qualified investment for trusts governed by
RRSPs, RRIFs, RESPs and DPSPs, as defined in the Tax Act. Where, at the end of a
month, a RRSP, RRIF, RESP or DPSP holds Trust Units that ceased to be a qualified
investment, the RRSP, RRIF, RESP or DPSP, as the case may be, must, in respect of that
month, pay a tax under Part XI.1 of the Tax Act equal to one percent of the fair market
value of the Trust Units at the time such Trust Units were acquired by the RRSP, RRIF,
RESP or DPSP. In addition, trusts governed by a RRSP or a RRIF which hold Trust Units
that are not qualified investments will be subject to tax on the income attributable to
the Trust Units while they are non-qualified investments, including the full capital
gains, if any, realized on the disposition of such Trust Units. Where a trust governed
by a RRSP or a RRIF acquires Trust Units that are not qualified investments, the value
of the investment will be included in the income of the annuitant for the year of the
acquisition. Trusts governed by RESPs which hold Trust Units that are not qualified
investments can have their registration revoked by the Canada Revenue Agency.
    
    The Trust would be required to pay a tax under Part XII.2 of the Tax Act. The
payment of Part XII.2 tax by the Trust may have adverse income tax consequences for
certain Unitholders, including non-resident persons and residents of Canada who are
exempt from Part I tax.
    
    The Trust would not be entitled to use the capital gains refund mechanism otherwise
available for mutual fund trusts.
    
    The Trust Units would constitute taxable Canadian property for the purposes of the
Tax Act, potentially subjecting non-residents of Canada to tax pursuant to the Tax Act
on the disposition (or deemed disposition) of such Trust Units.
 The ability of investors resident in the United States to enforce civil remedies may be negatively
affected for a number of reasons.
 -89-




---



##### 



Securities Act of 1933
 
    
    will enforce judgments of United States courts obtained in actions against the Trust
or such persons predicated upon the civil liability provisions of the United States
federal securities laws or the securities or blue sky laws of any state within the
United States; or
    
    will enforce, in original actions, liabilities against the Trust or such persons
predicated upon the United States federal securities laws or any such state securities
or blue sky laws.
 Your rights as a Unitholder differ from the rights associated with other types of investments and
we cannot assure you that the distributions you receive over the life of your investment will meet
or exceed your initial capital investment.
   Future acquisitions may result in substantial future dilution of your Trust Units.
  Canadian and United States practices differ in reporting reserves and production and our estimates
may not be comparable to those of companies in the United States.
 Standards of Disclosure for Oil and Gas
Activities
 -90-




---



##### 



You may be required to pay taxes even if you do not receive any cash distributions.
  Unitholders who are United States persons face certain income tax risks.
  
    
    We have elected under applicable United States Treasury Regulations to be treated as
a partnership for United States federal income tax purposes. Section 7704 of the
Internal Revenue Code of 1986, as amended (the Code) provides that publicly-traded
partnerships such as the Trust will, as a general rule, be taxed as corporations. We
will not be treated as a corporation for U.S. federal income tax purposes only if 90
percent or more of its gross income consists of qualifying income. Although we expect
to satisfy the 90 percent requirement at all times, if we fail to satisfy this
requirement, we will be treated as a foreign corporation.
    
    If we were treated as a foreign corporation, we could be a passive foreign
investment company or PFIC. If we were considered a PFIC, United States holders of
Trust Units could be subject to substantially increased United States tax liability,
including an interest charge upon the sale or other disposition of the United States
holders Trust Units, or upon the receipt of excess distributions from the Trust.
Certain elections may be available to a United States holder if we were classified as a
PFIC to alleviate these adverse tax consequences.
    
    We treat the Royalty between the Trust and the Corporation as a royalty interest for
all legal purposes, including United States federal income tax purposes. The Royalty
Indenture in some respects differs from more conventional net profits interests as to
which the courts and the IRS have ruled, and as a result the propriety of such
treatment is not free from doubt. It is possible that the IRS could contend, for
example, that we should be considered to have a working interest in the properties of
the Corporation. If the IRS were successful in making such a contention, the United
States federal income tax consequences to United States holders could be different,
perhaps materially worse, than indicated in the discussion herein, which generally
assumes that the Royalty Indenture will be respected as a royalty.
 -91-




---



##### 




    
    Gain or loss will be recognized on a sale of Trust Units equal to the
difference between the amount realized and the United States holders tax basis for the
Trust Units sold. Gain or loss recognized by a United States holder on the sale or
exchange of Trust Units will generally be taxable as capital gain or loss, and will be
long-term capital gain or loss if such United States holders holding period of the
Trust Units exceeds one year. A portion of any amount realized on a sale or exchange of
Trust Units (which portion could be substantial) will be separately computed and taxed
as ordinary income under Section 751 of the Code to the extent attributable to the
recapture of depletion or depreciation deductions. Ordinary income attributable to
depletion deductions and depreciation recapture could exceed net taxable gain realized
upon the sale of the Trust Units and may be recognized even if there is a net taxable
loss realized on the sale of the Trust Units. Thus, a United States holder may
recognize both ordinary income and a capital loss upon a taxable disposition of Trust
Units.
    
    We have registered as a tax shelter with the United States Secretary of the
Treasury because of the absence of assurance that we will not be subject to tax shelter
registration and in light of the substantial penalties which otherwise might be imposed
if we failed to register and it were subsequently determined that registration was
required. Registration as a tax shelter may increase the risk of an IRS audit of us
or a Unitholder. Any Unitholder owning less than a 1 percent profits interest in us has
very limited rights to participate in the income tax audit process. Further, any
adjustments in our tax returns will lead to adjustments in our Unitholders tax returns
and may lead to audits of Unitholders tax returns and adjustments of items unrelated
to us. You will bear the cost of any expense incurred in connection with an examination
of your personal tax return.
    
    Because we cannot match transferors and transferees of Trust Units, we must maintain
uniformity of the economic and tax characteristics of the Trust Units to a purchaser of
these Trust Units. In the absence of such uniformity, the Trust may be unable to comply
completely with a number of federal income tax requirements. A lack of uniformity,
however, can result from a literal application of some Treasury regulations. If any
non-uniformity was required by the IRS, it could have a negative impact on the value of
the Trust Units.
    
    The Trust may not be an appropriate investment for certain types of entities. For
example, there is a risk that some of the Trusts income could be unrelated business
taxable income with respect to tax-exempt organizations. Prospective purchasers of
Trust Units that are tax-exempt organizations are encouraged to consult their tax
advisors regarding investments in Trust Units.
 Distributions to our Unitholders may be reduced during periods in which Pengrowth makes capital
expenditures using cash flow.
  Changes in government regulations that affect the crude oil and natural gas industry could
adversely affect Pengrowth and reduce our distributions to our Unitholders.
  -92-




---



##### 



We became subject to additional rules and regulations of the SEC related to internal controls
commencing with our fiscal year ending December 31, 2006 which has increased our legal and
compliance costs and may have an adverse effect on our business and the trading price of our Trust
Units.
 Securities Exchange Act of
1934 Sarbanes-Oxley Act of 2002
 If Pengrowth expands operations beyond oil and natural gas production in Canada, Pengrowth may face
new challenges and risks. If Pengrowth is unsuccessful in managing these challenges and risks, its
results of operations and financial condition could be adversely affected, which could affect the
market price of the Trust Units and distributions to Unitholders.
  Delays in business operations could adversely affect the Trusts distributions to Unitholders and
the market price of the Trust Units.
  
    
    restrictions imposed by lenders;
    
    accounting delays;
    
    delays in the sale or delivery of products;
 -93-




---



##### 




    
    delays in the connection of wells to a gathering system;
    
    blowouts or other accidents;
    
    adjustments for prior periods;
    
    recovery by the operator of expenses incurred in the operation of the properties; or
    
    the establishment by the operator of reserves for these expenses.
  Changes in market-based factors may adversely affect the trading price of the Trust Units.
  The limited liability of Unitholders is uncertain.
  The redemption right of Unitholders is limited.
 Trust Units  Redemption Right in specie
 The industry in which Pengrowth operates exposes Pengrowth to potential liabilities that may not be
covered by insurance.
  -94-




---



##### 



Pengrowth may not be able to achieve the anticipated benefits of the CP Acquisition, and the
integration process may result in the loss of key employees and the disruption of ongoing business,
customer and employee relationships.
  
 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.
  -95-




---



##### 



Insider Bids, Issuer Bids, Going Private Transactions and Related Party Transactions.
    
 LEGAL PROCEEDINGS
  
 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
    -96-




---



##### 



INTERESTS OF EXPERTS
  
 AUDITORS, TRANSFER AGENT AND REGISTRAR
  
 MATERIAL CONTRACTS
  1.
    
    Trust Indenture;2.
    
    Royalty Indenture;3.
    
    Unanimous Shareholders Agreement;4.
    
    Management Agreement;5.
    
    Combination Agreement dated July 23, 2006 and amended August 22, 2006 in connection with the
Esprit Merger;6.
    
    Acquisition Agreement dated November 28, 2006 in connection with the CP Acquisition;7.
    
    Credit Facility dated June 16, 2006 and amended October 2, 2006; and8.
    
    Bridge Credit Facility dated January 22, 2007.
  
 CODE OF ETHICS
 U.S.
Securities Exchange Act of 1934
 -97-




---



##### 



OFF-BALANCE SHEET ARRANGEMENTS
  
 DISCLOSURE PURSUANT TO THE REQUIREMENTS
 OF THE NEW YORK STOCK EXCHANGE
  www.pengrowth.com
  
    
    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
 -98-




---



##### 



open market with the exception of the Trust Unit Award Plan which was implemented as
an employee retention mechanism in a very tight prevailing market in the Canadian
oil and gas industry.
 
    
    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
  www.sedar.com
  Investor Relations 
Pengrowth Energy Trust 
Suite 2900, 240  4th Avenue SW 
Calgary, Alberta T2P 4H4
Telephone: (403) 233-0224
1-800-223-4122
Fax: (403) 294-0051
    
    Toronto Investor Relations
Scotia Plaza, 40 King Street West
Suite 3006, Box 106
Toronto, Ontario M5H 3Y2
Telephone: (416) 362-1748
1-888-744-1111
 www.pengrowth.com
 investorrelations@pengrowth.com
 -99-




---



##### 



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




---



##### 



FORM 51-101F2
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
  1.
    
    We have prepared an evaluation of the Companys reserves data as at December 31, 2006. The
reserves data consist of the following:
 (a)   (i)
    
    proved and proved plus probable oil and gas reserves estimated as at
December 31, 2006, 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, 2006, 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, 2006, and identifies the respective
portions thereof that we have audited, evaluated and reviewed and reported on to the
Companys board of directors:
 Location ofDescription and
    
    ReservesIndependent
    
    Preparation Date of
    
    (Country or
    
    Net Present Value of Future Net RevenueQualified Reserves
    
    Evaluation
    
    Foreign
    
    (before income taxes, 10% discount rate $M)Evaluator
    
    Report
    
    Geographic Area)
    
    Audited
    
    Evaluated
    
    Reviewed
    
    TotalGLJ Petroleum Consultants
    
    January 12, 2007
    
    Canada
    
    
    
    $
    4,433,372
    
    
    
    
    $
    4,433,372




---



##### 



5.
    
    In our opinion, the reserves data respectively evaluated by us have, in all material
respects, been determined and are in accordance with the COGE Handbook. We have no
responsibility to update our reports referred to in paragraph 4 for events and circumstances
occurring after their respective preparation dates.6.
    
    Because the reserves data are based on judgements regarding future events, actual
results will vary and the variations may be material.




---



##### 



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




---



##### 



FORM 51-101F3
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
  (a)
    
    (i)
    
    proved and proved plus probable oil and gas reserves
estimated as at December 31, 2006 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,
2006 using constant prices and costs; and(ii)
    
    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.




---



##### 



/s/ James S. KinnearJames S. KinnearChairman, President and Chief Executive Officer
Pengrowth Corporation/s/
William G. ChristensenWilliam G. ChristensenVice President, Strategic Planning and Reservoir Exploitation
Pengrowth Corporation/s/ Stanley H. WongStanley H. WongDirector
Pengrowth Corporation/s/ Wayne K. FooWayne K. FooDirector
Pengrowth Corporation -2-




---



##### 



APPENDIX C
 Audit Committee Charter




---



##### 



CHARTER OF THE AUDIT COMMITTEE OF THE
BOARD OF DIRECTORS OF PENGROWTH CORPORATION (THE COMPANY)
JULY 30, 2001
AND AMENDED AND RESTATED DECEMBER 14, 2006
 I. Audit Committee purpose:
      II. Audit Committee Composition and Meetings
    III. Audit Committee Responsibilities and Duties
 Review 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 financial statements, managements discussion and analysis and annual
and interim earnings press releases prior to filing or public distribution. This review
should include discussions with management, the internal auditors and the external auditors of
significant issues regarding accounting principles, practices and judgements.3.
    
    Review, discuss with management and the external auditors and recommend to the Board for
approval, the Companys audited annual financial statements, annual earnings press releases,
annual information form including management discussion and analysis, all statements required
in prospectuses and other offering memoranda, financial statements required by regulatory
authorities, all prospectuses and all documents which may be incorporated by reference into a
prospectus, including without limitation, the annual proxy circular. Approve on behalf of the
Board the Companys interim financial statements and related managements discussion and
analysis and interim earnings press releases.4.
    
    Ensure that adequate procedures are in place for the review of the Companys public
disclosure of financial information extracted or derived from the Companys financial
statements, other than the public disclosure referred to in paragraph 2 above and periodically
assess the adequacy of those procedures.5.
    
    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.6.
    
    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).7.
    
    Review with financial management, the internal auditors and the external auditors the
Companys policies relating to risk management and risk assessment.8.
    
    Be responsible for reviewing the disclosure contained in the Companys annual information
form as required by Form 52-110F1 Audit Committee Information Required in an AIF attached to
MI 52-110. If management of the Company solicits proxies from shareholders of the Company for
the purpose of recommending persons to be elected as directors of the Company, the Audit
Committee shall be responsible for ensuring that the Companys information circular includes a
cross-reference to the sections in the Companys annual information form that contain the
information required by Form 52-110F1.9.
    
    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
 10.
    
    Review the annual audit plans of the internal auditors.
 C-2




---



##### 



11.
    
    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.12.
    
    Review the adequacy of the resources of the internal auditors to ensure the objectivity and
independence of the internal audit function.13.
    
    Consult with management on managements appointment, replacement, reassignment or dismissal
of the internal auditors.14.
    
    Ensure that the internal auditors have access to the Chair, the Chair of the Board of
Directors and the Chief Executive Officer.
 External Auditors
 15.
    
    The Audit Committee shall advise the external auditors of their accountability to the Audit
Committee and the Board as representatives of the shareholders of the Company to whom the
external auditors are ultimately responsible. The External auditors shall report directly to
the Audit Committee. The Audit Committee is directly responsible for overseeing the work of
the external auditors, shall review at least annually the independence and performance of the
external auditors and shall annually recommend to the Board 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 external auditors internal quality-control procedures; (ii) any material
issues raised by the most recent internal quality-control review, or peer review, of the
external auditors, or by any inquiry or investigation by governmental or professional
authorities, within the preceding five years, respecting one or more independent audits
carried out by the external auditors, and any steps taken to deal with any such issues; and
(iii) all relationships between the independent auditor and the Company.16.
    
    Approve the fees and other compensation to be paid to the external auditors.17.
    
    Pre-approve all services to be provided to the Company or its subsidiary entities by the
Companys external auditors and all related terms of engagement.18.
    
    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.19.
    
    The Committee shall review the external auditors audit plan  discuss scope, staffing,
locations, and reliance upon management and general audit approach.20.
    
    Prior to releasing the year-end earnings, discuss the results of the audit with the external
auditors.21.
    
    Consider the external auditors judgments about the quality and appropriateness of the
Companys accounting principles as applied in its financial reporting.22.
    
    Be responsible for the resolution of disagreements between management and the external
auditors regarding financial performance.23.
    
    Ensure compliance by the Companys external auditors with the requirements set forth in
National Instrument 52-108 Auditor Oversight.24.
    
    Ensure that the Companys external auditors are participants in good standing with the
Canadian Public Accountability Board (CPAB) and participate in the oversight programs
established by the CPAB from time to time and that the external auditors have complied with
any restrictions or
 C-3




---



##### 



sanctions imposed by the CPAB as of the date of the applicable auditors report relating to
the Companys annual audited financial statements.25.
    
    Monitor compliance with the lead auditor rotation requirements of Regulation S-X.
 Other Audit Committee Responsibilities
 26.
    
    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.27.
    
    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.28.
    
    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.29.
    
    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.30.
    
    Ensure the preparation and filing of each annual certificate in Form 52-109F1 and each
interim certificate in Form 52-109F2 to be signed by each of the Chief Executive Officer and
Chief Financial Officer of the Company in accordance with the requirements set forth under
Multilateral Instrument 52-109 Certification of Disclosure in Issuers Annual and Interim
Filings as amended from time to time (MI 52-109).31.
    
    In respect of annual filings only, the Audit Committee is responsible for ensuring that
management of the Company evaluates the effectiveness of the Companys disclosure controls and
procedures as of the end of the period covered by the annual filings and has caused the
Company to disclose in the annual managements discussion and analysis its conclusions about
the effectiveness of the disclosure controls and procedures as of the end of the period
covered by the annual filings based on such evaluation. The terms annual filings, interim
filings, disclosure controls and procedures and internal control over financial reporting
shall have the meanings set forth under MI 52-109.32.
    
    Be responsible for monitoring any changes in the Companys internal control over financial
reporting and for ensuring that any change that occurred during the Companys most recent
interim period that has materially affected, or is reasonably likely to materially affect, the
Companys internal control over financial reporting is disclosed in the Companys annual
managements discussion and analysis.33.
    
    Review all exceptions to established policies, procedures and internal controls of the
Company which have been approved by any two officers of the Company.34.
    
    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.35.
    
    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




---



##### 



The following Managements Discussion and Analysis (MD&A) of financial results should be
read in conjunction with the audited consolidated Financial Statements for the year ended
December 31, 2006 of Pengrowth Energy Trust and is based on information available to February
26, 2007.
       PENGROWTH
2006 | 61




---



##### 



62 | PENGROWTH 2006




---



##### 



PENGROWTH
2006 | 63




---



##### 




    
    Oil and gas sales increased five percent to $1.2 billion dollars in 2006 reflecting
higher volumes produced during the year, partially offset by lower average realized
prices. In the fourth quarter, oil and gas sales were $351 million, an increase of 22
percent from the third quarter and virtually unchanged from the same quarter in 2005.
    
    Production for 2006 averaged 62,821 barrels of oil equivalent (boe) per day, a six
percent increase over 2005. Fourth quarter production averaged 77,614 boe per day, up 33
percent from the third quarter and 26 percent from the fourth quarter in 2005. The higher
production levels reflect volumes added through the Carson Creek and Esprit Trust
acquisitions and through ongoing development activities.
    
    Distributable cash totaled $576 million in 2006 and $140 million in the fourth
quarter. This represents a decrease of five percent from 2005 and one percent from the
previous quarter. The decreases are mainly as a result of higher operating, royalty,
administrative and interest costs incurred. The 26 percent decrease in the fourth quarter
of 2006 from the fourth quarter in 2005 is primarily due to higher production volumes
which were largely offset by lower commodity prices, higher operating, royalty,
administrative and interest costs incurred.
    
    Distributions remained stable during the fourth quarter and for the full year of
2006, at $0.25 per unit per month. For the full year, distributions of $3.00 per unit or
$559 million were paid or declared to unitholders, an increase of 25 percent from the
previous year.
    
    In 2006, Pengrowth paid out or declared 97 percent of its distributable cash as
distributions to unitholders and 132 percent in the fourth quarter. The payout ratio in
the fourth quarter reflects distributions paid out or declared on units issued for the
acquisition of Esprit Trust and for the acquisition of the CP Properties. However, due to
the usual delays in receiving cash flow from production as well as the early 2007 closing
of the CP Properties acquisition, the corresponding cash flow is not reflected in
operating results.
    
    During 2006, Pengrowth issued $1.9 billion in equity to fund strategic acquisitions
announced in 2006. This included the acquisition of the Carson Creek assets, the business
combination with Esprit Trust and most recently, the acquisition of the CP Properties
where $461 million in equity was raised at the end of 2006 and the acquisition was
completed in early 2007.
 64 | PENGROWTH 2006




---



##### 




    
    Net income decreased almost 20 percent for 2006 from 2005 as a result of higher operating
expenses, royalties and depletion and depreciation. Net income decreased approximately 97
percent in the fourth quarter of 2006 compared to the fourth quarter of 2005 primarily due to
higher depletion and depreciation expenses, lower commodity prices, higher operating, royalty,
administrative and interest costs incurred, partly offset by higher production volumes.
    
    During the year, Pengrowths average realized price was $52.88 per boe (after hedging)
compared to an average price of $53.02 per boe in 2005. A decrease in natural gas prices
during the year was largely offset by a combination of higher oil and natural gas liquids
prices and lower hedging losses. For the fourth quarter, average realized prices were $49.24
per boe (after hedging) down eight percent from the third quarter and 21 percent from the same
quarter last year. These decreases reflect a lower commodity price environment for oil and
natural gas in the fourth quarter of 2006.
    
    Operating netbacks (after hedging) decreased nine percent in 2006 to $29.59 per boe, largely
driven by higher operating and royalty costs. For the fourth quarter, operating netbacks were
$24.17 per boe down from the previous quarter and fourth quarter of 2005 by 22 percent and 38
percent, respectively. The fourth quarter netbacks were lower largely due to lower realized
prices and higher operating costs.
    
    Pengrowths development capital in 2006 totaled $301 million, an increase of 71 percent from
the previous year. This years capital program was one of Pengrowths most successful and
resulted in reserve replacement of 99 percent on a proved plus probable basis. Development
capital for the fourth quarter was $122 million compared to $57 million in the third quarter
and $60 million in the fourth quarter of 2005. During the year, Pengrowth participated in 298
gross (162.9 net) wells with a 96 percent success rate.
    
    On July 27, 2006 Pengrowth consolidated its Class A trust units and Class B trust units into
one class of trust units. The Class A trust units were delisted from the Toronto Stock
Exchange and converted into Class B trust units (with the exception of Class A trust units
held by residents of Canada who elected to retain their Class A trust units), the Class B
trust units were renamed as trust units and their trading symbol was changed from PGF.B to
PGF.UN.
    
    On March 30, 2006, Pengrowth closed the acquisition of an additional working interest in the
Dunvegan Unit as well as some minor oil and gas properties in central Alberta for
approximately $48 million.
    
    On January 12, 2006, Pengrowth divested non-core oil and gas properties for consideration of
$22 million of cash, prior to adjustments, and approximately eight million shares in Monterey
Exploration Ltd. (Monterey). Pengrowth holds approximately 34 percent of the common shares of
Monterey.
 PENGROWTH 2006 | 65




---



##### 



Three Months ended December 31
    
    
    
    Twelve Months ended December 31(thousands, except per unit amounts)
    
    
    2006
    
    
    
    2005
    
    
    % Change
    
    
    
    2006
    
    
    
    2005
    
    
    % ChangeINCOME STATEMENTOil and gas sales
    
    
    $
    350,908
    
    
    
    $
    353,923
    
    
    
    (1
    )
    
    
    $
    1,214,093
    
    
    
    $
    1,151,510
    
    
    
    5Net income
    
    
    $
    3,310
    
    
    
    $
    116,663
    
    
    
    (97
    )
    
    
    $
    262,303
    
    
    
    $
    326,326
    
    
    
    (20
    )Net income per trust unit
    
    
    $
    0.01
    
    
    
    $
    0.73
    
    
    
    (99
    )
    
    
    $
    1.49
    
    
    
    $
    2.08
    
    
    
    (28
    )CASH FLOWCash flows from operating activities
    
    
    $
    91,237
    
    
    
    $
    196,588
    
    
    
    (54
    )
    
    
    $
    554,368
    
    
    
    $
    618,070
    
    
    
    (10
    )Cash flows from operating activities
per trust unit
    
    
    $
    0.41
    
    
    
    $
    1.23
    
    
    
    (67
    )
    
    
    $
    3.15
    
    
    
    $
    3.93
    
    
    
    (20
    )Distributable cash*
    
    
    $
    140,405
    
    
    
    $
    189,379
    
    
    
    (26
    )
    
    
    $
    575,884
    
    
    
    $
    608,217
    
    
    
    (5
    )Distributable cash per trust unit*
    
    
    $
    0.64
    
    
    
    $
    1.19
    
    
    
    (46
    )
    
    
    $
    3.27
    
    
    
    $
    3.87
    
    
    
    (16
    )Distributions paid or declared
    
    
    $
    185,651
    
    
    
    $
    119,858
    
    
    
    55
    
    
    
    $
    559,063
    
    
    
    $
    445,977
    
    
    
    25Distributions paid or declared
per trust unit
    
    
    $
    0.75
    
    
    
    $
    0.75
    
    
    
    
    
    
    
    $
    3.00
    
    
    
    $
    2.82
    
    
    
    6Payout ratio*
    
    
    
    132
    %
    
    
    
    63
    %
    
    
    
    
    
    
    
    97
    %
    
    
    
    73
    %Capital expenditures
    
    
    $
    121,781
    
    
    
    $
    60,093
    
    
    
    103
    
    
    
    $
    300,809
    
    
    
    $
    175,693
    
    
    
    71Capital expenditures per trust unit
    
    
    $
    0.55
    
    
    
    $
    0.38
    
    
    
    45
    
    
    
    $
    1.71
    
    
    
    $
    1.12
    
    
    
    53Weighted average number
of trust units outstanding
    
    
    
    220,734
    
    
    
    
    159,528
    
    
    
    38
    
    
    
    
    175,871
    
    
    
    
    157,127
    
    
    
    12BALANCE SHEETWorking capital
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    (149,937
    )
    
    
    $
    (112,205
    )
    
    
    34Property, plant and equipment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    3,741,602
    
    
    
    $
    2,067,988
    
    
    
    81Long term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    604,200
    
    
    
    $
    368,089
    
    
    
    64Trust unitholders equity
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    3,049,677
    
    
    
    $
    1,475,996
    
    
    
    107Trust unitholders equity
per trust unit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    12.50
    
    
    
    $
    9.23
    
    
    
    35Number of trust units
outstanding at year end
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    244,017
    
    
    
    
    159,864
    
    
    
    53DAILY PRODUCTIONCrude oil (bbls)
    
    
    
    25,000
    
    
    
    
    21,179
    
    
    
    18
    
    
    
    
    21,821
    
    
    
    
    20,799
    
    
    
    5Heavy oil (bbls)
    
    
    
    4,695
    
    
    
    
    5,410
    
    
    
    (13
    )
    
    
    
    4,964
    
    
    
    
    5,623
    
    
    
    (12
    )Natural gas (mcf)
    
    
    
    234,050
    
    
    
    
    168,862
    
    
    
    39
    
    
    
    
    175,578
    
    
    
    
    161,056
    
    
    
    9Natural gas liquids (bbls)
    
    
    
    8,910
    
    
    
    
    6,710
    
    
    
    33
    
    
    
    
    6,774
    
    
    
    
    6,093
    
    
    
    11Total production (boe)
    
    
    
    77,614
    
    
    
    
    61,442
    
    
    
    26
    
    
    
    
    62,821
    
    
    
    
    59,357
    
    
    
    6TOTAL PRODUCTION (mboe)
    
    
    
    7,141
    
    
    
    
    5,653
    
    
    
    26
    
    
    
    
    22,930
    
    
    
    
    21,665
    
    
    
    6PRODUCTION PROFILECrude oil
    
    
    
    32
    %
    
    
    
    34
    %
    
    
    
    
    
    
    
    35
    %
    
    
    
    35
    %Heavy oil
    
    
    
    6
    %
    
    
    
    9
    %
    
    
    
    
    
    
    
    8
    %
    
    
    
    10
    %Natural gas
    
    
    
    50
    %
    
    
    
    46
    %
    
    
    
    
    
    
    
    46
    %
    
    
    
    45
    %Natural gas liquids
    
    
    
    12
    %
    
    
    
    11
    %
    
    
    
    
    
    
    
    11
    %
    
    
    
    10
    %AVERAGE REALIZED PRICES(after hedging)Crude oil (per bbl)
    
    
    $
    60.35
    
    
    
    $
    59.40
    
    
    
    2
    
    
    
    $
    66.85
    
    
    
    $
    58.59
    
    
    
    14Heavy oil (per bbl)
    
    
    $
    37.61
    
    
    
    $
    31.77
    
    
    
    18
    
    
    
    $
    42.26
    
    
    
    $
    33.32
    
    
    
    27Natural gas (per mcf)
    
    
    $
    7.12
    
    
    
    $
    11.97
    
    
    
    (41
    )
    
    
    $
    7.22
    
    
    
    $
    8.76
    
    
    
    (18
    )Natural gas liquids (per bbl)
    
    
    $
    52.69
    
    
    
    $
    58.46
    
    
    
    (10
    )
    
    
    $
    57.11
    
    
    
    $
    54.22
    
    
    
    5Average realized price per boe
    
    
    $
    49.24
    
    
    
    $
    62.55
    
    
    
    (21
    )
    
    
    $
    52.88
    
    
    
    $
    53.02
    
    
    
    PROVED PLUS
PROBABLE RESERVESCrude oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    112,388
    
    
    
    
    98,684
    
    
    
    14Heavy oil (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18,336
    
    
    
    
    15,790
    
    
    
    16Natural gas (bcf)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    827
    
    
    
    
    516
    
    
    
    60Natural gas liquids (mbbls)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    29,142
    
    
    
    
    18,985
    
    
    
    54Total oil equivalent (mboe)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    297,774
    
    
    
    
    219,396
    
    
    
    36
 *
    
    See the section entitled Non-GAAP Financial Measures. Prior year restated to
conform to presentation adopted in current year.
 66 | PENGROWTH 2006




---



##### 



Daily Production
 Three months ended
    
    
    
    Twelve months endedDec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Light crude oil (bbls)
    
    
    
    25,000
    
    
    
    
    20,651
    
    
    
    21,179
    
    
    
    
    21,821
    
    
    
    
    20,799Heavy oil (bbls)
    
    
    
    4,695
    
    
    
    
    5,272
    
    
    
    5,410
    
    
    
    
    4,964
    
    
    
    
    5,623Natural gas (mcf)
    
    
    
    234,050
    
    
    
    
    158,757
    
    
    
    168,862
    
    
    
    
    175,578
    
    
    
    
    161,056Natural gas liquids (bbls)
    
    
    
    8,910
    
    
    
    
    5,961
    
    
    
    6,710
    
    
    
    
    6,774
    
    
    
    
    6,093Total boe per day
    
    
    
    77,614
    
    
    
    
    58,344
    
    
    
    61,442
    
    
    
    
    62,821
    
    
    
    
    59,357
    PENGROWTH 2006 | 67




---



##### 



Three months ended
    
    
    
    Twelve months ended(Cdn$)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Light crude oil (per bbl)
    
    
    
    60.94
    
    
    
    
    75.53
    
    
    
    67.00
    
    
    
    
    68.83
    
    
    
    
    65.47after hedging
    
    
    
    60.35
    
    
    
    
    72.61
    
    
    
    59.40
    
    
    
    
    66.85
    
    
    
    
    58.59Heavy oil (per bbl)
    
    
    
    37.61
    
    
    
    
    51.47
    
    
    
    31.77
    
    
    
    
    42.26
    
    
    
    
    33.32Natural gas (per mcf)
    
    
    
    6.82
    
    
    
    
    6.22
    
    
    
    12.80
    
    
    
    
    7.08
    
    
    
    
    8.99after hedging
    
    
    
    7.12
    
    
    
    
    6.29
    
    
    
    11.97
    
    
    
    
    7.22
    
    
    
    
    8.76Natural gas liquids (per bbl)
    
    
    
    52.69
    
    
    
    
    60.76
    
    
    
    58.46
    
    
    
    
    57.11
    
    
    
    
    54.22Total per boe
    
    
    
    48.52
    
    
    
    
    54.51
    
    
    
    67.43
    
    
    
    
    53.18
    
    
    
    
    56.06after hedging
    
    
    
    49.24
    
    
    
    
    53.67
    
    
    
    62.55
    
    
    
    
    52.88
    
    
    
    
    53.02Benchmark pricesWTI oil (U.S. $ per bbl)
    
    
    
    60.17
    
    
    
    
    70.54
    
    
    
    60.05
    
    
    
    
    66.25
    
    
    
    
    56.70AECO spot gas (Cdn $ per gj)
    
    
    
    6.36
    
    
    
    
    5.72
    
    
    
    11.08
    
    
    
    
    6.70
    
    
    
    
    8.04NYMEX gas (U.S. $ per mmbtu)
    
    
    
    6.56
    
    
    
    
    6.66
    
    
    
    12.97
    
    
    
    
    7.24
    
    
    
    
    8.62Currency (U.S. $ per Cdn $)
    
    
    
    0.88
    
    
    
    
    0.89
    
    
    
    0.85
    
    
    
    
    0.88
    
    
    
    
    0.83
   ($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedRealized
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Light crude oil
    
    
    
    1.4
    
    
    
    
    5.5
    
    
    
    14.8
    
    
    
    
    15.8
    
    
    
    
    52.2Light crude oil ($ per bbl)
    
    
    
    0.59
    
    
    
    
    2.92
    
    
    
    7.60
    
    
    
    
    1.98
    
    
    
    
    6.88Natural gas
    
    
    
    (6.5
    )
    
    
    
    (1.0
    )
    
    
    12.9
    
    
    
    
    (8.8
    )
    
    
    
    13.6Natural gas ($ per mcf)
    
    
    
    (0.30
    )
    
    
    
    (0.07
    )
    
    
    0.83
    
    
    
    
    (0.14
    )
    
    
    
    0.23Combined
    
    
    
    (5.1
    )
    
    
    
    4.5
    
    
    
    27.7
    
    
    
    
    7.0
    
    
    
    
    65.8Combined
($ per boe)
    
    
    
    (0.72
    )
    
    
    
    0.84
    
    
    
    4.88
    
    
    
    
    0.30
    
    
    
    
    3.04
 68 | PENGROWTH 2006




---



##### 



($ millions)
    
    
    Three months ended
    
    
    
    Twelve months endedDec. 31,
    
    
    % of
    
    
    
    Sept. 30,
    
    
    % of
    
    
    Dec. 31,
    
    
    % of
    
    
    
    Dec 31,
    
    
    % of
    
    
    
    Dec. 31,
    
    
    % ofSales Revenue
    
    
    2006
    
    
    total
    
    
    
    2006
    
    
    total
    
    
    2005
    
    
    total
    
    
    
    2006
    
    
    total
    
    
    
    2005
    
    
    totalLight crude oil
    
    
    
    138.8
    
    
    
    40
    
    
    
    
    137.9
    
    
    
    48
    
    
    
    115.7
    
    
    
    33
    
    
    
    
    532.4
    
    
    
    44
    
    
    
    
    444.8
    
    
    
    39Natural gas
    
    
    
    153.3
    
    
    
    44
    
    
    
    
    91.9
    
    
    
    32
    
    
    
    186.0
    
    
    
    53
    
    
    
    
    462.4
    
    
    
    38
    
    
    
    
    514.9
    
    
    
    45Natural gas liquids
    
    
    
    43.2
    
    
    
    12
    
    
    
    
    33.3
    
    
    
    11
    
    
    
    36.1
    
    
    
    10
    
    
    
    
    141.2
    
    
    
    12
    
    
    
    
    120.6
    
    
    
    10Heavy oil
    
    
    
    16.3
    
    
    
    4
    
    
    
    
    24.9
    
    
    
    9
    
    
    
    15.8
    
    
    
    4
    
    
    
    
    76.6
    
    
    
    6
    
    
    
    
    68.4
    
    
    
    6Brokered sales/sulphur
    
    
    
    (0.7
    )
    
    
    
    
    
    
    
    (0.2
    )
    
    
    
    
    
    
    0.3
    
    
    
    
    
    
    
    
    1.5
    
    
    
    
    
    
    
    
    2.8
    
    
    
    Total oil and gas sales
    
    
    
    350.9
    
    
    
    
    
    
    
    
    287.8
    
    
    
    
    
    
    
    353.9
    
    
    
    
    
    
    
    
    1,214.1
    
    
    
    
    
    
    
    
    1,151.5
   ($ millions)
    
    
    Light oil
    
    
    Natural gas
    
    
    NGL
    
    
    Heavy oil
    
    
    Other
    
    
    TotalYear ended December 31, 2005
    
    
    
    444.8
    
    
    
    514.9
    
    
    
    120.6
    
    
    
    68.4
    
    
    
    2.8
    
    
    
    1,151.5Effect of change in product prices
    
    
    
    26.8
    
    
    
    (122.5
    )
    
    
    7.1
    
    
    
    16.2
    
    
    
    
    
    
    
    (72.4
    )Effect of change in sales volumes
    
    
    
    24.4
    
    
    
    47.6
    
    
    
    13.5
    
    
    
    (8.0
    )
    
    
    
    
    
    
    77.5Effect of change in hedging losses/gains
    
    
    
    36.4
    
    
    
    22.4
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    58.8Other
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1.3
    )
    
    
    (1.3
    )Year ended December 31, 2006
    
    
    
    532.4
    
    
    
    462.4
    
    
    
    141.2
    
    
    
    76.6
    
    
    
    1.5
    
    
    
    1,214.1
 PENGROWTH 2006 | 69




---



##### 



Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Processing, interest & other income
    
    
    
    6.2
    
    
    
    
    4.7
    
    
    
    4.0
    
    
    
    
    18.8
    
    
    
    
    17.7$  per boe
    
    
    
    0.86
    
    
    
    
    0.88
    
    
    
    0.71
    
    
    
    
    0.82
    
    
    
    
    0.82
   Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Royalty expense
    
    
    
    73.1
    
    
    
    
    57.8
    
    
    
    68.0
    
    
    
    
    241.5
    
    
    
    
    213.9$  per boe
    
    
    
    10.23
    
    
    
    
    10.77
    
    
    
    12.03
    
    
    
    
    10.53
    
    
    
    
    9.87Royalties as a percent of sales
    
    
    
    20.8
    %
    
    
    
    20.1
    %
    
    
    19.2
    %
    
    
    
    19.9
    %
    
    
    
    18.6
    %
    Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Operating expenses
    
    
    
    99.7
    
    
    
    
    58.8
    
    
    
    61.2
    
    
    
    
    270.5
    
    
    
    
    218.1$  per boe
    
    
    
    13.97
    
    
    
    
    10.94
    
    
    
    10.83
    
    
    
    
    11.80
    
    
    
    
    10.07
  70 | PENGROWTH 2006




---



##### 



Three months ended
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Light oil transportation
    
    
    
    0.5
    
    
    
    
    0.5
    
    
    
    0.5
    
    
    
    
    2.0
    
    
    
    
    2.2$  per bbl
    
    
    
    0.21
    
    
    
    
    0.26
    
    
    
    0.27
    
    
    
    
    0.25
    
    
    
    
    0.29Natural gas transportation
    
    
    
    1.8
    
    
    
    
    1.3
    
    
    
    1.8
    
    
    
    
    5.6
    
    
    
    
    5.7$  per mcf
    
    
    
    0.09
    
    
    
    
    0.09
    
    
    
    0.12
    
    
    
    
    0.09
    
    
    
    
    0.10
   Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Purchased and capitalized
    
    
    
    9.4
    
    
    
    
    7.9
    
    
    
    14.5
    
    
    
    
    34.6
    
    
    
    
    34.7Amortization
    
    
    
    9.3
    
    
    
    
    8.8
    
    
    
    7.1
    
    
    
    
    34.6
    
    
    
    
    24.4
   PENGROWTH 2006 | 71




---



##### 



Three months ended
    
    
    
    Twelve months endedCombined Netbacks ($ per boe)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Sales price
    
    
    
    49.24
    
    
    
    
    53.67
    
    
    
    62.55
    
    
    
    
    52.88
    
    
    
    
    53.02Other production income
    
    
    
    (0.09
    )
    
    
    
    (0.06
    )
    
    
    0.06
    
    
    
    
    0.06
    
    
    
    
    0.1349.15
    
    
    
    
    53.61
    
    
    
    62.61
    
    
    
    
    52.94
    
    
    
    
    53.15Processing, interest and other income
    
    
    
    0.86
    
    
    
    
    0.88
    
    
    
    0.71
    
    
    
    
    0.82
    
    
    
    
    0.82Royalties
    
    
    
    (10.23
    )
    
    
    
    (10.77
    )
    
    
    (12.02
    )
    
    
    
    (10.53
    )
    
    
    
    (9.87
    )Operating expenses
    
    
    
    (13.97
    )
    
    
    
    (10.94
    )
    
    
    (10.83
    )
    
    
    
    (11.80
    )
    
    
    
    (10.07
    )Transportation costs
    
    
    
    (0.33
    )
    
    
    
    (0.33
    )
    
    
    (0.41
    )
    
    
    
    (0.33
    )
    
    
    
    (0.36
    )Amortization of injectants
    
    
    
    (1.31
    )
    
    
    
    (1.63
    )
    
    
    (1.25
    )
    
    
    
    (1.51
    )
    
    
    
    (1.13
    )Operating netback
    
    
    
    24.17
    
    
    
    
    30.82
    
    
    
    38.81
    
    
    
    
    29.59
    
    
    
    
    32.54
 Three months ended
    
    
    
    Twelve months endedLight Crude Netbacks ($ per bbl)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Sales price
    
    
    
    60.35
    
    
    
    
    72.61
    
    
    
    59.40
    
    
    
    
    66.85
    
    
    
    
    58.59Other production income
    
    
    
    (0.31
    )
    
    
    
    (0.19
    )
    
    
    0.17
    
    
    
    
    0.13
    
    
    
    
    0.3760.04
    
    
    
    
    72.42
    
    
    
    59.57
    
    
    
    
    66.98
    
    
    
    
    58.96Processing, interest and other income
    
    
    
    0.64
    
    
    
    
    0.60
    
    
    
    0.34
    
    
    
    
    0.58
    
    
    
    
    0.47Royalties
    
    
    
    (11.65
    )
    
    
    
    (12.19
    )
    
    
    (6.47
    )
    
    
    
    (10.63
    )
    
    
    
    (8.64
    )Operating expenses
    
    
    
    (17.95
    )
    
    
    
    (13.20
    )
    
    
    (14.32
    )
    
    
    
    (13.78
    )
    
    
    
    (12.28
    )Transportation costs
    
    
    
    (0.21
    )
    
    
    
    (0.26
    )
    
    
    (0.27
    )
    
    
    
    (0.25
    )
    
    
    
    (0.29
    )Amortization of injectants
    
    
    
    (4.08
    )
    
    
    
    (4.61
    )
    
    
    (3.63
    )
    
    
    
    (4.35
    )
    
    
    
    (3.21
    )Operating netback
    
    
    
    26.79
    
    
    
    
    42.76
    
    
    
    35.22
    
    
    
    
    38.55
    
    
    
    
    35.01
 Three months ended
    
    
    
    Twelve months endedHeavy Oil Netbacks ($ per bbl)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Sales price
    
    
    
    37.61
    
    
    
    
    51.47
    
    
    
    31.77
    
    
    
    
    42.26
    
    
    
    
    33.32Processing, interest and other income
    
    
    
    0.80
    
    
    
    
    0.38
    
    
    
    0.74
    
    
    
    
    0.43
    
    
    
    
    0.36Royalties
    
    
    
    (5.44
    )
    
    
    
    (6.27
    )
    
    
    (2.98
    )
    
    
    
    (4.53
    )
    
    
    
    (4.53
    )Operating expenses
    
    
    
    (14.06
    )
    
    
    
    (16.28
    )
    
    
    (11.60
    )
    
    
    
    (15.16
    )
    
    
    
    (15.65
    )Operating netback
    
    
    
    18.91
    
    
    
    
    29.30
    
    
    
    17.93
    
    
    
    
    23.00
    
    
    
    
    13.50
 72 | PENGROWTH 2006




---



##### 



Three months ended
    
    
    
    Twelve months endedNatural Gas Netbacks ($ per mcf)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Sales price
    
    
    
    7.12
    
    
    
    
    6.29
    
    
    
    11.97
    
    
    
    
    7.22
    
    
    
    
    8.76Other production income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.01
    
    
    
    
    7.12
    
    
    
    
    6.29
    
    
    
    11.97
    
    
    
    
    7.23
    
    
    
    
    8.76Processing, interest and other income
    
    
    
    0.20
    
    
    
    
    0.23
    
    
    
    0.19
    
    
    
    
    0.21
    
    
    
    
    0.23Royalties
    
    
    
    (1.41
    )
    
    
    
    (1.34
    )
    
    
    (2.62
    )
    
    
    
    (1.54
    )
    
    
    
    (1.70
    )Operating expenses
    
    
    
    (1.90
    )
    
    
    
    (1.38
    )
    
    
    (1.38
    )
    
    
    
    (1.65
    )
    
    
    
    (1.24
    )Transportation costs
    
    
    
    (0.09
    )
    
    
    
    (0.09
    )
    
    
    (0.12
    )
    
    
    
    (0.09
    )
    
    
    
    (0.10
    )Operating netback
    
    
    
    3.92
    
    
    
    
    3.71
    
    
    
    8.04
    
    
    
    
    4.16
    
    
    
    
    5.95
 Three months ended
    
    
    
    Twelve months endedNGLs Netbacks ($ per bbl)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Sales price
    
    
    
    52.69
    
    
    
    
    60.76
    
    
    
    58.46
    
    
    
    
    57.11
    
    
    
    
    54.22Royalties
    
    
    
    (16.61
    )
    
    
    
    (21.84
    )
    
    
    (21.29
    )
    
    
    
    (20.17
    )
    
    
    
    (17.66
    )Operating expenses
    
    
    
    (14.00
    )
    
    
    
    (10.26
    )
    
    
    (10.05
    )
    
    
    
    (11.12
    )
    
    
    
    (9.04
    )Operating netback
    
    
    
    22.08
    
    
    
    
    28.66
    
    
    
    27.12
    
    
    
    
    25.82
    
    
    
    
    27.52
    Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Cash G&A expense
    
    
    
    11.7
    
    
    
    
    6.8
    
    
    
    7.7
    
    
    
    
    34.1
    
    
    
    
    27.4$  per boe
    
    
    
    1.63
    
    
    
    
    1.27
    
    
    
    1.36
    
    
    
    
    1.49
    
    
    
    
    1.27Non-cash G&A expense
    
    
    
    (0.3
    )
    
    
    
    0.9
    
    
    
    0.8
    
    
    
    
    2.5
    
    
    
    
    2.9$  per boe
    
    
    
    (0.04
    )
    
    
    
    0.17
    
    
    
    0.14
    
    
    
    
    0.11
    
    
    
    
    0.13Total G&A
    
    
    
    11.4
    
    
    
    
    7.7
    
    
    
    8.5
    
    
    
    
    36.6
    
    
    
    
    30.3Total G&A ($  per boe)
    
    
    
    1.59
    
    
    
    
    1.44
    
    
    
    1.50
    
    
    
    
    1.60
    
    
    
    
    1.40
  PENGROWTH 2006 | 73




---



##### 



Three months ended
    
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Management Fee
    
    
    
    0.9
    
    
    
    
    0.8
    
    
    
    2.2
    
    
    
    
    7.0
    
    
    
    
    9.1Performance Fee
    
    
    
    (1.6
    )
    
    
    
    2.2
    
    
    
    2.2
    
    
    
    
    2.9
    
    
    
    
    6.9Total
    
    
    
    (0.7
    )
    
    
    
    3.0
    
    
    
    4.4
    
    
    
    
    9.9
    
    
    
    
    16.0Total ($  per boe)
    
    
    
    (0.09
    )
    
    
    
    0.56
    
    
    
    0.77
    
    
    
    
    0.43
    
    
    
    
    0.74
        74 | PENGROWTH 2006




---



##### 



PENGROWTH 2006 | 75




---



##### 



Three months ended
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Depletion and Depreciation
    
    
    
    129.2
    
    
    
    
    83.5
    
    
    
    71.4
    
    
    
    
    351.6
    
    
    
    
    285.0$  per boe
    
    
    
    18.09
    
    
    
    
    15.56
    
    
    
    12.63
    
    
    
    
    15.33
    
    
    
    
    13.15Accretion
    
    
    
    4.9
    
    
    
    
    4.5
    
    
    
    3.6
    
    
    
    
    16.6
    
    
    
    
    14.2$  per boe
    
    
    
    0.68
    
    
    
    
    0.84
    
    
    
    0.64
    
    
    
    
    0.72
    
    
    
    
    0.65
     76 | PENGROWTH 2006




---



##### 



PENGROWTH 2006 | 77




---



##### 








Three months ended
    
    
    Twelve months ended($ millions)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Geological and geophysical
    
    
    
    6.1
    
    
    
    
    0.5
    
    
    
    
    
    
    
    
    8.9
    
    
    
    
    1.4Drilling and completions
    
    
    
    83.6
    
    
    
    
    42.2
    
    
    
    41.1
    
    
    
    
    217.1
    
    
    
    
    130.3Plant and facilities
    
    
    
    26.6
    
    
    
    
    9.4
    
    
    
    10.2
    
    
    
    
    56.9
    
    
    
    
    34.1Land purchases
    
    
    
    5.5
    
    
    
    
    4.7
    
    
    
    8.8
    
    
    
    
    17.9
    
    
    
    
    9.9Development capital
    
    
    
    121.8
    
    
    
    
    56.8
    
    
    
    60.1
    
    
    
    
    300.8
    
    
    
    
    175.7Cash costs for business
acquisitions
    
    
    
    4.8
    
    
    
    
    475.6
    
    
    
    (0.6
    )
    
    
    
    500.5
    
    
    
    
    0.9Cash costs for
property acquisitions
    
    
    
    0.5
    
    
    
    
    (1.7
    )
    
    
    (1.3
    )
    
    
    
    52.9
    
    
    
    
    91.6Value of trust units issued for
acquisitions
    
    
    
    895.9
    
    
    
    
    
    
    
    
    
    
    
    
    
    895.9
    
    
    
    
    88.0Total value of cash and
trust units issued for acquisitions
    
    
    
    901.2
    
    
    
    
    473.9
    
    
    
    (1.9
    )
    
    
    
    1,449.3
    
    
    
    
    180.5Total capital expenditures
and acquisitions
    
    
    
    1,023.0
    
    
    
    
    530.7
    
    
    
    58.2
    
    
    
    
    1,750.1
    
    
    
    
    356.2




















78 | PENGROWTH 2006




---



##### 



As at December 31($ thousands)
    
    
    2006
    
    
    
    2005Term credit facilities
    
    
    
    257,000
    
    
    
    
    35,000Senior unsecured notes
    
    
    
    347,200
    
    
    
    
    333,089Working capital deficit
    
    
    
    140,563
    
    
    
    
    77,638Note payable
    
    
    
    
    
    
    
    
    20,000Bank indebtedness
    
    
    
    9,374
    
    
    
    
    14,567Net debt excluding convertible debentures
    
    
    
    754,137
    
    
    
    
    480,294Convertible debentures
    
    
    
    75,127
    
    
    
    
    Net debt including convertible debentures
    
    
    
    829,264
    
    
    
    
    480,294Trust unitholders equity
    
    
    
    3,049,677
    
    
    
    
    1,475,996Net debt excluding convertible debentures as a percentage of total book capitalization
    
    
    
    19.8
    %
    
    
    
    24.6
    %Net debt including convertible debentures as a percentage of total book capitalization
    
    
    
    21.4
    %
    
    
    
    24.6
    %Cash flow from operating activities
    
    
    
    554,368
    
    
    
    
    618,070Net debt excluding convertible debentures to cash flow from operating activities
    
    
    
    1.4
    
    
    
    
    0.8Net debt including convertible debentures to cash flow from operating activities
    
    
    
    1.5
    
    
    
    
    0.8
  PENGROWTH
2006 | 79




---



##### 



1.
    
    Total senior debt should not be greater than three times Earnings Before Income
Taxes Depreciation and Amortization (EBITDA) for the last four fiscal quarters.
 2.
    
    Total debt should not be greater than 3.5 times EBITDA for the last four fiscal
quarters.
 3.
    
    Total senior debt should be less than 50 percent of total book capitalization.
 4.
    
    EBITDA should not be less than four times interest expense.
    80
| PENGROWTH 2006




---



##### 



Three months ended
    
    Twelve months ended($ thousands, except per trust unit amounts)
    
    
    Dec 31, 2006
    
    
    
    Sept 30, 2006
    
    
    Dec 31, 2005
    
    
    
    Dec 31, 2006
    
    
    
    Dec 31, 2005Cash flows from operating activities
    
    
    
    91,237
    
    
    
    
    179,971
    
    
    
    196,588
    
    
    
    
    554,368
    
    
    
    
    618,070Change in non-cash
operating working capital
    
    
    
    50,714
    
    
    
    
    (37,028
    )
    
    
    (7,993
    )
    
    
    
    24,331
    
    
    
    
    (9,833
    )Funds generated from operations
    
    
    
    141,951
    
    
    
    
    142,943
    
    
    
    188,595
    
    
    
    
    578,699
    
    
    
    
    608,237Change in remediation trust funds
    
    
    
    (1,546
    )
    
    
    
    (599
    )
    
    
    784
    
    
    
    
    (2,815
    )
    
    
    
    (20
    )Distributable cash (2)
    
    
    
    140,405
    
    
    
    
    142,344
    
    
    
    189,379
    
    
    
    
    575,884
    
    
    
    
    608,217Distributions paid or declared
    
    
    
    185,651
    
    
    
    
    132,513
    
    
    
    119,858
    
    
    
    
    559,063
    
    
    
    
    445,977Distributable cash per trust unit (2)
    
    
    
    0.64
    
    
    
    
    0.88
    
    
    
    1.19
    
    
    
    
    3.27
    
    
    
    
    3.87Distributions paid or declared
per trust unit
    
    
    
    0.75
    
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    
    3.00
    
    
    
    
    2.82Payout ratio (1) (2)
    
    
    
    132
    %
    
    
    
    93
    %
    
    
    63
    %
    
    
    
    97
    %
    
    
    
    73
    %
 
 (1)
    
    Payout ratio is calculated as
distributions paid or declared divided by distributable cash.(2)
    
    Prior year restated to conform to presentation
adopted in the current year.   PENGROWTH
2006 | 81




---



##### 



82 | PENGROWTH 2006




---



##### 



($ thousands)
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    2010
    
    
    2011
    
    
    thereafter
    
    
    TotalLong term debt (1)
    
    
    
    
    
    
    
    
    
    
    
    257,000
    
    
    
    174,810
    
    
    
    
    
    
    
    158,759
    
    
    
    590,569Interest payments on
long term debt (2)
    
    
    
    30,172
    
    
    
    30,172
    
    
    
    23,202
    
    
    
    11,585
    
    
    
    8,704
    
    
    
    25,538
    
    
    
    129,373Convertible debentures (3)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    74,741
    
    
    
    
    
    
    
    
    
    
    
    74,741Interest payments on
convertible debentures (4)
    
    
    
    4,858
    
    
    
    4,858
    
    
    
    4,858
    
    
    
    4,858
    
    
    
    
    
    
    
    
    
    
    
    19,432Other (5)
    
    
    
    7,350
    
    
    
    7,387
    
    
    
    6,494
    
    
    
    6,019
    
    
    
    5,790
    
    
    
    35,923
    
    
    
    68,96342,380
    
    
    
    42,417
    
    
    
    291,554
    
    
    
    272,013
    
    
    
    14,494
    
    
    
    220,220
    
    
    
    883,078Purchase obligationsPipeline transportation
    
    
    
    47,959
    
    
    
    42,215
    
    
    
    33,317
    
    
    
    18,758
    
    
    
    18,207
    
    
    
    59,589
    
    
    
    220,045CO2 purchases (6)
    
    
    
    7,651
    
    
    
    5,845
    
    
    
    4,232
    
    
    
    4,267
    
    
    
    3,772
    
    
    
    14,876
    
    
    
    40,64355,610
    
    
    
    48,060
    
    
    
    37,549
    
    
    
    23,025
    
    
    
    21,979
    
    
    
    74,465
    
    
    
    260,688Remediation trust fund payments
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    250
    
    
    
    11,750
    
    
    
    13,00098,240
    
    
    
    90,727
    
    
    
    329,353
    
    
    
    295,288
    
    
    
    36,723
    
    
    
    306,435
    
    
    
    1,156,766
 (1)
    
    The debt repayment includes the principal owing at maturity on foreign
denominated fixed rate debt. (see Note 10 of the financial statements)(2)
    
    Interest
payments relate to the interest payable on foreign denominated fixed rate debt using the year-end
exchange rate.(3)
    
    Includes repayment of convertible debentures on maturity (see Note 9 of the
financial statements), and assumes no conversion of convertible debentures to trust units.(4)
    
    Includes annual interest on convertible debentures outstanding at year-end and
assumes no conversion of convertible debentures prior to maturity.(5)
    
    Includes office rent and vehicle leases.(6)
    
    For the Weyburn CO2 project, prices are denominated in U.S.
dollars and have been translated at the year-end exchange rate. For the Judy Creek CO2
pilot project, prices are denominated in Canadian dollars.
 PENGROWTH 2006 | 83




---



##### 



High
    
    
    Low
    
    
    Close
    
    
    Volume
    
    
    Value(000's)
    
    
    ($ millions)TSX  PGF.A ($ Cdn)2006 1st quarter
    
    
    
    28.96
    
    
    
    24.96
    
    
    
    26.88
    
    
    
    1,244
    
    
    
    33.82nd quarter
    
    
    
    28.50
    
    
    
    24.20
    
    
    
    26.70
    
    
    
    1,810
    
    
    
    47.63rd quarter *
    
    
    
    28.25
    
    
    
    24.95
    
    
    
    25.30
    
    
    
    4,297
    
    
    
    110.64th quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Year
    
    
    
    28.96
    
    
    
    24.20
    
    
    
    25.30
    
    
    
    7,351
    
    
    
    192.02005 1st 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
    
    
    
    192.9TSX  PGF.B ($ Cdn)2006 1st quarter
    
    
    
    24.50
    
    
    
    20.71
    
    
    
    23.32
    
    
    
    18,338
    
    
    
    420.12nd quarter
    
    
    
    26.05
    
    
    
    22.41
    
    
    
    26.05
    
    
    
    18,982
    
    
    
    459.63rd quarter *
    
    
    
    27.25
    
    
    
    24.84
    
    
    
    25.31
    
    
    
    14,226
    
    
    
    364.04th quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Year
    
    
    
    27.25
    
    
    
    20.71
    
    
    
    25.31
    
    
    
    51,546
    
    
    
    1,243.72005 1st 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
    
    
    
    1,738.2TSX  PGF.UN ($ Cdn)2006 1st quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2nd quarter
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3rd quarter *
    
    
    
    26.11
    
    
    
    21.02
    
    
    
    21.94
    
    
    
    29,262
    
    
    
    708.04th quarter
    
    
    
    22.69
    
    
    
    16.81
    
    
    
    19.94
    
    
    
    75,576
    
    
    
    1,505.0Year
    
    
    
    26.11
    
    
    
    16.81
    
    
    
    19.94
    
    
    
    104,838
    
    
    
    2,213.0NYSE  PGH ($ U.S.)2006 1st quarter
    
    
    
    25.15
    
    
    
    21.50
    
    
    
    23.10
    
    
    
    13,421
    
    
    
    316.22nd quarter
    
    
    
    25.00
    
    
    
    21.85
    
    
    
    24.09
    
    
    
    14,277
    
    
    
    337.03rd quarter
    
    
    
    24.95
    
    
    
    18.90
    
    
    
    19.62
    
    
    
    27,359
    
    
    
    604.04th quarter
    
    
    
    20.25
    
    
    
    14.78
    
    
    
    17.21
    
    
    
    55,108
    
    
    
    955.6Year
    
    
    
    25.15
    
    
    
    14.78
    
    
    
    17.21
    
    
    
    110,165
    
    
    
    2,212.82005 1st 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
    
    
    
    1,590.1
 
 *
    
    On July 27, 2006, Pengrowths Class A trust units and Class B trust units were
consolidated into a single class of trust units pursuant to which the Class A trust units were
delisted from the Toronto Stock Exchange, Class A trust units were converted into Class B
trust units (with the exception of Class A trust units held by residents of Canada who elected
to retain their Class A trust units) and the Class B trust units were renamed as trust units
and their trading symbol changed to PGF.UN. 84 | PENGROWTH 2006




---



##### 



2006
    
    
    Q1
    
    
    Q2
    
    
    Q3
    
    
    Q4Oil and gas sales ($000s)
    
    
    
    291,896
    
    
    
    283,532
    
    
    
    287,757
    
    
    
    350,908Net income ($000s)
    
    
    
    66,335
    
    
    
    110,116
    
    
    
    82,542
    
    
    
    3,310Net income per trust unit ($)
    
    
    
    0.41
    
    
    
    0.69
    
    
    
    0.51
    
    
    
    0.01Net income per trust unit  diluted ($)
    
    
    
    0.41
    
    
    
    0.68
    
    
    
    0.51
    
    
    
    0.01Distributable cash ($000s) (1)
    
    
    
    140,869
    
    
    
    152,266
    
    
    
    142,344
    
    
    
    140,405Actual distributions paid or declared per trust unit ($)
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.75
    
    
    
    0.75Daily production (boe)
    
    
    
    58,845
    
    
    
    56,325
    
    
    
    58,344
    
    
    
    77,614Total production (mboe)
    
    
    
    5,296
    
    
    
    5,126
    
    
    
    5,368
    
    
    
    7,141Average realized price ($ per boe)
    
    
    
    55.04
    
    
    
    54.91
    
    
    
    53.67
    
    
    
    49.24Operating netback ($ per boe)
    
    
    
    31.44
    
    
    
    33.94
    
    
    
    30.82
    
    
    
    24.17
 2005
    
    Q1
    
    
    Q2
    
    
    Q3
    
    
    Q4Oil 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)(1)
    
    
    126,144
    
    
    
    134,779
    
    
    
    157,915
    
    
    
    189,379Actual 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
    
    
    
    38.81
 
 (1)
    
    Prior year restated to conform to presentation adopted in the current year. PENGROWTH 2006 | 85




---



##### 



Twelve months ended December 31($ thousands)
    
    
    2006
    
    
    2005
    
    2004Oil and gas sales
    
    
    
    1,214,093
    
    
    
    
    1,151,510
    
    
    
    815,751Net income
    
    
    
    262,303
    
    
    
    
    326,326
    
    
    
    153,745Net income per trust unit ($)
    
    
    
    1.49
    
    
    
    
    2.08
    
    
    
    1.15Net income per trust unit  diluted ($)
    
    
    
    1.49
    
    
    
    
    2.07
    
    
    
    1.15Distributable cash (1)
    
    
    
    575,884
    
    
    
    
    608,217
    
    
    
    402,077Actual distributions paid or declared per trust unit ($)
    
    
    
    3.00
    
    
    
    
    2.82
    
    
    
    2.63Total assets
    
    
    
    4,669,972
    
    
    
    
    2,391,432
    
    
    
    2,276,534Long term debt (2)
    
    
    
    679,327
    
    
    
    
    368,089
    
    
    
    365,400Trust unitholders equity
    
    
    
    3,049,677
    
    
    
    
    1,475,996
    
    
    
    1,462,211Number of trust units outstanding at year end (thousands)
    
    
    
    244,017
    
    
    
    
    159,864
    
    
    
    152,973
 
 (1)
    
    Prior years restated to conform to presentation adopted in the current year.(2)
    
    Includes long term debt, long term portion of note payable and convertible
debentures.   
    
    The prices of Pengrowths products (crude oil, natural gas, and NGLs) fluctuate due
to many factors including local and global market supply and demand, weather patterns,
pipeline transportation and political stability.
 
    
    The marketability of our production depends in part upon the availability,
proximity and capacity of gathering systems, pipelines and processing facilities.
Operational or economic factors may result in the inability to deliver our products to
market.
 
    
    Geological and operational risks affect the quantity and quality of reserves and
the costs of recovering those reserves. Our actual results will vary from our reserve
estimates and those variations could be material.
 
    
    Government royalties, income taxes, commodity taxes and other taxes, levies and
fees have a significant economic impact on Pengrowths financial results. Changes to
federal and provincial legislation including implementation of the October 31 Proposals
governing such royalties, taxes and fees and other changes to federal and provincial
legislation could have a material adverse impact on Pengrowths financial results and the
value of Pengrowths trust units.
 86 | PENGROWTH 2006




---



##### 




    
    Oil and natural gas operations carry the risk of damaging the local environment in the event
of equipment or operational failure. The cost to remediate any environmental damage could be
significant.
 
    
    Environmental laws and regulatory initiatives impact Pengrowth financially and operationally.
We may incur substantial capital and operating expenses to comply with increasingly complex
laws and
regulations covering the protection of the environment and human health and safety. In
particular, we may be required to incur significant costs to comply with future regulations to
reduce greenhouse gas and other emissions.
 
    
    Pengrowths oil and gas reserves will be depleted over time and our level of 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. Additional uncertainty with new
legislation may limit access to capital or increase the cost of raising capital.
 
    
    Increased competition for properties will drive the cost of acquisitions up and expected
returns from the properties down.
 
    
    A significant portion of our properties are operated by third parties. If these operators
fail to perform their duties properly, or become insolvent, we may experience interruptions in
production and revenues from these properties or incur additional liabilities and expenses as
a result of the default of these third party operators.
 
    
    Increased activity within the oil and gas sector has increased the cost of goods and services
and makes it more difficult to hire and retain professional staff.
 
    
    Changing interest rates influence borrowing costs and the availability of capital.
 
    
    Investors interest in the oil and gas sector may change over time which would affect the
availability of capital and the value of Pengrowth trust units.
 
    
    Inflation may result in escalating costs which could impact unitholder distributions and the
value of Pengrowth trust units.
 
    
    Canadian/U.S. exchange rates influence revenues and, to a lesser extent, operating and
capital costs.
 
    
    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.
  PENGROWTH 2006 | 87




---



##### 



88 | PENGROWTH 2006




---



##### 



PENGROWTH 2006 | 89




---



##### 



90 | PENGROWTH 2006




---



##### 



PENGROWTH 2006 | 91




---



##### 



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




---



##### 



/s/
James S. Kinnear
    

/s/
Christopher G. WebsterJames S. Kinnear
    
    Christopher G. WebsterChairman, President and
    
    Chief Financial OfficerChief Executive Officer
  92 | PENGROWTH 2006




---



##### 



PENGROWTH 2006 | 93




---



##### 



94 | PENGROWTH 2006




---



##### 



Stated in thousands of dollars
 As at December 31
    
    
    2006
    
    
    
    2005ASSETSCurrent AssetsAccounts receivable
    
    
    $
    151,719
    
    
    
    $
    127,394Fair value of commodity contracts (Note 20)
    
    
    
    37,972
    
    
    
    
    189,691
    
    
    
    
    127,394Fair value of commodity contracts(Note 20)
    
    
    
    495
    
    
    
    
    Deposit on acquisition(Note 22)
    
    
    
    103,750
    
    
    
    
    Other assets(Note 4)
    
    
    
    29,097
    
    
    
    
    13,215Equity investment(Note 5)
    
    
    
    7,035
    
    
    
    
    Property, plant and equipment(Note 6)
    
    
    
    3,741,602
    
    
    
    
    2,067,988Goodwill(Note 3)
    
    
    
    598,302
    
    
    
    
    182,835$
    4,669,972
    
    
    
    $
    2,391,432LIABILITIES AND UNITHOLDERS EQUITYCurrent LiabilitiesBank indebtedness
    
    
    $
    9,374
    
    
    
    $
    14,567Accounts payable and accrued liabilities
    
    
    
    201,056
    
    
    
    
    111,493Distributions payable to unitholders
    
    
    
    122,080
    
    
    
    
    79,983Due to Pengrowth Management Limited
    
    
    
    2,101
    
    
    
    
    8,277Other liabilities (Notes 7 and 8)
    
    
    
    5,017
    
    
    
    
    25,279339,628
    
    
    
    
    239,599Fair value of commodity contracts(Note 20)
    
    
    
    1,367
    
    
    
    
    Contract liabilities(Note 8)
    
    
    
    16,825
    
    
    
    
    12,937Convertible debentures(Note 9)
    
    
    
    75,127
    
    
    
    
    Long term debt(Note 10)
    
    
    
    604,200
    
    
    
    
    368,089Asset retirement obligations(Note 11)
    
    
    
    255,331
    
    
    
    
    184,699Future income taxes(Note 12)
    
    
    
    327,817
    
    
    
    
    110,112Trust unitholders equity(Note 13)Trust unitholders capital
    
    
    
    4,383,993
    
    
    
    
    2,514,997Equity portion of convertible debentures
    
    
    
    160
    
    
    
    
    Contributed surplus
    
    
    
    4,931
    
    
    
    
    3,646Deficit (Note 15)
    
    
    
    (1,339,407
    )
    
    
    
    (1,042,647
    )3,049,677
    
    
    
    
    1,475,996Commitments(Note 21)Subsequent events(Note 22)$
    4,669,972
    
    
    
    $
    2,391,432
   [signed]Director
    
    
    
    [signed]Director
 PENGROWTH 2006 | 95




---



##### 



Stated in thousands of dollars
 Years ended December 31
    
    
    2006
    
    
    
    2005REVENUESOil and gas sales
    
    
    $
    1,214,093
    
    
    
    $
    1,151,510Processing and other income
    
    
    
    15,639
    
    
    
    
    15,091Royalties, net of incentives
    
    
    
    (241,494
    )
    
    
    
    (213,863
    )988,238
    
    
    
    
    952,738Interest and other income
    
    
    
    3,129
    
    
    
    
    2,596Net Revenue
    
    
    
    991,367
    
    
    
    
    955,334EXPENSESOperating
    
    
    
    270,519
    
    
    
    
    218,115Transportation
    
    
    
    7,621
    
    
    
    
    7,891Amortization of injectants for miscible floods
    
    
    
    34,644
    
    
    
    
    24,393Interest
    
    
    
    32,109
    
    
    
    
    21,642General and administrative
    
    
    
    36,613
    
    
    
    
    30,272Management fee
    
    
    
    9,941
    
    
    
    
    15,961Foreign exchange (gain) loss (Note 16)
    
    
    
    22
    
    
    
    
    (6,966
    )Depletion and depreciation
    
    
    
    351,575
    
    
    
    
    284,989Accretion (Note 11)
    
    
    
    16,591
    
    
    
    
    14,162Unrealized gain on commodity contracts (Note 20)
    
    
    
    (26,499
    )
    
    
    
    Other expenses
    
    
    
    10,183
    
    
    
    
    4,029743,319
    
    
    
    
    614,488Income Before Taxes
    
    
    
    248,048
    
    
    
    
    340,846Income Tax Expense (Reduction) (Note 12)Capital
    
    
    
    14
    
    
    
    
    2,244Future
    
    
    
    (14,269
    )
    
    
    
    12,276(14,255
    )
    
    
    
    14,520NET INCOME
    
    
    $
    262,303
    
    
    
    $
    326,326Deficit, beginning of year
    
    
    
    (1,042,647
    )
    
    
    
    (922,996
    )Distributions paid or declared
    
    
    
    (559,063
    )
    
    
    
    (445,977
    )Deficit, end of year
    
    
    $
    (1,339,407
    )
    
    
    $
    (1,042,647
    )Net Income per Trust Unit(Note 19)Basic
    
    
    $
    1.49
    
    
    
    $
    2.08Diluted
    
    
    $
    1.49
    
    
    
    $
    2.07
 
 96 | PENGROWTH 2006




---



##### 



Stated in thousands of dollars
 Years ended December 31
    
    
    2006
    
    
    2005CASH PROVIDED BY (USED FOR):OPERATINGNet income
    
    
    $
    262,303
    
    
    
    $
    326,326Depletion, depreciation and accretion
    
    
    
    368,166
    
    
    
    
    299,151Future income taxes (reduction)
    
    
    
    (14,269
    )
    
    
    
    12,276Contract liability amortization
    
    
    
    (5,447
    )
    
    
    
    (5,795
    )Amortization of injectants
    
    
    
    34,644
    
    
    
    
    24,393Purchase of injectants
    
    
    
    (34,630
    )
    
    
    
    (34,658
    )Expenditures on remediation
    
    
    
    (9,093
    )
    
    
    
    (7,353
    )Other non-cash items
    
    
    
    (66
    )
    
    
    
    Unrealized foreign exchange (gain) loss (Note 16)
    
    
    
    480
    
    
    
    
    (7,800
    )Unrealized gain on commodity contracts (Note 20)
    
    
    
    (26,499
    )
    
    
    
    Trust unit based compensation (Note 14)
    
    
    
    2,546
    
    
    
    
    2,932Deferred charges
    
    
    
    (5,081
    )
    
    
    
    (4,961
    )Amortization of deferred charges
    
    
    
    5,645
    
    
    
    
    3,726Changes in non-cash operating working capital (Note 17)
    
    
    
    (24,331
    )
    
    
    
    9,833554,368
    
    
    
    
    618,070FINANCINGDistributions paid
    
    
    
    (516,966
    )
    
    
    
    (436,450
    )Bank indebtedness
    
    
    
    9,374
    
    
    
    
    Change in long term debt, net
    
    
    
    (54,870
    )
    
    
    
    10,030Redemption of convertible debentures (Note 9)
    
    
    
    (21,184
    )
    
    
    
    Repayment of note payable (Note 7)
    
    
    
    (20,000
    )
    
    
    
    (15,000
    )Proceeds from issue of trust units
    
    
    
    971,791
    
    
    
    
    42,544368,145
    
    
    
    
    (398,876
    )INVESTINGBusiness acquisitions (Note 3)
    
    
    
    (500,451
    )
    
    
    
    (935
    )Property acquisitions
    
    
    
    (52,880
    )
    
    
    
    (91,633
    )Expenditures on property, plant and equipment
    
    
    
    (300,809
    )
    
    
    
    (175,693
    )Proceeds on property dispositions
    
    
    
    15,230
    
    
    
    
    37,617Deposit on acquisition (Note 22)
    
    
    
    (103,750
    )
    
    
    
    Change in remediation trust funds (Note 11)
    
    
    
    (2,815
    )
    
    
    
    (20
    )Change in non-cash investing working capital (Note 17)
    
    
    
    37,529
    
    
    
    
    1,117(907,946
    )
    
    
    
    (229,547
    )Change in cash (bank indebtedness)
    
    
    
    14,567
    
    
    
    
    (10,353
    )Bank indebtedness at beginning of year
    
    
    
    (14,567
    )
    
    
    
    (4,214
    )Cash (bank indebtedness) at end of year
    
    
    $
    
    
    
    
    $
    (14,567
    )
 
 PENGROWTH 2006 | 97




---



##### 



98 | PENGROWTH 2006




---



##### 



Basis of Presentation
   Joint Interest Operations
  Property, Plant and Equipment
      PENGROWTH 2006 | 99




---



##### 



Goodwill
  Injectant Costs
  Asset Retirement Obligations
   Income Taxes
   Trust Unit Compensation Plans
  100 | PENGROWTH 2006




---



##### 



Risk Management
      Measurement Uncertainty
  PENGROWTH 2006 | 101




---



##### 



Net Income Per Trust Unit
  Revenue Recognition
  Comparative Figures
  102 | PENGROWTH 2006




---



##### 



2006 Acquisitions
 Carson Creek
    
    
    EspritProperties
    
    
    Energy Trust
    
    
    TotalALLOCATION OF PURCHASE PRICE:Property, plant and equipment
    
    
    $
    495,806
    
    
    $
    1,207,121
    
    
    $
    1,702,927Goodwill
    
    
    
    129,745
    
    
    
    285,722
    
    
    
    415,467Fair value of commodity contracts
    
    
    
    
    
    
    
    10,601
    
    
    
    10,601Bank debt
    
    
    
    
    
    
    
    (276,870
    )
    
    
    (276,870
    )Convertible debentures (Note 9)
    
    
    
    
    
    
    
    (96,500
    )
    
    
    (96,500
    )Contract liabilities (Note 8)
    
    
    
    (9,073
    )
    
    
    
    
    
    
    (9,073
    )Asset retirement obligations
    
    
    
    (20,668
    )
    
    
    (51,651
    )
    
    
    (72,319
    )Future income taxes
    
    
    
    (121,384
    )
    
    
    (110,590
    )
    
    
    (231,974
    )Working capital deficiency
    
    
    
    
    
    
    
    (45,864
    )
    
    
    (45,864
    )$
    474,426
    
    
    $
    921,969
    
    
    $
    1,396,395CONSIDERATION:Cash
    
    
    $
    474,089
    
    
    $
    19,990
    
    
    $
    494,079Pengrowth trust units issued
    
    
    
    
    
    
    
    895,944
    
    
    
    895,944Acquisition costs
    
    
    
    337
    
    
    
    6,035
    
    
    
    6,372$
    474,426
    
    
    $
    921,969
    
    
    $
    1,396,395
   Carson Creek Properties
   PENGROWTH 2006 | 103




---



##### 



Esprit Energy Trust
    2005 Acquisitions
 Crispin
    
    
    Swan HillsEnergy Inc
    
    
    Properties
    
    
    TotalALLOCATION OF PURCHASE PRICE:Working capital
    
    $
    1,655
    
    
    $
    
    
    
    $
    1,655Property, plant and equipment
    
    
    121,729
    
    
    
    87,170
    
    
    
    208,899Goodwill
    
    
    12,216
    
    
    
    
    
    
    
    12,216Bank debt
    
    
    (20,459
    )
    
    
    
    
    
    
    (20,459
    )Asset retirement obligations
    
    
    (4,038
    )
    
    
    
    
    
    
    (4,038
    )Future income taxes
    
    
    (22,208
    )
    
    
    
    
    
    
    (22,208
    )$
    88,895
    
    
    $
    87,170
    
    
    $
    176,065CONSIDERATION:Cash
    
    $
    
    
    
    $
    87,170
    
    
    $
    87,170Pengrowth trust units issued
    
    
    87,960
    
    
    
    
    
    
    
    87,960Acquisition costs
    
    
    935
    
    
    
    
    
    
    
    935$
    88,895
    
    
    $
    87,170
    
    
    $
    176,065
   104 | PENGROWTH 2006




---



##### 



Crispin Energy Inc.
   Swan Hills Properties
   2006
    
    
    
    2005Deferred compensation expense
(net of accumulated amortization of $2,381, 2005  $2,143)
    
    
    $
    2,696
    
    
    
    $
    2,141Debt issue costs
(net of accumulated Amortization of $1,192, 2005 - $821)
    
    
    
    1,626
    
    
    
    
    1,997Imputed interest on note payable
(net of accumulated amortization of $3,607, 2005  $2,859)
    
    
    
    
    
    
    
    
    7484,322
    
    
    
    
    4,886Deferred foreign exchange loss on translation of U.K. debt
    
    
    
    13,631
    
    
    
    
    Remediation trust funds (Note 11)
    
    
    
    11,144
    
    
    
    
    8,329$
    29,097
    
    
    
    $
    13,215
  2006
    
    
    
    2005Investment in Monterey
    
    
    $
    7,035
    
    
    
    
    
   PENGROWTH 2006 | 105




---



##### 



2006
    
    
    
    2005Property, plant and equipment, at cost
    
    
    $
    5,365,309
    
    
    
    $
    3,340,106Accumulated depletion and depreciation
    
    
    
    (1,658,999
    )
    
    
    
    (1,307,424
    )Net book value of property, plant and equipment
    
    
    
    3,706,310
    
    
    
    
    2,032,682Net book value of deferred injectant costs
    
    
    
    35,292
    
    
    
    
    35,306Net book value of property, plant and equipment and deferred injectants
    
    
    $
    3,741,602
    
    
    
    $
    2,067,988
   EdmontonForeign
    
    
    LightWTI Oil
    
    
    Exchange Rate
    
    
    Crude Oil
    
    
    AECO GasYear
    
    
    (U.S.$/bbl)
    
    
    (U.S.$/Cdn$)
    
    
    (Cdn$/bbl)
    
    
    (Cdn$/mmbtu)2007
    
    
    $
    62.00
    
    
    
    0.87
    
    
    $
    70.25
    
    
    $
    7.202008
    
    
    $
    60.00
    
    
    
    0.87
    
    
    $
    68.00
    
    
    $
    7.452009
    
    
    $
    58.00
    
    
    
    0.87
    
    
    $
    65.75
    
    
    $
    7.752010
    
    
    $
    57.00
    
    
    
    0.87
    
    
    $
    64.50
    
    
    $
    7.802011
    
    
    $
    57.00
    
    
    
    0.87
    
    
    $
    64.50
    
    
    $
    7.852012
    
    
    $
    57.50
    
    
    
    0.87
    
    
    $
    65.00
    
    
    $
    8.152013
    
    
    $
    58.50
    
    
    
    0.87
    
    
    $
    66.25
    
    
    $
    8.302014
    
    
    $
    59.75
    
    
    
    0.87
    
    
    $
    67.75
    
    
    $
    8.502015
    
    
    $
    61.00
    
    
    
    0.87
    
    
    $
    69.00
    
    
    $
    8.702016
    
    
    $
    62.25
    
    
    
    0.87
    
    
    $
    70.50
    
    
    $
    8.902017
    
    
    $
    63.50
    
    
    
    0.87
    
    
    $
    71.75
    
    
    $
    9.10Escalate thereafter
    
    
    + 2.0 percent/yr
    
    
    
    
    
    
    + 2.0 percent/yr
    
    
    + 2.0 percent/yr
  2006
    
    
    
    2005Current portion of contract liabilities
    
    
    $
    5,017
    
    
    
    $
    5,279Note payable
    
    
    
    
    
    
    
    
    20,000$
    5,017
    
    
    
    $
    25,279
  106 | PENGROWTH 2006




---



##### 



2006
    
    
    
    2005Fixed price commodity contract
    
    
    $
    7,800
    
    
    
    $
    12,318Firm transportation contracts
    
    
    
    14,042
    
    
    
    
    5,89821,842
    
    
    
    
    18,216Less current portion
    
    
    
    (5,017
    )
    
    
    
    (5,279
    )$
    16,825
    
    
    
    $
    12,937
      PENGROWTH 2006 | 107




---



##### 



Debt
    
    
    Equity
    
    
    TotalFair value on October 2, 2006 (Note 3)
    
    
    $
    96,295
    
    
    $
    205
    
    
    $
    96,500Amortization of debt premium
    
    
    
    (29
    )
    
    
    
    
    
    
    (29
    )Redeemed for cash
    
    
    
    (21,139
    )
    
    
    (45
    )
    
    
    (21,184
    )Balance, December 31, 2006
    
    
    $
    75,127
    
    
    $
    160
    
    
    $
    75,287
  2006
    
    
    
    2005U.S. dollar denominated debt:U.S. $150 million senior unsecured notes at 4.93 percent due April 2010
    
    
    $
    174,810
    
    
    
    $
    174,450U.S. $50 million senior unsecured notes at 5.47 percent due April 2013
    
    
    
    58,270
    
    
    
    
    58,150233,080
    
    
    
    
    232,600Pound sterling denominated 50 million unsecured notes
at 5.46 percent due December 2015
    
    
    
    114,120
    
    
    
    
    100,489Canadian dollar revolving credit borrowings
    
    
    
    257,000
    
    
    
    
    35,000$
    604,200
    
    
    
    $
    368,089
     108 | PENGROWTH 2006




---



##### 



2006
    
    
    
    2005Asset retirement obligations, beginning of year
    
    
    $
    184,699
    
    
    
    $
    171,866Increase (decrease) in liabilities during the year related to:Acquisitions
    
    
    
    72,680
    
    
    
    
    6,347Disposals
    
    
    
    (1,500
    )
    
    
    
    (3,844
    )Additions
    
    
    
    1,649
    
    
    
    
    1,972Revisions
    
    
    
    (9,695
    )
    
    
    
    1,549Accretion expense
    
    
    
    16,591
    
    
    
    
    14,162Liabilities settled during the year
    
    
    
    (9,093
    )
    
    
    
    (7,353
    )Asset retirement obligations, end of year
    
    
    $
    255,331
    
    
    
    $
    184,699
 Remediation trust funds
    PENGROWTH 2006 | 109




---



##### 



Remediation Trust Funds
    
    
    2006
    
    
    
    2005Opening balance
    
    
    $
    8,329
    
    
    
    $
    8,309Contributions to Judy Creek Remediation Trust Fund
    
    
    
    1,036
    
    
    
    
    778Contributions to SOEP Environmental Restoration Fund
    
    
    
    2,153
    
    
    
    
    556Remediation funded by Judy Creek Remediation Trust Fund
    
    
    
    (374
    )
    
    
    
    (1,314
    )2,815
    
    
    
    
    20Closing balance
    
    
    $
    11,144
    
    
    
    $
    8,329
 Expenditures on ARO
    
    
    2006
    
    
    
    2005Expenditures on ARO not covered by the trust funds
    
    
    $
    8,719
    
    
    
    $
    6,039Expenditures on ARO covered by the trust funds
    
    
    
    374
    
    
    
    
    1,314$
    9,093
    
    
    
    $
    7,353
   2006
    
    
    
    2005Income before taxes
    
    
    $
    248,048
    
    
    
    $
    340,846Combined federal and provincial tax rate
    
    
    
    34.1
    %
    
    
    
    37.6
    %Expected income tax
    
    
    
    84,584
    
    
    
    
    128,158Net income of the Trust
    
    
    
    (85,989
    )
    
    
    
    (122,698
    )Resource allowance
    
    
    
    (8,618
    )
    
    
    
    (10,985
    )Non-deductible crown charges
    
    
    
    17,586
    
    
    
    
    24,271Unrealized foreign exchange gain
    
    
    
    1
    
    
    
    
    (1,623
    )Attributed Canadian royalty income
    
    
    
    (6,616
    )
    
    
    
    (3,541
    )Effect of proposed tax changes
    
    
    
    (19,886
    )
    
    
    
    Future tax rate difference
    
    
    
    2,491
    
    
    
    
    (1,402
    )Other including stock based compensation
    
    
    
    2,178
    
    
    
    
    96Future income taxes
    
    
    
    (14,269
    )
    
    
    
    12,276Capital taxes
    
    
    
    14
    
    
    
    
    2,244$
    (14,255
    )
    
    
    $
    14,520
  110 | PENGROWTH 2006




---



##### 



2006
    
    
    
    2005Future income tax liabilities:Property, plant, equipment and other assets
    
    
    $
    339,660
    
    
    
    $
    114,256Unrealized foreign exchange gain
    
    
    
    8,288
    
    
    
    
    9,689Other
    
    
    
    150
    
    
    
    
    110348,098
    
    
    
    
    124,055Future income tax assets:Attributed Canadian royalty income
    
    
    
    (13,947
    )
    
    
    
    (7,819
    )Contract liabilities
    
    
    
    (6,334
    )
    
    
    
    (6,124
    )$
    327,817
    
    
    
    $
    110,112
    Total Trust Units:
 Years ended December 31
    
    
    2006
    
    
    2005Number
    
    
    
    
    
    
    
    NumberTrust units issued
    
    
    of trust units
    
    
    Amount
    
    
    
    of trust units
    
    
    AmountBalance at beginning of year
    
    
    
    159,864,083
    
    
    $
    2,514,997
    
    
    
    
    152,972,555
    
    
    $
    2,383,284Issued for the Crispin acquisition (non-cash)
    
    
    
    
    
    
    
    
    
    
    
    
    4,225,313
    
    
    
    87,960Issued for the Esprit Trust business combination (non-cash)
    
    
    
    34,725,157
    
    
    
    895,944
    
    
    
    
    
    
    
    
    Issued for cash
    
    
    
    47,575,000
    
    
    
    987,841
    
    
    
    
    
    
    
    
    Issue costs
    
    
    
    
    
    
    
    (51,575
    )
    
    
    
    
    
    
    
    Issued on redemption of Deferred Entitlement Trust Units (DEUs)
    
    
    
    14,523
    
    
    
    233
    
    
    
    
    
    
    
    
    Issued for cash on exercise of trust unit options and rights
    
    
    
    607,766
    
    
    
    9,476
    
    
    
    
    1,512,211
    
    
    
    21,818Issued for cash under Distribution Reinvestment Plan (DRIP)
    
    
    
    1,226,806
    
    
    
    26,049
    
    
    
    
    1,154,004
    
    
    
    20,726Issued on redemption of Royalty Units (non-cash)
    
    
    
    3,288
    
    
    
    
    
    
    
    
    
    
    
    
    Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    
    1,028
    
    
    
    
    
    
    
    
    1,209Balance at end of year
    
    
    
    244,016,623
    
    
    $
    4,383,993
    
    
    
    
    159,864,083
    
    
    $
    2,514,997
 PENGROWTH 2006 | 111




---



##### 



Consolidated Trust Units:
 Year ended December 31
    
    
    2006NumberTrust units issued
    
    
    of trust units
    
    
    AmountBalance at beginning of year
    
    
    
    
    
    
    $
    Issued in trust unit consolidation
    
    
    
    160,921,001
    
    
    
    2,535,949Issued on conversion of Class A trust units
    
    
    
    3,450
    
    
    
    57Issued for the Esprit Trust business combination (non-cash)
    
    
    
    34,725,157
    
    
    
    895,944Issued for cash
    
    
    
    47,575,000
    
    
    
    987,841Issue costs
    
    
    
    
    
    
    
    (51,575
    )Issued on redemption of DEUs
    
    
    
    14,523
    
    
    
    233Issued for cash on exercise of trust unit options and rights
    
    
    
    99,228
    
    
    
    1,579Issued for cash under DRIP
    
    
    
    663,458
    
    
    
    13,415Issued on redemption of Royalty Units (non-cash)
    
    
    
    3,288
    
    
    
    Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    
    376Balance at end of year
    
    
    
    244,005,105
    
    
    $
    4,383,819
 Class A Trust Units:
 Years ended December 31
    
    
    2006
    
    
    
    2005Number
    
    
    
    
    
    
    
    NumberTrust units issued
    
    
    of trust units
    
    
    Amount
    
    
    
    of trust units
    
    
    AmountBalance at beginning of year
    
    
    
    77,524,673
    
    
    $
    1,196,121
    
    
    
    
    76,792,759
    
    
    $
    1,176,427Issued for the Crispin acquisition (non-cash)
    
    
    
    
    
    
    
    
    
    
    
    
    686,732
    
    
    
    19,002Trust units converted to Class A trust units
    
    
    
    2,760
    
    
    
    43
    
    
    
    
    45,182
    
    
    
    692Trust units converted to consolidated trust units
    
    
    
    (77,515,915
    )
    
    
    (1,195,990
    )
    
    
    
    
    
    
    
    Balance at end of year
    
    
    
    11,518
    
    
    $
    174
    
    
    
    
    77,524,673
    
    
    $
    1,196,121
 Class B Trust Units:
 Years ended December 31
    
    
    2006
    
    
    
    2005Number
    
    
    
    
    
    
    
    NumberTrust units issued
    
    
    of trust units
    
    
    Amount
    
    
    
    of trust units
    
    
    AmountBalance at beginning of year
    
    
    
    82,301,443
    
    
    $
    1,318,294
    
    
    
    
    76,106,471
    
    
    $
    1,205,734Trust units converted to (from) Class B trust unit
    
    
    
    1,095
    
    
    
    17
    
    
    
    
    (9,824
    )
    
    
    (151
    )Issued for the Crispin acquisition (non-cash)
    
    
    
    
    
    
    
    
    
    
    
    
    3,538,581
    
    
    
    68,958Issued for cash on exercise of trust unit options and rights
    
    
    
    508,538
    
    
    
    7,897
    
    
    
    
    1,512,211
    
    
    
    21,818Issued for cash under DRIP
    
    
    
    563,348
    
    
    
    12,634
    
    
    
    
    1,154,004
    
    
    
    20,726Trust unit rights incentive plan (non-cash exercised)
    
    
    
    
    
    
    
    652
    
    
    
    
    
    
    
    
    1,209Trust units renamed to become consolidated trust units
    
    
    
    (83,374,424
    )
    
    
    (1,339,494
    )
    
    
    
    
    
    
    
    Balance at end of year
    
    
    
    
    
    
    $
    
    
    
    
    
    82,301,443
    
    
    $
    1,318,294
 112 | PENGROWTH 2006




---



##### 



Unclassified Trust Units:
 Years ended December 31
    
    
    2006
    
    
    
    2005Number
    
    
    
    
    
    
    
    NumberTrust units issued
    
    
    of trust units
    
    
    Amount
    
    
    
    of trust units
    
    
    AmountBalance at beginning of year
    
    
    
    37,967
    
    
    $
    582
    
    
    
    
    73,325
    
    
    $
    1,123Converted to Class A or Class B trust units
    
    
    
    (3,855
    )
    
    
    (60
    )
    
    
    
    (35,358
    )
    
    
    (541
    )Trust units converted to consolidated trust units
    
    
    
    (34,112
    )
    
    
    (522
    )
    
    
    
    
    
    
    
    Balance at end of year
    
    
    
    
    
    
    $
    
    
    
    
    
    37,967
    
    
    $
    582
 Class A Trust Unit and Class B Trust Unit Consolidation
  
    
    Effective as of 5:00 pm (Mountain Time) on June 27, 2006, the restrictions on the Class B
trust units that provided that the Class B trust units may only be held by residents of Canada
was eliminated.
 
    
    Effective as of 5:00 p.m. (Mountain Time) on July 27, 2006;
 
    
    the Class A trust units were delisted from the Toronto Stock Exchange (TSX) (effective as
of the close of markets);
    
    the Class B trust units were renamed as trust units to become the
consolidated trust units and the trading symbol of the consolidated trust units was
changed from PGF.B to PGF.UN;
    
    all of the issued and outstanding Class A trust units were
converted into consolidated trust units on the basis of one consolidated trust unit for
each whole Class A trust unit previously held (with the exception of Class A trust units held
by residents of Canada who provided a residency declaration to the Trustee);
    
    the
consolidated trust units were substitutionally listed in place of the Class A trust units
on the New York Stock Exchange under the symbol PGH; and
    
    the unclassified trust units were
converted into consolidated trust units on the basis of one consolidated trust unit for each
unclassified trust unit held.
  Redemption Rights
  PENGROWTH 2006 | 113




---



##### 



Distribution Reinvestment Plan
  Contributed Surplus
 2006
    
    
    
    2005Balance, beginning of year
    
    
    $
    3,646
    
    
    
    $
    1,923Trust unit rights incentive plan (non-cash expensed)
    
    
    
    1,298
    
    
    
    
    1,740Deferred entitlement trust units (non-cash expensed)
    
    
    
    1,248
    
    
    
    
    1,192Trust unit rights incentive plan (non-cash exercised)
    
    
    
    (1,028
    )
    
    
    
    (1,209
    )Deferred entitlement trust units (non-cash exercised)
    
    
    
    (233
    )
    
    
    
    Balance, end of year
    
    
    $
    4,931
    
    
    
    $
    3,646
    Deferred Entitlement Unit Plan
   114 | PENGROWTH 2006




---



##### 



2006
    
    
    2005Number
    
    
    Weighted value
    
    
    
    Number
    
    
    Weighted valueDEUs
    
    
    of DEUs
    
    
    average fair
    
    
    
    of DEUs
    
    
    average fairOutstanding at
beginning of year
    
    
    
    185,591
    
    
    $
    18.32
    
    
    
    
    
    
    
    $
    Granted
    
    
    
    222,088
    
    
    $
    22.28
    
    
    
    
    194,229
    
    
    $
    18.31Forfeited
    
    
    
    (33,981
    )
    
    $
    20.13
    
    
    
    
    (26,258
    )
    
    $
    18.16Exercised
    
    
    
    (14,207
    )
    
    $
    20.43
    
    
    
    
    
    
    
    $
    Deemed DRIP
    
    
    
    40,077
    
    
    $
    19.14
    
    
    
    
    17,620
    
    
    $
    18.19Outstanding at end of year
    
    
    
    399,568
    
    
    $
    20.55
    
    
    
    
    185,591
    
    
    $
    18.32
 Trust Unit Rights Incentive Plan
   2006
    
    
    2005Number
    
    
    Weighted average
    
    
    
    Number
    
    
    WeightedTrust Unit Rights
    
    
    of Rights
    
    
    exercise price
    
    
    
    of Rights
    
    
    exercise priceOutstanding at beginning
of year
    
    
    
    1,441,737
    
    
    $
    14.85
    
    
    
    
    2,011,451
    
    
    $
    14.23Granted (1)
    
    
    
    617,409
    
    
    $
    22.39
    
    
    
    
    606,575
    
    
    $
    18.34Exercised
    
    
    
    (452,468
    )
    
    $
    14.75
    
    
    
    
    (953,904
    )
    
    $
    12.81Forfeited
    
    
    
    (72,437
    )
    
    $
    17.47
    
    
    
    
    (222,385
    )
    
    $
    16.19Outstanding at year-end
    
    
    
    1,534,241
    
    
    $
    16.06
    
    
    
    
    1,441,737
    
    
    $
    14.85Exercisable at year-end
    
    
    
    969,402
    
    
    $
    14.22
    
    
    
    
    668,473
    
    
    $
    13.73
  (1)
    
    Weighted average exercise price of rights granted are based on the exercise price at the
date of grant. PENGROWTH 2006 | 115




---



##### 



Rights Outstanding
    
    
    
    
    
    Rights ExercisableWeighted averageremaining
    
    
    Weighted
    
    
    
    
    
    
    WeightedNumber
    
    
    contractual life
    
    
    average
    
    
    Number
    
    
    averageRange of Exercise Price
    
    outstanding
    
    
    (years)
    
    
    exercise price
    
    
    exercisable
    
    
    exercise price$7.00 to $8.99
    
    
    130,250
    
    
    
    0.9
    
    
    $
    7.18
    
    
    
    130,250
    
    
    $
    7.18$9.00 to $10.99
    
    
    2,100
    
    
    
    1.4
    
    
    $
    10.48
    
    
    
    2,100
    
    
    $
    10.48$11.00 to $12.99
    
    
    345,820
    
    
    
    2.1
    
    
    $
    12.22
    
    
    
    345,820
    
    
    $
    12.22$14.00 to $15.99
    
    
    378,075
    
    
    
    3.0
    
    
    $
    15.05
    
    
    
    246,317
    
    
    $
    15.16$16.00 to $18.99
    
    
    241,349
    
    
    
    4.4
    
    
    $
    17.93
    
    
    
    109,059
    
    
    $
    17.70$19.00 to $24.99
    
    
    436,647
    
    
    
    4.2
    
    
    $
    21.62
    
    
    
    135,856
    
    
    $
    21.64$7.00 to $24.99
    
    
    1,534,241
    
    
    
    3.2
    
    
    $
    16.06
    
    
    
    969,402
    
    
    $
    14.22
   Trust Unit Option Plan
   116 | PENGROWTH 2006




---



##### 



2006
    
    
    
    2005Number
    
    
    Weighted average
    
    
    
    Number
    
    
    Weighted averageTrust Unit Options
    
    
    of Options
    
    
    exercise price
    
    
    
    of Options
    
    
    exercise priceOutstanding at beginning of year
    
    
    
    259,317
    
    
    $
    17.28
    
    
    
    
    845,374
    
    
    $
    16.97Exercised
    
    
    
    (155,298
    )
    
    $
    18.03
    
    
    
    
    (558,307
    )
    
    $
    16.74Expired
    
    
    
    (5,400
    )
    
    $
    16.96
    
    
    
    
    (27,750
    )
    
    $
    18.63Outstanding and exercisable at year-end
    
    
    
    98,619
    
    
    $
    16.12
    
    
    
    
    259,317
    
    
    $
    17.28
  Options Outstanding and ExercisableWeighted averageRange of
    
    Number outstanding
    
    
    remaining contractual
    
    
    Weighted averageexercise prices
    
    and exercisable
    
    
    life (years)
    
    
    exercise price$12.00 to $14.99
    
    
    24,793
    
    
    
    2.0
    
    
    $
    13.12$15.00 to $16.99
    
    
    22,799
    
    
    
    1.8
    
    
    $
    15.00$17.00 to $17.99
    
    
    29,316
    
    
    
    1.3
    
    
    $
    17.47$18.00 to $20.50
    
    
    21,711
    
    
    
    0.9
    
    
    $
    18.90$12.00 to $20.50
    
    
    98,619
    
    
    
    1.5
    
    
    $
    16.12
 Trust Unit Award Plan
   Employee Savings Plans
  PENGROWTH 2006 | 117




---



##### 



Trust Unit Margin Purchase Plan
     2006
    
    
    
    2005Accumulated earnings
    
    
    $
    1,315,686
    
    
    
    $
    1,053,383Accumulated distributions paid or declared
    
    
    
    (2,655,093
    )
    
    
    
    (2,096,030
    )$
    (1,339,407
    )
    
    
    $
    (1,042,647
    )
  118 | PENGROWTH 2006




---



##### 



2006
    
    
    2005Unrealized foreign exchange loss (gain) on translation
of U.S. dollar denominated debt
    
    $
    480
    
    
    $
    (7,800
    )Realized foreign exchange (gain) loss
    
    
    (458
    )
    
    
    834$
    22
    
    
    $
    (6,966
    )
   Change in Non-Cash Operating Working Capital
 Cash provided by (used for):
    
    2006
    
    
    2005Accounts receivable
    
    $
    12,819
    
    
    $
    (21,072
    )Accounts payable and accrued liabilities
    
    
    (30,974
    )
    
    
    29,953Due to Pengrowth Management Limited
    
    
    (6,176
    )
    
    
    952$
    (24,331
    )
    
    $
    9,833
 Change in Non-Cash Investing Working Capital
 Cash provided by:
    
    
    2006
    
    
    
    2005Accounts payable for capital accruals
    
    
    $
    37,529
    
    
    
    $
    1,117
 Cash Payments
 2006
    
    
    
    2005Taxes
    
    
    $
    14
    
    
    
    $
    2,123Interest
    
    
    $
    32,183
    
    
    
    $
    21,779
   PENGROWTH 2006 | 119




---



##### 



2006
    
    
    
    2005Weighted average number of trust units  basic
    
    
    
    175,871
    
    
    
    
    157,127Dilutive effect of trust unit options, trust unit
rights and DEUs
    
    
    
    583
    
    
    
    
    787Weighted average number of trust units  diluted
    
    
    
    176,454
    
    
    
    
    157,914
   Interest Rate Risk
  Foreign Currency Exchange Risk
   Credit Risk
  120 | PENGROWTH
2006




---



##### 



Forward and Futures Contracts
   Crude Oil:
 Volume
    
    
    Reference
    
    PriceRemaining Term
    
    
    (bbl/d)
    
    
    Point
    
    per bblFinancial:Jan 1, 2007  Dec 31, 2007
    
    
    
    13,000
    
    
    WTI
    (1)
    
    $ 76.58 CdnJan 1, 2008  Oct 31, 2008
    
    
    
    1,000
    
    
    WTI
    (1)
    
    $ 74.25 CdnJan 1, 2008  Dec 31, 2008
    
    
    
    1,000
    
    
    WTI
    (1)
    
    $ 78.88 Cdn
 Natural Gas:
 Volume
    
    
    Reference
    
    
    PriceRemaining Term
    
    
    (mmbtu/d)
    
    
    Point
    
    
    per mmbtuFinancial:Jan 1, 2007  Oct 31, 2007
    
    
    
    5,000
    
    
    Transco Z6
    (1)
    
    $
    11.62
    CdnJan 1, 2007  Mar 31, 2007
    
    
    
    11,848
    
    
    AECO
    
    
    $
    9.63
    CdnApr 1, 2007  Oct 31, 2007
    
    
    
    9,478
    
    
    AECO
    
    
    $
    8.28
    CdnJan 1, 2007  Dec 31, 2007
    
    
    
    42,652
    
    
    AECO
    
    
    $
    7.97
    CdnJan 1, 2007  Oct 31, 2007
    
    
    
    5,000
    
    
    Chicago MI
    (1)
    
    $
    9.69
    CdnJan 1, 2007  Dec 31, 2007
    
    
    
    10,500
    
    
    Chicago MI
    (1)
    
    $
    8.89
    CdnJan 1, 2007  Oct 31, 2007
    
    
    
    4,739
    
    
    AECO
    
    
    $
    7.399.07
    Cdn(2)Jan 1, 2007  Mar 31, 2007
    
    
    
    4,739
    
    
    AECO
    
    
    $
    7.9110.81
    Cdn(2)
 (1)
    
    Associated Cdn$ / U.S.$ foreign exchange rate has been fixed.(2)
    
    Costless collars
  PENGROWTH
2006 | 121




---



##### 



Natural Gas Fixed Price Sales Contract:
  Volume
    
    
    PriceRemaining Term
    
    
    (mmbtu/d)
    
    
    per mmbtu (1)2007 to 2009:Jan 1, 2007  Oct 31, 2007
    
    
    
    3,886
    
    
    $2.29CdnNov 1, 2007  Oct 31, 2008
    
    
    
    3,886
    
    
    $2.34CdnNov 1, 2008  April 30, 2009
    
    
    
    3,886
    
    
    $2.40Cdn
 (1)
    
    Reference price based on AECO.
  2006Current gain on the fair value of commodity contracts
    
    
    $
    37,972Non-current gain on the fair value of commodity contracts
    
    
    
    495Non-current loss on the fair value of commodity contracts
    
    
    
    (1,367
    )37,100Fair value of commodity contracts recognized as part of Esprit Trust acquisition
    
    
    
    (10,601
    )Unrealized gain on fair value of commodity contracts
    
    
    $
    26,499
 Fair Value of Financial Instruments
  2006
    
    
    2005Years ended December 31
    
    Fair value
    
    
    Net book value
    
    
    Fair value
    
    
    Net book valueRemediation funds
    
    $
    11,162
    
    
    $
    11,144
    
    
    $
    9,071
    
    
    $
    8,329U.S. dollar denominated debt
    
    $
    224,624
    
    
    $
    233,080
    
    
    $
    220,187
    
    
    $
    232,600Pound Sterling denominated debt
    
    $
    109,692
    
    
    $
    114,120
    
    
    $
    101,257
    
    
    $
    100,489Convertible debentures
    
    $
    75,488
    
    
    $
    75,127
    
    
    $
    
    
    
    $
    
 122 | PENGROWTH
2006




---



##### 



2007
    
    
    2008
    
    
    2009
    
    
    2010
    
    
    2011
    
    
    Thereafter
    
    
    TotalOperating leases
    
    $
    7,350
    
    
    $
    7,387
    
    
    $
    6,494
    
    
    $
    6,019
    
    
    $
    5,790
    
    
    $
    35,923
    
    
    $
    68,963
 (1)
    
    Operating leases include office rent and vehicle leases.
      Crude Oil:
 Volume
    
    
    Reference
    
    
    PriceRemaining Term
    
    
    (bbl/d)
    
    
    Point
    
    
    per bblFinancial:Mar 1, 2007  Dec 31, 2007
    
    
    
    2,000
    
    
    WTI
    (1)
    
    $73.36
    CdnJan 1, 2008  Dec 31, 2008
    
    
    
    7,000
    
    
    WTI
    (1)
    
    $75.31
    Cdn
 PENGROWTH 2006 | 123




---



##### 



Natural Gas:
 Volume
    
    
    Reference
    
    
    PriceRemaining Term
    
    
    (mmbtu/d)
    
    
    Point
    
    
    per mmbtuFinancial:Feb 1, 2007  Dec 31, 2007
    
    
    
    7,500
    
    
    TETCO M3
    (1)
    
    $
    9.00
    CdnMar 1, 2007  Dec 31, 2007
    
    
    
    5,000
    
    
    TETCO M3
    (1)
    
    $
    9.08
    CdnFeb 1, 2007  Dec 31, 2007
    
    
    
    7,500
    
    
    NYMEX
    (1)
    
    $
    8.94
    CdnJan 1, 2008  Dec 31, 2008
    
    
    
    5,000
    
    
    Transco Z6
    (1)
    
    $
    10.90
    CdnMar 1, 2007  Dec 31, 2007
    
    
    
    4,740
    
    
    AECO
    
    
    $
    8.48
    CdnApr 1, 2007  Dec 31, 2007
    
    
    
    2,370
    
    
    AECO
    
    
    $
    7.02
    CdnNov 1, 2007  Dec 31, 2007
    
    
    
    2,370
    
    
    AECO
    
    
    $
    8.44
    CdnJan 1, 2008  Mar 31, 2008
    
    
    
    2,370
    
    
    AECO
    
    
    $
    8.44
    CdnJan 1, 2008  Dec 31, 2008
    
    
    
    42,653
    
    
    AECO
    
    
    $
    8.33
    CdnMar 1, 2007  Dec 31, 2007
    
    
    
    2,500
    
    
    Chicago MI
    (1)
    
    $
    8.21
    CdnJan 1, 2008  Dec 31, 2008
    
    
    
    5,000
    
    
    Chicago MI
    (1)
    
    $
    9.20
    Cdn
 (1)
    
    Associated Cdn$ / U.S.$ foreign exchange rate has been fixed.
 23.
    
    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, 2006, the application of the full cost ceiling test
under U.S. GAAP resulted in a write-down of capitalized costs of $114.2 million. The ceiling
test did not include the CP Properties discussed in Note 22. The application of the full cost
ceiling test under U.S. GAAP did not result in a write-down of capitalized costs at December
31, 2005.
  (b)
    
    Under U.S. GAAP, interest and other income would not be included as a component of
Net Revenue.(c)
    
    Statement of Financial Accounting Standards (SFAS) 130, Reporting Comprehensive
Income 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.
 124 | PENGROWTH 2006




---



##### 



(d)
    
    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.
     (e)
    
    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 consolidated trust units traded on the TSX for the ten trading
days after the trust units have been surrendered for redemption and the closing market price of the
consolidated trust units quoted on the TSX on the date the trust units have been surrendered for
redemption. The total amount of trust units that can be redeemed for cash is limited 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.(f)
    
    Under U.S. GAAP, an entity that is subject to income tax in multiple jurisdictions is
required to disclose income tax expense in each jurisdiction. Pengrowth is subject to tax at the
federal and provincial level. The portion of income tax expense (reduction) taxed at the federal
level for the year ended December 31, 2006 is ($9.4 million) (2005  $12.9 million). The portion of
income tax expense (reduction) taxed at the provincial level is ($4.9 million) (2005  $1.6
million).
 PENGROWTH 2006 | 125




---



##### 



(g)
    
    SFAS 123 (revised 2004) (SFAS 123(R)), Share-Based Payment deals with accounting for
transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R)
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 123(R) requires a public entity to measure the cost of
employee services received in exchange for an award of equity instruments based on the grant-date
fair value of the award (with limited exceptions). That cost will be recognized over the period
during which an employee is required to provide service in exchange for the award the requisite
service period. Since January 1, 2003, Pengrowth has recognized the costs of equity instruments
issued in exchange for employee services based on the grant-date fair value of the award, in
accordance with Canadian GAAP. Prior to adoption of SFAS 123(R) on January 1, 2006, forfeitures of
share-based payments were accounted for as they occurred, as permitted under Canadian GAAP. As of
January 1, 2006, forfeitures were estimated at the date of grant for both Canadian GAAP and U.S.
GAAP. The effect of the change of estimating forfeitures was not material.
    2006
    
    
    2005Number Exercised
    
    
    
    Intrinsic Value
    
    
    
    
    Number Exercised
    
    
    
    Intrinsic ValueDEUs
    
    
    
    14,523
    (1)
    
    $
    334
    
    
    
    
    
    
    
    $
    Trust Unit Options
    
    
    
    155,298
    
    
    
    827
    
    
    
    
    558,307
    
    
    
    1,611Trust Unit Rights
    
    
    
    452,468
    
    
    
    3,924
    
    
    
    
    953,904
    
    
    
    6,023Total
    
    
    
    622,289
    
    
    $
    5,085
    
    
    
    
    1,512,211
    
    
    $
    7,634
 (1)
    
    DEUs exercised relates to trust units issued under the plan for 2006
retirees as DEUs vest immediately upon retirement.  Trust Unit Options
    
    
    
    Trust Unit Rights
    
    
    
    DEUsNumber vested and expected to vest
    
    
    
    98,619
    
    
    
    1,521,207
    
    
    
    374,595Weighted average exercise price per unit (1)
    
    
    $
    16.12
    
    
    $
    16.04
    
    
    $
    Aggregate intrinsic value
    
    
    $
    377
    
    
    $
    5,936
    
    
    $
    7,469Weighted average remaining life (years)
    
    
    
    1.5
    
    
    
    3.2
    
    
    
    1.8
 (1)
    
    No proceeds on exercise price of DEUs, see Note 14 for details 126
| 2006 PENGROWTH




---



##### 



Trust Unit Options
    
    
    
    Trust Unit RightsNumber exercisable (1)
    
    
    
    98,619
    
    
    
    969,402Weighted average exercise price per unit
    
    
    $
    16.12
    
    
    $
    14.22Aggregate intrinsic value
    
    
    $
    377
    
    
    $
    5,542Weighted average remaining life (years)
    
    
    
    1.5
    
    
    
    3.2
 
 (1)
    
    No DEUs were exercisable at December 31, 2006. (h)
    
    Under US GAAP, the unrealized gain on crude oil and natural gas derivative contracts
of $26.5 million for the year ended December 31, 2006 would be combined with realized gains or
losses on crude oil and natural gas derivative contracts and recorded in oil and gas sales.(i)
    
    Under Canadian GAAP, the Trusts convertible debentures are classified as debt with a portion,
representing the estimated fair value of the conversion feature at the date of issue, being
allocated to equity. In addition, under Canadian GAAP a non-cash interest expense or income
representing the effective yield of the debt component is recorded in the consolidated statements
of income with a corresponding credit or debit to the convertible debenture liability balance to
accrete or amortize the balance to the principal due on maturity.Under U.S. GAAP, the convertible debentures, in their entirety, are classified as debt. The
non-cash interest expense recorded under Canadian GAAP would not be recorded under U.S. GAAP.(j)
    
    Under SFAS 141, Business Combinations, supplemental pro forma disclosure is required for
significant business combinations occurring during the year. On October 2, 2006, Pengrowth and
Esprit Trust completed a business combination. The consolidated financial statements include the
results of operations and cash flows of Esprit Trust and Esprit subsequent to October 2, 2006.
  (unaudited)
    
    
    
    2006 Pro Forma
    
    
    
    
    2005 Pro formaOil and gas sales
    
    
    $
    1,458,370
    
    
    
    $
    1,441,793Net income
    
    
    $
    182,661
    
    
    
    $
    355,573Net income per trust unit:Basic
    
    
    $
    0.90
    
    
    
    $
    1.85Diluted
    
    
    $
    0.89
    
    
    
    $
    1.85
 (k)
    
    Under U.S. GAAP, the amount shown as bank indebtedness of $14.6 million for the year ended
December 31, 2005 on the consolidated statement of cash flows would be shown as cash generated from
financing activities.(l)
    
    New Accounting Pronouncements
  PENGROWTH 2006 | 127




---



##### 



128 | PENGROWTH 2006




---



##### 



Consolidated Statements of Income
 
 Years ended December 31
    
    
    2006
    
    
    
    2005Net income, as reported
    
    
    $
    262,303
    
    
    
    $
    326,326Adjustments:Depletion and depreciation (a)
    
    
    
    23,997
    
    
    
    
    24,723Ceiling test write down under US GAAP (a)
    
    
    
    (114,212
    )
    
    
    
    Unrealized gain (loss) on ineffective portion
of oil and natural gas hedges (d)
    
    
    
    255
    
    
    
    
    (255
    )Unrealized loss on foreign exchange contract (d)
    
    
    
    
    
    
    
    
    (2,204
    )Reclassification of hedging losses on foreign
exchange swap from other comprehensive income (d)
    
    
    
    13,631
    
    
    
    
    Deferred foreign exchange loss (d)
    
    
    
    (13,631
    )
    
    
    
    Non-cash interest on convertible debentures (i)
    
    
    
    (29
    )
    
    
    
    Net income  U.S. GAAP
    
    
    $
    172,314
    
    
    
    $
    348,590Other comprehensive income (c):Unrealized gain on foreign exchange swap (d)
    
    
    
    16,077
    
    
    
    
    Unrealized hedging gain (loss) (d)
    
    
    
    18,153
    
    
    
    
    (25,470
    )Reclassification to net income (d)
    
    
    
    (13,631
    )
    
    
    
    Comprehensive income  U.S. GAAP
    
    
    $
    192,913
    
    
    
    $
    323,120Net income  U.S. GAAPBasic
    
    
    $
    0.98
    
    
    
    $
    2.22Diluted
    
    
    $
    0.98
    
    
    
    $
    2.21
 PENGROWTH 2006 | 129




---



##### 



Consolidated Balance Sheets
 
 IncreaseAs at December 31, 2006
    
    As Reported
    
    
    (Decrease)
    
    
    U.S. GAAPAssets:Current portion of unrealized foreign
exchange gain (d)
    
    $
    
    
    
    $
    1,559
    
    
    $
    1,559Other assets (d)
    
    
    29,097
    
    
    
    (1,317
    )
    
    
    27,780Capital assets (a)
    
    
    3,741,602
    
    
    
    (282,434
    )
    
    
    3,459,168$
    (282,192
    )LiabilitiesConvertible debentures (i)
    
    $
    75,127
    
    
    $
    189
    
    
    $
    75,316Unitholders equity (e):Accumulated other comprehensive income (c)(d)
    
    $
    
    
    
    $
    2,446
    
    
    $
    2,446Trust Unitholders Equity (a)
    
    
    3,049,677
    
    
    
    (284,827
    )
    
    
    2,764,850$
    (282,192
    )
 IncreaseAs at December 31, 2005
    
    As Reported
    
    
    (Decrease)
    
    
    U.S. GAAPAssets:Capital assets (a)
    
    $
    2,067,988
    
    
    $
    (192,219
    )
    
    $
    1,875,769$
    (192,219
    )LiabilitiesAccounts payable (d)
    
    $
    111,493
    
    
    $
    255
    
    
    $
    111,748Current portion of unrealized hedging loss (d)
    
    
    
    
    
    
    18,153
    
    
    
    18,153Current portion of unrealized foreign
currency contract (d)
    
    
    
    
    
    
    2,204
    
    
    
    2,204Unitholders equity (e):Accumulated other comprehensive income (c)(d)
    
    $
    
    
    
    $
    (18,153
    )
    
    $
    (18,153
    )Trust Unitholders Equity (a)
    
    
    1,475,996
    
    
    
    (194,678
    )
    
    
    1,281,318$
    (192,219
    )
 130 | PENGROWTH 2006




---



##### 



As at December 31,
    
    
    2006
    
    
    
    2005Trade
    
    
    $
    125,522
    
    
    
    $
    103,619Prepaids
    
    
    
    23,972
    
    
    
    
    20,230Other
    
    
    
    2,225
    
    
    
    
    3,545$
    151,719
    
    
    
    $
    127,394
  As at December 31,
    
    
    2006
    
    
    
    2005Accounts payable
    
    
    $
    73,631
    
    
    
    $
    50,756Accrued liabilities
    
    
    
    127,425
    
    
    
    
    60,737$
    201,056
    
    
    
    $
    111,493
 PENGROWTH 2006 | 131




---



##### 



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




---



##### 



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




---



##### 



RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
  (thousands of dollars)
    
    2006
    
    
    2005RevenueSales
    
    $
    988,238
    
    
    $
    952,738DeductProduction costs
    
    
    253,162
    
    
    
    208,140Transportation costs
    
    
    7,621
    
    
    
    7,891Amortization of injectant costs
    
    
    34,644
    
    
    
    24,393Technical support and other
    
    
    17,357
    
    
    
    9,975Depletion, depreciation and amortization
    
    
    327,578
    
    
    
    260,266Results of operations from producing activities
    
    $
    347,876
    
    
    $
    442,073
 
 1.
    
    The costs in this schedule exclude corporate overhead, interest expense and other operating
costs which are not directly related to producing activities.




---



##### 



COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
  2006
    
    
    2005(thousands of dollars)Property Acquisition CostsProved
    
    $
    1,333,666
    
    
    $
    208,424Unproved
    
    
    440,357
    
    
    
    18,697Development Costs
    
    
    284,605
    
    
    
    169,314Injectant Costs
    
    
    34,630
    
    
    
    34,658$
    2,093,258
    
    
    $
    431,093
      CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
  (thousands of dollars)
    
    2006
    
    
    2005Oil and gas properties
    
    $
    5,400,601
    
    
    $
    3,375,412Less accumulated depletion, depreciation and amortization
    
    
    (1,941,433
    )
    
    
    (1,499,643
    )Net capitalized costs
    
    $
    3,459,168
    
    
    $
    1,875,769
 (thousands of dollars)
    
    2006

    2005Unproven oil and gas properties
    
    $
    471,820
    
    
    $
    31,463Proven oil and gas properties
    
    
    2,987,348
    
    
    
    1,844,306Net capitalized costs
    
    $
    3,459,168
    
    
    $
    1,875,769




---



##### 



OIL AND GAS RESERVE INFORMATION
  Crude Oil and
    
    
    NaturalNatural Gas Liquids
    
    
    GasMMbbls
    
    
    BcfNET PROVED DEVELOPED AND UNDEVELOPED RESERVES AFTER ROYALTIESEnd 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
    
    
    
    333.5Revision of previous estimates
    
    
    5.5
    
    
    
    9.6Purchase of reserves in place
    
    
    18.2
    
    
    
    184.7Sales of reserves in place
    
    
    (0.4
    )
    
    
    (8.0
    )Discoveries and extensions
    
    
    0.8
    
    
    
    23.9Production
    
    
    (10.1
    )
    
    
    (51.8
    )End of year 2006
    
    
    102.2
    
    
    
    491.9NET PROVED DEVELOPED RESERVES AFTER ROYALTIESEnd of year 2004
    
    
    70.5
    
    
    
    305.7End of year 2005
    
    
    70.4
    
    
    
    309.3End of year 2006
    
    
    84.1
    
    
    
    453.1
 
 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.




---



##### 



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
  2006
    
    
    2005(millions of dollars)Future cash inflows
    
    $
    9,480
    
    
    $
    8,591Future costsFuture production and development costs
    
    
    (4,162
    )
    
    
    (2,892
    )Future net cash flows
    
    
    5,318
    
    
    
    5,699Deduct: 10% annual discount factor
    
    
    (2,152
    )
    
    
    (2,355
    )Standardized measure of discounted future net cash flows
    
    $
    3,166
    
    
    $
    3,344




---



##### 



CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL AND GAS
RESERVES
  2006
    
    
    2005 (1)(millions of dollars)Future discounted net cash flows at beginning of year
    
    $
    3,344
    
    
    $
    1,992Sales and transfer, net of production costs
    
    
    (676
    )
    
    
    (706
    )Net change in sales and transfer prices, net of production costs
    
    
    (637
    )
    
    
    1,450Development costs during the year
    
    
    284
    
    
    
    169Change in future development costs
    
    
    (355
    )
    
    
    (139
    )Changes due to extensions and discoveries
    
    
    83
    
    
    
    74Changes due to revisions (including infill drilling and improved recovery)
    
    
    129
    
    
    
    109Accretion of discount
    
    
    334
    
    
    
    199Sales of reserves in place
    
    
    (40
    )
    
    
    (26
    )Purchase of reserves in place
    
    
    842
    
    
    
    196Changes in timing of future net cash flows and other
    
    
    (142
    )
    
    
    26End of Year
    
    $
    3,166
    
    
    $
    3,344
 
 Note: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.




---



##### 



APPENDIX
E
 PENGROWTH ENERGY TRUST CODE OF BUSINESS CONDUCT AND ETHICS 
DATED DECEMBER 2006




---



##### 



December 2006




---



##### 



TABLE OF CONTENTS
 PageApplication
    
    
    1Purpose
    
    
    1Policy
    
    
    1Compliance with the Law
    
    
    2Health, Safety and the Environment
    
    
    2Public Reporting
    
    
    3Conflict of Interest
    
    
    3Private Business
    
    
    4Payments
    
    
    4Political Contributions
    
    
    5Involvement with Not-for-Profit Organizations
    
    
    6Outside Employment
    
    
    6Directorships
    
    
    6Government Relations
    
    
    6Confidential Information
    
    
    6Company Information
    
    
    7Inside Information
    
    
    7Books of Account
    
    
    8Patents and Inventions
    
    
    8Community Relations
    
    
    9Company Property and Opportunities
    
    
    9Accounting and Financial Reporting
    
    
    9Employee Relations and Reporting
    
    
    9Policies, Procedures and Internal Controls
    
    
    10Acknowledgement
    
    
    10Exceptions and Changes
    
    
    10Appendix A Complaint Procedures For Accounting, Financial Reporting and
Auditing Matters and Violations of the Code of Business Conduct and Ethics
    
    
    11Appendix B Awareness Statement on Code of Business Conduct and Ethics
    
    
    14




---



##### 



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




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##### 



Compliance with the Law
     Health, Safety and the Environment
    Page
2




---



##### 



Public Reporting
   
    
    all accounting records, and the reports produced from such records, must be in accordance with all applicable laws;
    
    all accounting records must fairly and accurately reflect the transactions or occurrences to which they relate;
    
    all accounting records must fairly and accurately reflect in reasonable detail Pengrowths assets, liabilities,
revenues and expenses;
    
    no accounting records should contain any false or intentionally misleading entries;
    
    no transactions should be intentionally misclassified as to accounts, departments or accounting periods;
    
    all transactions must be supported by accurate documentation in reasonable detail and recorded in the proper account
and in the proper accounting period;
    
    no information should be concealed from the internal auditors or the independent auditors; and
    
    compliance with Pengrowths system of internal controls is required.
 Conflict of Interest
  Page
3




---



##### 



Private Business
   Payments
   Page
4




---



##### 



Ø
    
    they are not in cash or securities and are of nominal value;Ø
    
    they do not contravene any law and are made as a matter of general and accepted
practice or in accordance with corporate policy; andØ
    
    if subsequently disclosed to the public, they would not in any way embarrass
Pengrowth or their recipients.
  Political Contributions
  (a)
    
    any such contribution may only be made to a political party and not to an
individual candidate for election to public office;(b)
    
    any such contribution requires the approval of the Chief Executive Officer; and(c)
    
    any such contribution must be within the approved operating budget of Pengrowth.
  Page 5




---



##### 



Involvement with Not-for-Profit Organizations
  Outside Employment
  Directorships
  Government Relations
  Confidential Information
   Page
6




---



##### 



Company Information
     Inside Information
    Page
7




---



##### 



If you have knowledge of a material fact, pending change of fact, or
material change related to the affairs of Pengrowth or any public
issuer involved in a transaction with Pengrowth which is not
generally known, no purchase or sale may be made until the knowledge
has been made public. In addition, this knowledge must not be
conveyed to any other person for the purpose of assisting that
person in trading securities.
  Policy on Trading in Securities by Directors, Officers and
Employees
 Books of Account
  Patents and Inventions
  Page 8




---



##### 



Community Relations
 Public Disclosure Policy,
Electronic Communications and Related Procedures
 Company Property and Opportunities
  Accounting and Financial Reporting
   Employee Relations and Reporting
    Page
9




---



##### 



Policies, Procedures and Internal Controls
  Acknowledgement
   personal
 Exceptions and Changes
   Page
10




---



##### 



Appendix A
 Complaint Procedures
 For Accounting, Financial Reporting and Auditing Matters
 and Violations of the Code of Business Conduct and Ethics
    Receipt of Complaints
 
    
    Directors, officers and employees with concerns regarding
Accounting Matters may report their concerns to the Chairman
of the Audit Committee.
    
    Directors, officers, employees, consultants or contractors
with concerns regarding Conduct Matter may report their
concerns to the Chairman of the Corporate Governance
Committee.
    
    Directors, officers and employees may report concerns
regarding Accounting Matters or Conduct Matters on a
confidential or anonymous basis to Grant Thornton LLP, at
1-888-747-7171 or usecare@GrantThornton.ca.
    
    A director, officer or employee who makes an anonymous
submission must be sure to provide sufficient detail to
identify the concern being raised. Because the submission is
made anonymously, the Audit Committee or the Corporate
Governance Committee, as the case may be, will be unable to
follow up if there are additional questions. The complaint
should, at a minimum, contain dates, places, persons involved
and witnesses such that a reasonable investigation or
assessment can be conducted.
 Scope of Accounting Matters Covered by These Procedures
  
    
    fraud or deliberate error in the preparation, evaluation, review or audit of any financial
 Page
11




---



##### 



statement of Pengrowth;
    
    fraud or deliberate error in the recording and maintaining of financial records of Pengrowth;
    
    deficiencies in or non-compliance with Pengrowths internal accounting controls;
    
    misrepresentation or false statement to or by a director, officer, employee or external accountant regarding a
matter contained in the financial records, financial reports or audit reports of Pengrowth; or
    
    deviation from full and fair reporting of Pengrowths financial condition.
 Treatment of Complaints
 
    
    Grant Thornton LLP shall inform (i) the
Chairman of the Audit Committee of all
complaints and concerns provided to it in
respect of Accounting Matters; and (ii) the
Chairman of the Corporate Governance
Committee of all complaints provided to it in
respect of Conduct Matters.
    
    Upon receipt of a complaint or concern, the
Chairman of the Audit Committee or Chairman
of the Corporate Governance Committee, as the
case may be, will (i) determine whether or
not the complaint actually pertains to
Accounting Matters or Conduct Matters and
(ii) when possible, acknowledge receipt of
the complaint to the sender.
    
    Complaints relating to Accounting Matters
will be reviewed by the Audit Committee,
outside legal counsel or such other persons
as the Audit Committee determines to be
appropriate. Complaints relating to Conduct
Matters will be reviewed by the Corporate
Governance Committee, outside legal counsel
and such and the persons as the Corporate
Governance Committee determines to be
appropriate. In any case, confidentiality
will be maintained to the fullest extent
possible, consistent with the need to conduct
an adequate review.
    
    Prompt and appropriate corrective action will
be taken when and as warranted in the
judgment of the Audit Committee or the
Corporate Governance Committee, as the case
may be.
    
    Pengrowth will not discharge, demote,
suspend, threaten, harass or in any manner
discriminate against any individual in the
terms and conditions of employment based upon
any lawful actions of such individual with
respect to reporting of complaints in good
faith regarding Accounting Matters or Conduct
Matters.
    
    Pengrowth will regard the making of any
deliberately false or malicious allegations
by an employee as a serious offence which may
result in recommendations to the Board or to
senior management of Pengrowth for
disciplinary action including dismissal for
cause and, if warranted, legal proceedings.
 Reporting and Retention of Complaints and Investigations
 
    
    The Chairman of the Audit Committee and the
Chairman of the Corporate Governance
Committee will maintain a log of all
complaints, tracking their receipt,
investigation and
 Page
12




---



##### 



resolution and shall
prepare a periodic summary report thereof for
the Audit Committee or the
Corporate Governance Committee, as the case may be.
  Page
13




---



##### 



Appendix B
 Awareness Statement on Code of Business Conduct and Ethics
 To be completed by all directors, officers, employees, consultants and contractors
 of Pengrowth Energy Trust and its subsidiaries (Pengrowth)
  1.
    
    I understand the content and consequences of contravening the Code and agree to abide by the
Code.2.
    
    I am in compliance with the Code.3.
    
    All facts and dealings which I believe to be non-compliant with the Code have been
communicated to the appropriate representative of Pengrowth and are detailed below.4.
    
    (If applicable) After due inquiry and to my best knowledge and belief, no employee,
consultant or contractor under my direct supervision is in violation of the Code.5.
    
    I have and will continue to exercise my best efforts to assure full compliance with the Code
by myself and (if applicable) all employees, consultants and contractors under my direct
supervision.
 Print or type name:Signature:Title and location:Date:
 Facts and dealings that I believe to be non-compliant with the Code
  1.2.
  Page
14