##### Table of Contents



UNITED STATES SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 
 Amendment No. 1 to:
 FORM 20-F
  o
    
    Registration statement pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934.orþ
    
    Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.For the fiscal year ended December 31, 2004.Oro
    
    Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.For the transition period from  too
    
    SHELL COMPANY REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Date of event reporting this shell
company reportIf this is an annual report,
indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Acts. Yes o  No o
 Commission file number 000-32115
 ENTERRA ENERGY TRUST
 (Exact Name of Registrant as Specified in Its Charter)
 Alberta, Canada  (Jurisdiction of Incorporation or Organization)
 Suite 2600, 500  4th Avenue S.W.
Calgary, Alberta, Canada
T2P 2V6  (Address of Principal Executive Offices)
  Title of Each Class
    
    Name of Each Exchange On Which RegisteredNone
    
    N/A
 Trust Units
 None
  Trust Units, without par value at December 31, 2004: 25,426,800
  þ o
  o þ




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ITEM 1. Identity of Directors, Senior Management and Advisors
    
    
    3ITEM 2. Offer Statistics and Expected Timetable
    
    
    3ITEM 3. Key Information
    
    
    3ITEM 4. Information on the Trust
    
    
    20ITEM 5. Operating and Financial Review and Prospects
    
    
    43ITEM 6. Directors, Senior Management and Employees
    
    
    66ITEM 7. Major Shareholders and Related Party Transactions
    
    
    74ITEM 8. Financial Information
    
    
    74ITEM 9. The Offer and Listing
    
    
    75ITEM 10. Additional information
    
    
    79ITEM 11. Qualitative and Quantitative Disclosures about Market Risk
    
    
    93ITEM 12. Description of Securities Other Than Equity Securities
    
    
    94ITEM 13. Defaults, Dividends Arrearages and Delinquencies
    
    
    95ITEM 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
    
    
    95ITEM 15. Controls and Procedures
    
    
    95ITEM 17. Financial Statements
    
    
    97ITEM 18. Financial Statements
    
    
    97ITEM 19. Exhibits
    
    
    98
 Certifications of CEO pursuant to Section 302Certification of CFO pursuant to Section 302Certification of CEO pursuant to Section 906Certification of CFO pursuant to Section 906Consent of KPMG LLPConsent from Deloitte & Touche LLPConsent of McDaniel & Associates Consultants Ltd.Certification of CEO pursuant to Section 302Certification of CFO pursuant to Section 302Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906Consent from KPMG LLPConsent from Deloitte Touche LLPConsent from McDaniel & Associates Consultants Ltd.
  2




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PART I
 
 ITEM 1. Identity of Directors, Senior Management and Advisors
  
 ITEM 2. Offer Statistics and Expected Timetable
  
 ITEM 3. Key Information
 A. Selected Financial Data
   3




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Consolidated statements of earnings data:
 (In thousands, except per unit data)Year Ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000C$
    
    
    C$
    
    
    C$
    
    
    C$
    
    
    C$Restated(2)
    
    
    Restated(1)(2)
    
    
    Restated(1)
    
    
    Restated(1)
    
    
    Restated(1)Amounts in accordance with Canadian GAAPRevenue
    
    $
    108,293
    
    
    $
    72,097
    
    
    $
    25,746
    
    
    $
    20,264
    
    
    $
    16,700Earnings before income taxes and non-controlling
interest
    
    $
    14,415
    
    
    $
    7,220
    
    
    $
    5,878
    
    
    $
    2,423
    
    
    $
    3,880Net earnings
    
    $
    14,027
    
    
    $
    5,430
    
    
    $
    4,881
    
    
    $
    1,700
    
    
    $
    2,256Basic earnings per unit/share
    
    $
    0.62
    
    
    $
    0.29
    
    
    $
    0.27
    
    
    $
    0.12
    
    
    $
    0.26Diluted earnings per unit/share
    
    $
    0.62
    
    
    $
    0.27
    
    
    $
    0.26
    
    
    $
    0.12
    
    
    $
    0.25Dividends paid on preferred shares  C$
    
    $
    
    
    
    $
    33
    
    
    $
    23
    
    
    $
    
    
    
    $
    Dividends paid on preferred shares  US$
    
    $
    
    
    
    $
    24
    
    
    $
    15
    
    
    $
    
    
    
    $
    Dividends paid on common shares
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Weighted average units/shares outstanding  basic
    
    
    22,518
    
    
    
    18,752
    
    
    
    18,309
    
    
    
    13,985
    
    
    
    8,844Amounts in accordance with US GAAP(2)Revenue
    
    $
    108,293
    
    
    $
    72,097
    
    
    $
    25,746
    
    
    $
    20,264
    
    
    $
    16,700Earnings before income taxes
    
    $
    7,906
    
    
    $
    12,835
    
    
    $
    2,909
    
    
    $
    3,228
    
    
    $
    4,175Net earnings (loss)
    (
    $
    179,632
    )
    (
    $
    218,914
    )
    
    $
    6,748
    
    (
    $
    15,535
    )
    
    $
    2,453Basic earnings (loss) per unit/share
    (
    $
    7.70
    )
    (
    $
    11.55
    )
    
    $
    0.37
    
    (
    $
    1.11
    )
    
    $
    0.53Diluted earnings (loss) per unit/share
    (
    $
    7.62
    )
    (
    $
    11.55
    )
    
    $
    0.36
    
    (
    $
    1.11
    )
    
    $
    0.52Dividends paid on preferred shares
    
    $
    
    
    
    $
    33
    
    
    $
    23
    
    
    $
    
    
    
    $
    Dividends paid on common shares
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
 4




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Consolidated balance sheet data:
 (In thousands)
    
    As at December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000C$
    
    
    C$
    
    
    C$
    
    
    C$
    
    
    C$Restated(2)
    
    
    Restated(1)(2)
    
    
    Restated(1)
    
    
    Restated(1)
    
    
    Restated(1)Amounts
in accordance with Canadian GAAPCash
    
    $
    4,779
    
    
    $
    66
    
    
    $
    108
    
    
    $
    43
    
    
    $
    1Accounts receivable and prepaid expenses
    
    $
    16,131
    
    
    $
    9,204
    
    
    $
    7,971
    
    
    $
    6,880
    
    
    $
    2,505Property and equipment
    
    $
    148,458
    
    
    $
    105,260
    
    
    $
    96,142
    
    
    $
    74,130
    
    
    $
    19,588Total assets
    
    $
    221,128
    
    
    $
    116,705
    
    
    $
    104,505
    
    
    $
    81,054
    
    
    $
    23,354Total Unitholders equity
    
    $
    114,971
    
    
    $
    44,545
    
    
    $
    38,417
    
    
    $
    33,410
    
    
    $
    7,173Amounts in accordance with US GAAP(2)Cash
    
    $
    4,779
    
    
    $
    66
    
    
    $
    108
    
    
    $
    43
    
    
    $
    1Accounts receivable and prepaid expenses
    
    $
    16,131
    
    
    $
    9,204
    
    
    $
    7,971
    
    
    $
    6,880
    
    
    $
    2,505Property and equipment
    
    $
    117,940
    
    
    $
    84,288
    
    
    $
    68,308
    
    
    $
    43,693
    
    
    $
    18,085Total assets
    
    $
    171,331
    
    
    $
    95,696
    
    
    $
    76,670
    
    
    $
    50,616
    
    
    $
    22,076Total Mezzanine equity
    
    $
    529,764
    
    
    $
    261,810
    
    
    $
    
    
    
    $
    
    
    
    $
    Total Unitholders equity
    
    $
    (449,727
    )
    
    $
    (227,813
    )
    
    $
    23,373
    
    
    $
    16,373
    
    
    $
    7,545
 
 (1)
    
Effective January 1, 2004, the Trust retroactively adopted CICA Handbook
Section 3110 Asset Retirement Obligations. The new recommendations
require the recognition of the fair value of obligations associated with the
retirement of long-lived assets to be recorded in the period the asset is put into use, with
a corresponding increase to the carrying amount of the related asset. The obligations
recognized are statutory, contractual or legal obligations. The liability is accreted over
time for changes in the fair value of the liability through charges to accretion expense,
which are included in depletion, depreciation, and accretion expense. The costs capitalized
to the related assets are amortized to earnings in a manner consistent with the depletion
and depreciation of the underlying asset.(2)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants issued
EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally
pursuant to this new standard, as certain exchangeable shares were issued by subsidiaries of
the Trust and initially recorded at book value all subsequent exchanges of these
exchangeable shares for trust units must be measured at the fair value of the trust units
issued. The excess amounts of the book value over fair market value are allocated to
property, plant and equipment, goodwill and future income tax. In addition, a portion of
consolidated earnings before non-controlling interest is reflected as a reduction to such
earnings in the Trusts consolidated statements of earnings and accumulated earnings. Prior
periods have been retroactively restated. The retroactive restatements were required by the
transitional provisions of the new accounting standard.(3)
    
    For further information on the US GAAP reconciliation, see ITEM 18 Financial
Statements  Note 18. 5




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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
    
    
    the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and
    
    market demand;
    
    risks and uncertainties involving geology of oil and gas deposits;
    
    the uncertainty of reserves estimates and reserves life;
    
    the uncertainty of estimates and projections relating to production, costs and expenses;
    
    potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
    
    fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;
    
    health, safety and environmental risks;
    
    uncertainties as to the availability and cost of financing; and
    
    the possibility that government policies or laws may change or governmental approvals may be delayed or withheld.
   6




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Exchange Rate Information
  U.S. Dollar/Canadian Dollar Exchange Rates for Five Most Recent Financial Years
 Year Ended December 31,
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000End of period
    
    
    0.8300
    
    
    
    0.7738
    
    
    
    0.6344
    
    
    
    0.6285
    
    
    
    0.6669Average for the period
    
    
    0.7683
    
    
    
    0.7139
    
    
    
    0.6372
    
    
    
    0.6456
    
    
    
    0.6732High during the period
    
    
    0.8502
    
    
    
    0.7738
    
    
    
    0.6656
    
    
    
    0.6714
    
    
    
    0.6969Low during the period
    
    
    0.7164
    
    
    
    0.6349
    
    
    
    0.6175
    
    
    
    0.6227
    
    
    
    0.6410
 U.S. Dollar/Canadian Dollar Exchange Rates for Previous Six Months
 May 2005
    
    June 2005
    
    July 2005
    
    August 2005
    
    September 2005
    
    October 2005High
    
    
    0.8086
    
    
    
    0.8173
    
    
    
    0.8317
    
    
    
    0.8449
    
    
    
    0.8630
    
    
    
    0.8599Low
    
    
    0.7853
    
    
    
    0.7943
    
    
    
    0.8024
    
    
    
    0.8168
    
    
    
    0.8378
    
    
    
    0.8387
 B. Capitalization and Indebtedness
  C. Reasons for the Offer and Use of Proceeds
  7




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D. Risk Factors
  Our results of operations and financial condition are dependent on the prices received for our oil
and natural gas production.
    An increase in operating costs or a decline in our production level could have a material adverse
effect on our results of operations and financial condition and, therefore, could reduce
distributions to Unitholders as well as affect the market price of the trust units.
   Distributions may be reduced during periods in which we make capital expenditures or debt
repayments using cash flow, which could also affect the market price of our trust units.
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A decline in our ability to market our oil and natural gas production could have a material adverse
effect on production levels or on the price that we received for our production, which in turn,
could reduce distributions to Unitholders as well as affect the market price of our trust units.
  Fluctuations in foreign currency exchange rates could adversely affect our business, and could
affect the market price of our trust units as well as distributions to Unitholders.
  If we are unable to acquire additional reserves, the value of our trust units and distributions to
Unitholders may decline.
  Actual reserves will vary from reserve estimates, and those variations could be material, and
affect the market price of our trust units and distributions to Unitholders.
   
    
    historical production in the area compared with production rates from similar producing areas;
    
    future commodity prices, production and development costs, royalties and capital expenditures;
    
    initial production rates;
 9




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
    
    production decline rates;
    
    ultimate recovery of reserves;
    
    success of future development activities;
    
    marketability of production;
    
    effects of government regulation; and
    
    other government levies that may be imposed over the producing life of reserves.
  As we expand our operations beyond oil and natural gas production in western Canada, we face new
challenges and risks.
   In determining the purchase price of acquisitions, we rely on both internal and external
assessments relating to estimates of reserves that may prove to be materially inaccurate. Such
reliance could adversely affect the market price of our trust units and distributions to
Unitholders.
  We do not operate some of our properties and, therefore, results of operations may be adversely
affected by the failure of third-party operators, which could affect the market price of our trust
units and distributions to Unitholders.
   Delays in business operations could adversely affect distributions to Unitholders and the market
price of our trust units.
 10




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
    
    restrictions imposed by lenders;
    
    accounting delays;
    
    delays in the sale or delivery of products;
    
    delays in the connection of wells to a gathering system;
    
    blowouts or other accidents;
    
    adjustments for prior periods;
    
    recovery by the operator of expenses incurred in the operation of the properties; or
    
    the establishment by the operator of reserves for these expenses.
  We may, from time to time, finance a significant portion of our operations through debt. Our
indebtedness may limit the timing or amount of the distributions that are paid to Unitholders, and
could affect the market price of our trust units.
   Our current credit facility and any replacement credit facility may not provide sufficient
liquidity.
  If we do not satisfy the conditions under the Kingsbridge Purchase Agreement, we will be unable to
draw down on the committed equity financing facility with Kingsbridge. The potential
unavailability of this facility might negatively affect our financing activities.
  11




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Each advance under the committed equity financing facility is limited. We may not draw down on the
committed equity financing facility when Kingsbridge beneficially owns in excess of 9.9% of our
outstanding Trust Units. The potential unavailability of this facility might negatively affect our
financing activities.
  There are a large number of Trust Units underlying the committed equity financing facility and
otherwise that are being registered in this report, and the sale or availability for sale of these
Trust Units may depress the price of our Trust Units.
  The sale of Trust Units underlying the committed equity financing facility could encourage short
sales by third parties, which could contribute to the future decline of our Trust Unit price.
  12




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We cannot predict the actual number of Trust Units that we will issue under the committed equity
financing facility, in any particular draw down, or in total or otherwise under this report. The
number of Trust Units we will issue under each draw down under the committed equity financing
facility will fluctuate based on the market price of Trust Units over the fifteen trading days
after we give a draw down notice for each draw down period.
    The committed equity financing facility imposes certain liquidated damages, which may impair our
liquidity and ability to raise capital.
  We have a working capital deficiency at December 31, 2004; our credit facilities can be called at
any time. Any material change in our liquidity could impair our ability to pay dividends and could
adversely affect the value of your investment.
  13




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Our assets are leveraged. Any material change in our liquidity could impair our ability to pay
dividends and could adversely affect the value of your investment.
  The oil and natural gas industry is highly competitive.
  The industry in which we operate exposes us to potential liabilities that may not be covered by
insurance.
  The operation of oil and natural gas wells could subject us to environmental claims and liability.
    Lower crude oil and natural gas prices increase the risk of ceiling limitation write-downs. Any
write-downs could materially affect the value of your investment.
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Unforeseen title defects may result in a loss of entitlement to production and reserves.
  Aboriginal Land Claims.
  Changes in tax and other laws may adversely affect Unitholders.
  15




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Income Tax Matters.
     There would be material adverse tax consequences if the Trust lost its status as a mutual fund
trust under Canadian tax laws.
  
    
    The Trust would be taxed on certain types of income distributed to
Unitholders. Payment of this tax may have adverse consequences for
some Unitholders, particularly Unitholders that are not residents of
Canada and residents of Canada that are otherwise exempt from Canadian
income tax.
 
    
    The Trust would cease to be eligible for the capital gains refund
mechanism available under Canadian tax laws if it ceased to be a
mutual fund trust.
 
    
    Trust units held by Unitholders that are not residents of Canada would
become taxable Canadian property. These non-resident holders would be
subject to Canadian income tax on any gains realized on a disposition
of trust units held by them.
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
    
    The trust units would not constitute qualified investments for
Registered Retirement Savings Plans, or RRSPs, Registered Retirement
Income Funds, or RRIFs, Registered Education Savings Plans, or
RESPs, or Deferred Profit Sharing Plans, or DPSPs. If, at the end
of any month, one of these exempt plans holds trust units that are not
qualified investments, the plan must pay a tax equal to 1% of the fair
market value of the trust units at the time the trust units were
acquired by the exempt plan. An RRSP or RRIF holding non-qualified
trust units would be subject to taxation on income attributable to the
trust units. If an RESP holds non-qualified trust units, it may have
its registration revoked by the CRA.
  Rights as a unitholder differ from those associated with other types of investments.
   Changes in market-based factors may adversely affect the trading price of our trust units.
  Our operations are entirely independent from the Unitholders and loss of key management and other
personnel could impact our business.
  There may be future dilution.
  There may not always be an active trading market for the trust units.
  17




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The limited liability of Unitholders is uncertain.
 Income Trusts Liability Act
 The redemption rights of Unitholders are limited.
  Taxation of Enterra.
   We may undertake acquisitions that could limit our ability to manage and maintain our business,
result in adverse accounting treatment and are difficult to integrate into our business. Any of
these events could result in a material change in our liquidity, impair our ability to pay
dividends and could adversely affect the value of your investment.
  
    
    diversion of managements attention;
 18




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
    
    inability to retain the management, key personnel and other employees of the acquired business;
 
    
    inability to establish uniform standards, controls, procedures and policies;
 
    
    inability to retain the acquired companys customers;
 
    
    exposure to legal claims for activities of the acquired business prior to acquisition; and inability to integrate the
acquired company and its employees into our organization effectively.
 Since we are a Canadian company and most of our assets and key personnel are located in Canada, you
may not be able to enforce a U.S. judgment for claims you may bring against us, our assets, our key
personnel or many of the experts named in this report. This may prevent you from receiving
compensation to which you would otherwise be entitled.
  19




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ITEM 4. Information on the Trust
 A. History and development of The Trust
      Enterra
  RMAC
  EUSA
   The Partnership
 20




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EEC Trust
  History
 Business Corporations Act
          21




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Canada Business Corporations Act Business Corporations Act Canada Business Corporations Act
            22




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23




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B. Business Overview
 th
 Distribution per Trust Unit(US$)December, 2003(1)
    
    $
    0.10January, 2004
    
    $
    0.10February, 2004
    
    $
    0.10March, 2004
    
    $
    0.11April, 2004
    
    $
    0.11May, 2004
    
    $
    0.11June, 2004
    
    $
    0.12July, 2004
    
    $
    0.12August, 2004
    
    $
    0.12September, 2004
    
    $
    0.13October, 2004
    
    $
    0.13November, 2004
    
    $
    0.13December, 2004
    
    $
    0.14January, 2005
    
    $
    0.14February, 2005
    
    $
    0.14March, 2005
    
    $
    0.15April, 2005
    
    $
    0.15May, 2005
    
    $
    0.15June, 2005
    
    $
    0.16July, 2005
    
    $
    0.16August, 2005
    
    $
    0.16September, 2005
    
    $
    0.17October, 2005
    
    $
    0.17
  
 (1)
    
    This distribution was the first cash distribution of the Trust following the completion of
the Arrangement.  24




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Business Strategy
  Revenues
  For the year ended December 31,($000s)
    
    2004
    
    
    2003
    
    
    2002Revenue
    
    $
    108,293
    
    
    $
    72,097
    
    
    $
    25,746
  Employees
  Office Facilities
 Competition
 Government Regulation in Canada
  25




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Pricing and Marketing  Oil and Natural Gas
  3
  Provincial Royalties and Incentives
     26




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Land Tenure
  Environmental Regulation
  Environmental
Protection and Enhancement Act
 27




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Additional Information Relating to the Trust
 Income Streams and Distribution Policy
  Risk Factors
  The Notes
  CT Note
  Trust Units
 Redemption Right Meetings of Unitholders Exercise of Voting Rights
    28




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Special Voting Rights
    Unitholder Limited Liability
 Risk Factors
  Redemption Right
   29




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Meetings of Unitholders
  30




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Voting Of EEC trust units
  Exercise of Voting Rights
  (a)
    
    any sale, lease or other disposition of, or any interest in, all or substantially all of the
assets owned, directly or indirectly, by the Trust, except in conjunction with an internal
reorganization of the direct or indirect assets of the Trust, as a result of which the Trust
has substantially the same interest, whether direct or indirect, in the assets as the
interest, whether direct or indirect, that it had prior to the reorganization;
 (b)
    
    any merger, amalgamation, arrangement, reorganization, recapitalization, business combination
or similar transaction involving the Trust and any other corporation, except in conjunction
with an internal reorganization as referred to in paragraph (a) above; or
 (c)
    
    the winding up, liquidation or dissolution of the Trust prior to the end of the term of the
Trust except in conjunction with an internal reorganization as referred to in paragraph (a)
above;
   (a)
    
    any sale, lease or other disposition of, or any interest in, all or substantially all of the
assets owned, directly or indirectly, by Enterra, the Trust or the Partnership, except in
conjunction with an internal reorganization
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(b)
    
    any merger, amalgamation, arrangement, reorganization, recapitalization, business combination
or similar transaction involving Enterra, EEC Trust or the Partnership and any other
corporation, except in conjunction with an internal reorganization as referred to in paragraph
(a) above;
 (c)
    
    the winding up, liquidation or dissolution of Enterra, EEC Trust or the Partnership prior to
the end of the term of EEC Trust, except in conjunction with an internal reorganization as
referred to in paragraph (a) above;
 (d)
    
    any amendment to the articles of Enterra to increase or decrease the minimum or maximum
number of directors;
 (e)
    
    any material amendments to the articles of Enterra to change the authorized share capital or
amend the rights, privileges, restrictions and conditions attaching to any class of Enterras
shares in a manner which may be prejudicial to EEC Trust; or
 (f)
    
    any material amendment to the CT Indenture or the Partnership Agreement which may be
prejudicial to EEC Trust;
   Trustee
   Delegation of Authority, Administration and Trust Governance
  32




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##### Table of Contents



Liability of The Trustee
  Amendments to The Trust Indenture
  (a)
    
    ensuring the Trusts continuing compliance with applicable laws or requirements of any
governmental agency or authority;
 (b)
    
    ensuring that the Trust will satisfy the provisions of each of subsections 108(2) and 132(6)
and paragraph 132(8)(a) of the Tax Act as from time to time amended or replaced;
 (c)
    
    providing for and ensuring (i) the allocation of items of income, gain, loss, deduction and
credit in respect of the Trust for United States federal income tax purposes; (ii) the filing
of income tax returns necessary or desirable for the purposes of United States federal income
tax; or (iii) compliance by the Trust with any other applicable provisions of United States
federal income tax law;
 (d)
    
    ensuring that such additional protection is provided for the interests of Unitholders as the
Trustee may consider expedient;
 (e)
    
    removing or curing any conflicts or inconsistencies between the provisions of the Trust
Indenture or any supplemental indenture and any other agreement of the Trust or any offering
document pursuant to which securities of the Trust are issued with respect to the Trust, or
any applicable law or regulation of any
jurisdiction, provided that in the opinion of the Trustee the rights of the Trustee and of
the Unitholders are not prejudiced thereby;
 (f)
    
    curing, correcting or rectifying any ambiguities, defective or inconsistent provisions,
errors, mistakes or omissions, provided that in the opinion of the Trustee the rights of the
Trustee and of the Unitholders are
 33




---



##### Table of Contents



(g)
    
    changing the situs of or the laws governing the Trust which, in the opinion of the Trustee,
is desirable in order to provide Unitholders with the benefit of any legislation limiting
their liability.
 Termination of the Trust
   Reporting to Unitholders
   34




---



##### Table of Contents



C. Organizational Structure
  
 35




---



##### Table of Contents



D. Property, plants and equipment
  
 Peace River Arch of Alberta, Canada
 Clair
   36




---



##### Table of Contents



Hines Creek
    Central Alberta, Canada
 Provost
    Princess/ Tide Lake
  37




---



##### Table of Contents



Sylvan Lake
   38




---



##### Table of Contents



Reserves Summary
     39




---



##### Table of Contents



Reserve Quantity Information
  2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Net
    
    
    Net
    
    
    Net
    
    
    Gross
    
    
    Gross
    
    
    GrossProved developed and undeveloped
reserves  Oil (boe)At January 1
    
    
    4,457
    
    
    
    4,193
    
    
    
    3,472
    
    
    
    5,149
    
    
    
    5,234
    
    
    
    4,127Changes in reserves:Extensions, discoveries and
other additions
    
    
    139
    
    
    
    1,962
    
    
    
    2,054
    
    
    
    158
    
    
    
    2,267
    
    
    
    2,564Revisions of previous estimates
    
    
    (96
    )
    
    
    (214
    )
    
    
    (195
    )
    
    
    65
    
    
    
    (458
    )
    
    
    (61
    )Production
    
    
    (1,672
    )
    
    
    (1,062
    )
    
    
    (446
    )
    
    
    (2,161
    )
    
    
    (1,406
    )
    
    
    (533
    )Purchases of oil in place
    
    
    2,363
    
    
    
    98
    
    
    
    
    
    
    
    2,684
    
    
    
    113Sales of oil in place
    
    
    (21
    )
    
    
    (520
    )
    
    
    (692
    )
    
    
    (24
    )
    
    
    (601
    )
    
    
    (863
    )At December 31
    
    
    5,170
    
    
    
    4,457
    
    
    
    4,193
    
    
    
    5,871
    
    
    
    5,149
    
    
    
    5,234Proved developed reserves  OilAt January 1
    
    
    4,457
    
    
    
    3,239
    
    
    
    3,131
    
    
    
    5,149
    
    
    
    3,952
    
    
    
    3,734At December 31
    
    
    5,069
    
    
    
    4,457
    
    
    
    3,239
    
    
    
    5,755
    
    
    
    5,149
    
    
    
    3,952
 2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Net
    
    
    Net
    
    
    Net
    
    
    Gross
    
    
    Gross
    
    
    GrossProved developed and undeveloped
reserves  Gas (boe)At January 1
    
    
    744
    
    
    
    1,706
    
    
    
    1,342
    
    
    
    1,018
    
    
    
    2,174
    
    
    
    1,794Changes in reserves:Extensions, discoveries and
other additions
    
    
    25
    
    
    
    462
    
    
    
    752
    
    
    
    28
    
    
    
    534
    
    
    
    939Revisions of previous estimates
    
    
    (167
    )
    
    
    (167
    )
    
    
    (70
    )
    
    
    (124
    )
    
    
    (183
    )
    
    
    (176
    )Production
    
    
    (322
    )
    
    
    (322
    )
    
    
    (263
    )
    
    
    (416
    )
    
    
    (427
    )
    
    
    (314
    )Purchases of gas in place
    
    
    637
    
    
    
    23
    
    
    
    
    
    
    
    723
    
    
    
    26Sales of gas in place
    
    
    
    
    
    
    (958
    )
    
    
    (55
    )
    
    
    
    
    
    
    (1,106
    )
    
    
    (69
    )At December 31
    
    
    917
    
    
    
    744
    
    
    
    1,706
    
    
    
    1,229
    
    
    
    1,018
    
    
    
    2,174Proved developed reserves  GasAt January 1
    
    
    744
    
    
    
    1,606
    
    
    
    1,233
    
    
    
    1,018
    
    
    
    2,038
    
    
    
    1,650At December 31
    
    
    909
    
    
    
    744
    
    
    
    1,606
    
    
    
    1,219
    
    
    
    1,018
    
    
    
    2,038
 
 40




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##### Table of Contents



Production
  Years ended December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000
    
    
    1999
    
    
    1998Oil and NGLs (mbbls)
    
    
    2,130
    
    
    
    1,409
    
    
    
    533
    
    
    
    582
    
    
    
    410
    
    
    
    93
    
    
    
    86Gas (mmcf)
    
    
    2,495
    
    
    
    2,545
    
    
    
    1,882
    
    
    
    680
    
    
    
    63
    
    
    
    61
    
    
    
    220Total (MBOE)
    
    
    2,550
    
    
    
    1,834
    
    
    
    847
    
    
    
    695
    
    
    
    421
    
    
    
    100
    
    
    
    108Average Production in BOED
    
    
    6,957
    
    
    
    5,024
    
    
    
    2,320
    
    
    
    1,906
    
    
    
    1,150
    
    
    
    274
    
    
    
    296
  BOEPD  MBOE   MBbls  MMcf  NGLs
 Oil and Gas Wells
  Oil Wells
    
    
    Gas Wells
    
    
    Non Producing
    
    
    Grand TotalGross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetCanada
    
    
    542
    
    
    
    337.0
    
    
    
    55
    
    
    
    33.2
    
    
    
    202
    
    
    
    169.5
    
    
    
    799
    
    
    
    539.7US
    
    
    2
    
    
    
    0.5
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    0.5Total
    
    
    544
    
    
    
    337.5
    
    
    
    55
    
    
    
    33.2
    
    
    
    202
    
    
    
    169.5
    
    
    
    801
    
    
    
    540.2
 Average Sales Prices
 Year ended December 31,
    
    2004
    
    
    2003
    
    
    2002Oil  per barrel
    
    $
    43.30
    
    
    $
    39.12
    
    
    $
    33.86Natural Gas  per MCF
    
    $
    6.69
    
    
    $
    6.65
    
    
    $
    4.08
 Average Production Costs
 Year ended December 31,
    
    2004
    
    
    2003
    
    
    2002Per BOE
    
    $
    9.23
    
    
    $
    6.96
    
    
    $
    7.11
 41




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##### Table of Contents



Land Holdings
  Canada
    
    
    United States
    
    
    TotalGross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetDeveloped acres
    
    
    66,265
    
    
    
    43,795
    
    
    
    520
    
    
    
    123
    
    
    
    66,785
    
    
    
    43,918Undeveloped acres
    
    
    69,611
    
    
    
    49,054
    
    
    
    32,765
    
    
    
    12,278
    
    
    
    102,376
    
    
    
    61,332Total acres
    
    
    135,876
    
    
    
    92,849
    
    
    
    33,285
    
    
    
    12,401
    
    
    
    169,161
    
    
    
    105,250
  Drilling Activity
  2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Wells drilled
    
    Gross (Net)
    
    
    Gross (Net)
    
    
    Gross (Net)
    
    
    Gross (Net)
    
    
    Gross (Net)Oil
    
    
    23 (6.4
    )
    
    
    31 (31.0
    )
    
    
    25 (23.7
    )
    
    
    9   (5.0
    )
    
    
    9   (8.3
    )Natural Gas
    
    
    3 (0.7
    )
    
    
    3   (1.1
    )
    
    
    37 (34.0
    )
    
    
    8   (3.8
    )
    
    
    2   (1.3
    )Injection and water disposal
    
    
    2 (0.3
    )
    
    
    6   (6.0
    )
    
    
    0   (0.0
    )
    
    
    0   (0.0
    )
    
    
    0   (0.0
    )Abandoned
    
    
    3 (2.3
    )
    
    
    7   (6.4
    )
    
    
    0   (0.0
    )
    
    
    3   (1.8
    )
    
    
    2   (1.1
    )Total
    
    
    31 (9.7
    )
    
    
    47 (44.5
    )
    
    
    62 (57.7
    )
    
    
    20 (10.6
    )
    
    
    13 (10.7
    )
     Present Activities
  Q1 2005Wells drilled
    
    Gross (Net)Oil
    
    
    8 (1.0
    )Natural Gas
    
    
    4 (0.7
    )Injection and water disposal
    
    
    0 (0.0
    )Abandoned
    
    
    2 (0.4
    )Total
    
    
    14 (1.1
    )
 Delivery Commitments
  42




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##### Table of Contents



ITEM 5. Operating and Financial Review and Prospects
 Overview
  5.A Operating Results
 Comparison of the Year Ended December 31, 2004 to the Year Ended December 31, 2003
 Critical Accounting Policies
  (i)
    
    Capitalized costs under the full cost method are depleted and depreciated using the
unit-of-production method, based on estimated proved oil and gas reserves as determined by
independent engineers. To economically evaluate the Trusts proved oil and natural gas
reserves, these independent engineers must necessarily make a number of assumptions, estimates
and judgments that they believe to be reasonable based upon their expertise and NI 51-101
guidelines. Were the independent engineers to use differing assumptions, estimates and
judgments, then the Trusts consolidated financial condition and results of operations would
be affected. For example, the Trust would have lower net earnings (or net losses) in the
event the revised assumptions, estimates and judgments resulted in lower reserve estimates,
since our depletion and depreciation rate would then be higher and it might also result in a
write-down under the ceiling test. Similarly, the Trust would have higher net earnings in the
event the revised assumptions, estimates and judgments resulted in higher reserve estimates.(ii)
    
    The Trusts management also periodically assesses the carrying values of unproved properties
to ascertain whether any impairment in value has occurred. This assessment typically includes
a review of sales of similar properties to determine a fair market value. These properties
would be moved to the cost pool and depleted if this assessment indicates the fair market
value is less than the capitalized costs. Were the Trusts management to use differing
assumptions, estimates and judgments, then the Trusts consolidated financial condition and
results of operations would be affected.
 Production Revenue
   43




---



##### Table of Contents



SUMMARIZED FINANCIAL AND OPERATIONAL DATA
 (in Thousands except for volumes and
    
    Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Yearper unit amounts)
    
    2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeRestated(1)
    
    
    Restated(1)
    
    
    
    
    
    
    Restated(1)
    
    
    Restated(1)Exit production rate (boe per day)
    
    
    7,258
    
    
    
    6,460
    
    
    
    12
    %
    
    
    7,258
    
    
    
    6,460
    
    
    
    12
    %Production revenue
    
    $
    33,593
    
    
    $
    15,598
    
    
    
    115
    %
    
    $
    108,293
    
    
    $
    72,097
    
    
    
    50
    %Average production volumes (boe per day)
    
    
    7,925
    
    
    
    5,206
    
    
    
    52
    %
    
    
    6,957
    
    
    
    5,024
    
    
    
    38
    %Cash provided (used) by
operating activities (2)
    
    $
    14,192
    
    
    $
    (966
    )
    
    
    1,569
    %
    
    $
    42,345
    
    
    $
    20,971
    
    
    
    102
    %Net earnings (loss)
    
    $
    3,256
    
    
    $
    (4,754
    )
    
    
    168
    %
    
    $
    14,027
    
    
    $
    5,430
    
    
    
    158
    %Net earnings (loss) per unit
    
    $
    0.13
    
    
    $
    (0.25
    )
    
    
    152
    %
    
    $
    0.62
    
    
    $
    0.29
    
    
    
    114
    %Average number of units outstanding
    
    
    25,277
    
    
    
    18,956
    
    
    
    33
    %
    
    
    22,518
    
    
    
    18,787
    
    
    
    20
    %Average price per bbl of oil
    
    $
    46.90
    
    
    $
    31.79
    
    
    
    48
    %
    
    $
    43.00
    
    
    $
    39.12
    
    
    
    10
    %Average price per mcf of natural gas
    
    $
    6.87
    
    
    $
    5.91
    
    
    
    16
    %
    
    $
    6.69
    
    
    $
    6.65
    
    
    
    1
    %Production expenses per boe
    
    $
    10.98
    
    
    $
    6.19
    
    
    
    77
    %
    
    $
    9.23
    
    
    $
    6.96
    
    
    
    33
    %General and administrative expenses per
boe (cash portion)
    
    $
    2.61
    
    
    $
    2.18
    
    
    
    20
    %
    
    $
    1.71
    
    
    $
    1.69
    
    
    
    -1
    %
 
 (1)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants
issued EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally pursuant
to this new standard, as certain exchangeable shares were issued by subsidiaries of the Trust and
initially recorded at book value all subsequent exchanges of these exchangeable shares for trust
units must be measured at the fair value of the trust units issued. The excess amounts of the book
value over fair market value are allocated to property, plant and equipment, goodwill and future
income tax. In addition, a portion of consolidated earnings before non-controlling interest is
reflected as a reduction to such earnings in the Trusts consolidated statements of earnings and
accumulated earnings. Prior periods have been retroactively restated. The retroactive
restatements were required by the transitional provisions of the new
accounting standard.(2)
    
    The Trust had previously reported the Non-GAAP measure Cash flow from operations,
rather than the GAAP-based measure of Cash provided (used) by operating activities.   44




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##### Table of Contents



3 YEAR SUMMARY
 SUMMARIZED FINANCIAL AND OPERATIONAL DATA(in Thousands
    
    Year
    
    
    Year
    
    
    Yearexcept for volumes and per unit amounts)
    
    2004
    
    
    2003
    
    
    2002Restated(1)
    
    
    Restated(1)Revenue
    
    $
    108,293
    
    
    $
    72,097
    
    
    $
    25,746Cash provided by operating activities (2)
    
    $
    42,345
    
    
    $
    20,971
    
    
    $
    22,474Net earnings
    
    $
    14,027
    
    
    $
    5,430
    
    
    $
    4,881Net earnings per unit  basic
    
    $
    0.62
    
    
    $
    0.29
    
    
    $
    0.27Net earnings per unit  diluted
    
    $
    0.62
    
    
    $
    0.27
    
    
    $
    0.26Average number of units outstanding
    
    
    22,518
    
    
    
    18,752
    
    
    
    18,309Total assets
    
    $
    221,128
    
    
    $
    116,705
    
    
    $
    104,505Total bank debt and obligations under capital leases
    
    $
    47,315
    
    
    $
    38,129
    
    
    $
    29,358Distribution per unit
    
    US$
    1.42
    
    
    US$
    0.10
    
    
    
    N/A
 
 (1)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants
issued EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally pursuant
to this new standard, as certain exchangeable shares were issued by subsidiaries of the Trust and
initially recorded at book value all subsequent exchanges of these exchangeable shares for trust
units must be measured at the fair value of the trust units issued. The excess amounts of the book
value over fair market value are allocated to property, plant and equipment, goodwill and future
income tax. In addition, a portion of consolidated earnings before non-controlling interest is
reflected as a reduction to such earnings in the Trusts consolidated statements of earnings and
accumulated earnings. Prior periods have been retroactively restated. The retroactive
restatements were required by the transitional provisions of the new accounting standard.(2)
    
The Trust had previously reported the Non-GAAP measure cash flow from
operations, rather than the GAAP-based measure of cash provided by operating activities. 45




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##### Table of Contents



PRODUCTION REVENUE (in Thousands except for volumes and pricing)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeCrude oil and natural gas liquids
    
    $
    29,196
    
    
    $
    12,022
    
    
    
    143
    %
    
    $
    91,611
    
    
    $
    55,185
    
    
    
    66
    %Natural gas
    
    
    4,397
    
    
    
    3,576
    
    
    
    23
    %
    
    
    16,682
    
    
    
    16,912
    
    
    
    -1
    %Total production income
    
    $
    33,593
    
    
    $
    15,598
    
    
    
    115
    %
    
    $
    108,293
    
    
    $
    72,097
    
    
    
    50
    %VolumesAverage oil production (in bbls/day)
    
    
    6,766
    
    
    
    4,110
    
    
    
    65
    %
    
    
    5,821
    
    
    
    3,862
    
    
    
    51
    %Average gas production (in mcf/day)
    
    
    6,954
    
    
    
    6,572
    
    
    
    6
    %
    
    
    6,817
    
    
    
    6,972
    
    
    
    -2
    %Average total production (in boe/day)
    
    
    7,925
    
    
    
    5,206
    
    
    
    52
    %
    
    
    6,957
    
    
    
    5,024
    
    
    
    38
    %Exit oil production (in bbls/day)
    
    
    5,905
    
    
    
    4,890
    
    
    
    21
    %
    
    
    5,905
    
    
    
    4,890
    
    
    
    21
    %Exit gas production (in mcf/day)
    
    
    8,118
    
    
    
    9,420
    
    
    
    -14
    %
    
    
    8,118
    
    
    
    9,420
    
    
    
    -14
    %Exit total production (in boe/day)
    
    
    7,258
    
    
    
    6,460
    
    
    
    12
    %
    
    
    7,258
    
    
    
    6,460
    
    
    
    12
    %Commodity Pricing BenchmarksWest Texas Intermediate (US$/bbl)
    
    $
    48.28
    
    
    $
    31.18
    
    
    
    55
    %
    
    $
    41.40
    
    
    $
    31.10
    
    
    
    33
    %Exchange rate (US$)
    
    $
    0.80
    
    
    $
    0.76
    
    
    
    5
    %
    
    $
    0.77
    
    
    $
    0.72
    
    
    
    7
    %Edmonton Par ($/bbl)
    
    $
    57.71
    
    
    $
    39.85
    
    
    
    45
    %
    
    $
    52.55
    
    
    $
    43.39
    
    
    
    21
    %NYMEX (US$/mmbtu)
    
    $
    6.87
    
    
    $
    5.44
    
    
    
    26
    %
    
    $
    6.09
    
    
    $
    5.49
    
    
    
    11
    %Alberta Spot ($/mcf)
    
    $
    7.09
    
    
    $
    5.69
    
    
    
    24
    %
    
    $
    6.79
    
    
    $
    6.50
    
    
    
    4
    %Commodity Prices received by EnterraAverage price received per bbl of oil
    
    $
    49.90
    
    
    $
    31.78
    
    
    
    48
    %
    
    $
    43.00
    
    
    $
    39.12
    
    
    
    10
    %Average price received per mcf of natural gas
    
    $
    6.87
    
    
    $
    5.91
    
    
    
    16
    %
    
    $
    6.69
    
    
    $
    6.65
    
    
    
    1
    %
 Production Expenses
  PRODUCTION EXPENSES (in Thousands except for percentages and per boe amounts)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeProduction expenses
    
    $
    8,007
    
    
    $
    2,967
    
    
    
    170
    %
    
    $
    23,492
    
    
    $
    12,763
    
    
    
    84
    %As a percentage of production revenue
    
    
    24
    %
    
    
    19
    %
    
    
    25
    %
    
    
    22
    %
    
    
    18
    %
    
    
    22
    %Production expenses per boe
    
    $
    10.98
    
    
    $
    6.19
    
    
    
    77
    %
    
    $
    9.23
    
    
    $
    6.96
    
    
    
    33
    %
 46




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##### Table of Contents



Royalties
  ROYALTIES (in Thousands except for percentages and boe amounts)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeRoyalties
    
    $
    7,958
    
    
    $
    3,916
    
    
    
    103
    %
    
    $
    24,527
    
    
    $
    17,656
    
    
    
    39
    %As a percentage of production revenue
    
    
    24
    %
    
    
    25
    %
    
    
    -4
    %
    
    
    23
    %
    
    
    24
    %
    
    
    -4
    %Royalties per boe
    
    $
    10.91
    
    
    $
    8.18
    
    
    
    33
    %
    
    $
    9.63
    
    
    $
    9.63
    
    
    
    0
    %
 General and Administrative Expenses
  GENERAL AND ADMINISTRATIVE EXPENSES (in Thousands except for percentages and per boe amounts)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeGeneral and administrative expenses  cash portion
    
    $
    1,906
    
    
    $
    1,042
    
    
    
    83
    %
    
    $
    4,362
    
    
    $
    3,104
    
    
    
    41
    %General and administrative expenses  non-cash
portion
    
    $
    (606
    )
    
    
    
    
    
    
    
    
    
    $
    78
    
    
    $
    281
    
    
    
    -72
    %As a percentage of production revenue (cash portion)
    
    
    6
    %
    
    
    7
    %
    
    
    -15
    %
    
    
    4
    %
    
    
    4
    %
    
    
    -6
    %General and administrative expenses per boe (cash
portion)
    
    $
    2.61
    
    
    $
    2.18
    
    
    
    +20
    %
    
    $
    1.71
    
    
    $
    1.69
    
    
    
    1
    %
 Interest Expense
  INTEREST EXPENSE (in Thousands except for percentages and per boe amounts)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeLong-term debt, including bank debt
at end of period
    
    $
    47,316
    
    
    $
    38,128
    
    
    
    24
    %
    
    $
    47,315
    
    
    $
    38,129
    
    
    
    24
    %Interest expense
    
    $
    491
    
    
    $
    410
    
    
    
    20
    %
    
    $
    2,222
    
    
    $
    1,749
    
    
    
    27
    %As a percentage of production revenue
    
    
    2
    %
    
    
    3
    %
    
    
    33
    %
    
    
    2
    %
    
    
    2
    %
    
    
    0
    %Interest expense per boe
    
    $
    0.67
    
    
    $
    0.86
    
    
    
    -21
    %
    
    $
    0.87
    
    
    $
    0.95
    
    
    
    -8
    %
 47




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##### Table of Contents



Depletion and Depreciation
  DEPLETION AND DEPRECIATION EXPENSE (in Thousands except for percentages and per boe amounts)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeRestated(1)
    
    
    Restated(1)
    
    
    
    
    
    
    Restated(1)
    
    
    Restated(1)Depletion and depreciation expense
    
    $
    11,794
    
    
    $
    6,210
    
    
    
    90
    %
    
    $
    35,976
    
    
    $
    23,306
    
    
    
    54
    %As a percentage of production revenue
    
    
    35
    %
    
    
    40
    %
    
    
    -13
    %
    
    
    33
    %
    
    
    33
    %
    
    
    0
    %Depletion and depreciation expense per boe
    
    $
    16.18
    
    
    $
    12.97
    
    
    
    25
    %
    
    $
    14.13
    
    
    $
    12.71
    
    
    
    11
    %
 
 (1)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants
issued EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally pursuant
to this new standard, as certain exchangeable shares were issued by subsidiaries of the Trust and
initially recorded at book value all subsequent exchanges of these exchangeable shares for trust
units must be measured at the fair value of the trust units issued. The excess amounts of the book
value over fair market value are allocated to property, plant and equipment, goodwill and future
income tax. In addition, a portion of consolidated earnings before non-controlling interest is
reflected as a reduction to such earnings in the Trusts consolidated statements of earnings and
accumulated earnings. Prior periods have been retroactively restated. The retroactive
restatements were required by the transitional provisions of the new accounting standard. Income and Capital Taxes
     TAX POOLS (in Thousands except for percentages)
 YearEstimated tax pools at December 31
    
    2004Canadian oil and gas property expense (COGPE)
    
    $
    22,901Canadian exploration expense (CEE)
    
    
    4,688Canadian development expense (CDE)
    
    
    36,312Undepreciated capital cost (UCC)
    
    
    29,234Non-capital losses
    
    
    32,235Other
    
    
    1,444$
    126,814
 48




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##### Table of Contents



Earnings
  EARNINGS (in Thousands except for per unit amounts)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeRestated(1)
    
    
    Restated(1)
    
    
    
    
    
    
    Restated(1)
    
    
    Restated(1)Earnings (loss) before income taxes and
non-controlling interest
    
    $
    3,103
    
    
    $
    (4,710
    )
    
    
    166
    %
    
    $
    14,415
    
    
    $
    7,220
    
    
    
    100
    %Add (deduct) income taxes
    
    
    226
    
    
    $
    (377
    )
    
    
    160
    %
    
    $
    20
    
    
    $
    (2,122
    )
    
    
    -100
    %Add (deduct) non-controlling interest
    
    
    (73
    )
    
    
    332
    
    
    
    -121
    %
    
    
    (408
    )
    
    
    332
    
    
    
    -223
    %Net earnings (loss)
    
    $
    3,256
    
    
    $
    (4,755
    )
    
    
    168
    %
    
    $
    14,027
    
    
    $
    5,430
    
    
    
    158
    %Net Earnings (loss) as a percentage of revenue
    
    
    10
    %
    
    
    30
    %
    
    
    133
    %
    
    
    13
    %
    
    
    8
    %
    
    
    63
    %Net Earnings (loss) on a per boe basis
    
    $
    4.47
    
    
    $
    (9.92
    )
    
    
    147
    %
    
    $
    5.04
    
    
    $
    2.95
    
    
    
    71
    %Per unit informationNet earnings (loss) per unit
    
    $
    0.13
    
    
    $
    (0.25
    )
    
    
    152
    %
    
    $
    0.62
    
    
    $
    0.29
    
    
    
    137
    %Average number of units outstanding
    
    
    25,277
    
    
    
    18,956
    
    
    
    33
    %
    
    
    22,518
    
    
    
    18,752
    
    
    
    20
    %
 
 (1)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants
issued EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally pursuant
to this new standard, as certain exchangeable shares were issued by subsidiaries of the Trust and
initially recorded at book value all subsequent exchanges of these exchangeable shares for trust
units must be measured at the fair value of the trust units issued. The excess amounts of the book
value over fair market value are allocated to property, plant and equipment, goodwill and future
income tax. In addition, a portion of consolidated earnings before non-controlling interest is
reflected as a reduction to such earnings in the Trusts consolidated statements of earnings and
accumulated earnings. Prior periods have been retroactively restated. The retroactive
restatements were required by the transitional provisions of the new accounting standard. Cash Provided By Operating Activities
  49




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##### Table of Contents



CASH PROVIDED BY OPERATING ACTIVITIES (in Thousands except for per unit amounts)
 Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeRestated(1)
    
    
    Restated(1)
    
    
    
    
    
    
    Restated(1)
    
    
    Restated(1)Net earnings (loss)
    
    $
    3,256
    
    
    $
    (4,755
    )
    
    
    168
    %
    
    $
    14,027
    
    
    $
    5,430
    
    
    
    158
    %Add back depletion and depreciation
    
    
    11,794
    
    
    
    6,210
    
    
    
    90
    %
    
    
    35,976
    
    
    
    23,306
    
    
    
    54
    %Add back (deduct) amortization of
deferred financing charges
    
    
    (18
    )
    
    
    (27
    )
    
    
    33
    %
    
    
    33
    
    
    
    262
    
    
    
    -87
    %Add (deduct) Non controlling interest
    
    
    73
    
    
    
    (332
    )
    
    
    (122
    )
    
    
    408
    
    
    
    (332
    )
    
    
    -223
    %Add back (deduct) future income taxes
    
    
    (396
    )
    
    
    331
    
    
    
    -203
    %
    
    
    (280
    )
    
    
    1,988
    
    
    
    -114
    %Deduct amortization of deferred gain
    
    
    
    
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    (238
    )
    
    
    -100
    %Asset Retirement Expenditures
    
    
    
    
    
    
    (5
    )
    
    
    
    
    
    
    
    
    
    
    (5
    )
    
    
    
    %Add back (deduct) non-cash expense
related to warrants/ options
    
    
    (606
    )
    
    
    282
    
    
    
    -315
    %
    
    
    78
    
    
    
    282
    
    
    
    -72
    %Change in accounts receivable
    
    
    (2,137
    )
    
    
    (146
    )
    
    
    -1,364
    %
    
    
    (4,393
    )
    
    
    (1,429
    )
    
    
    -207
    %Change in prepaid expenses
    
    
    (134
    )
    
    
    23
    
    
    
    -683
    %
    
    
    (57
    )
    
    
    195
    
    
    
    -129
    %Change in accounts payable and
accrued liabilities
    
    
    2,190
    
    
    
    (2,431
    )
    
    
    190
    %
    
    
    (3,607
    )
    
    
    (8,453
    )
    
    
    57
    %Change of income taxes payable
    
    
    170
    
    
    
    (115
    )
    
    
    248
    %
    
    
    160
    
    
    
    (35
    )
    
    
    557
    %Cash provided by operating activities
    
    $
    14,192
    
    
    $
    (966
    )
    
    
    1,569
    %
    
    $
    42,345
    
    
    $
    20,971
    
    
    
    102
    %Cash provided by operating activities
as a percentage of revenue
    
    
    42
    %
    
    
    -6
    %
    
    
    800
    %
    
    
    39
    %
    
    
    29
    %
    
    
    34
    %
 
 (1)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants
issued EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally pursuant
to this new standard, as certain exchangeable shares were issued by subsidiaries of the Trust and
initially recorded at book value all subsequent exchanges of these exchangeable shares for trust
units must be measured at the fair value of the trust units issued. The excess amounts of the book
value over fair market value are allocated to property, plant and equipment, goodwill and future
income tax. In addition, a portion of consolidated earnings before non-controlling interest is
reflected as a reduction to such earnings in the Trusts consolidated statements of earnings and
accumulated earnings. Prior periods have been retroactively restated. The retroactive
restatements were required by the transitional provisions of the new accounting standard. Capital Expenditures
  CAPITAL EXPENDITURES
 Year
    
    
    Year(In Thousands except for percentages)
    
    2004
    
    
    2003
    
    
    ChangeProperty acquisitions
    
    $
    30,385
    
    
    $
    8,539
    
    
    
    256
    %Proceeds on disposal of properties
    
    
    (1,177
    )
    
    
    (18,263
    )
    
    
    -94
    %Drilling (exploration and development)
    
    
    11,001
    
    
    
    28,390
    
    
    
    -61
    %Facilities and equipment
    
    
    24,475
    
    
    
    14,368
    
    
    
    70
    %Other
    
    
    555
    
    
    
    280
    
    
    
    98
    %Net additions before ARO
    
    $
    65,239
    
    
    $
    33,314
    
    
    
    96
    %
 50




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##### Table of Contents



Cash Distributions
    51




---



##### Table of Contents



NEW ACCOUNTING PRONOUNCEMENTS
 Canadian Pronouncements
  Full Cost Accounting
  Asset Retirement Obligations
  Unit-based Compensation
  Variable Interest Entities (VIEs)
  Change in Accounting Policy
 52




---



##### Table of Contents



(a) Non-controlling interest (NCI)
     53




---



##### Table of Contents



Balance Sheet as at
    
    Balance asDecember 31, 2004
    
    reported prior to
    
    
    Adjustments
    
    
    Balance asNCI restatement
    
    
    for NCI
    
    
    restatedProperty, plant and equipment
    
    $
    146,910
    
    
    $
    1,548
    
    
    $
    148,458Goodwill
    
    
    29,991
    
    
    
    19,279
    
    
    
    49,270Future income tax liability
    
    
    21,526
    
    
    
    602
    
    
    
    22,128Non-controlling interest
    
    
    
    
    
    
    3,349
    
    
    
    3,349Unitholders capital
    
    
    111,653
    
    
    
    20,554
    
    
    
    132,207Exchangeable shares
    
    
    3,276
    
    
    
    (3,276
    )
    
    
    Accumulated earnings
    
    
    27,903
    
    
    
    (405
    )
    
    
    27,498Basic weighted average
number of units outstanding
    
    
    23,327,728
    
    
    
    (809,355
    )
    
    
    22,518,373Diluted weighted average
number of units outstanding
    
    
    23,560,785
    
    
    
    (318,825
    )
    
    
    23,241,960
 Balance Sheet as at
    
    Balance asDecember 31, 2003
    
    reported prior to
    
    
    Adjustments
    
    
    Balance asNCI restatement
    
    
    for NCI
    
    
    restatedProperty, plant and equipment
    
    $
    105,253
    
    
    $
    7
    
    
    $
    105,260Goodwill
    
    
    
    
    
    
    37
    
    
    
    37Future income tax liability
    
    
    13,936
    
    
    
    3
    
    
    
    13,939Non-controlling interest
    
    
    
    
    
    
    3,125
    
    
    
    3,125Unitholders capital
    
    
    32,838
    
    
    
    41
    
    
    
    32,879Exchangeable shares
    
    
    3,457
    
    
    
    (3,457
    )
    
    
    Accumulated earnings
    
    
    13,785
    
    
    
    332
    
    
    
    14,117Basic weighted average
number of units outstanding
    
    
    18,953,968
    
    
    
    (202,334
    )
    
    
    18,751,634Diluted weighted average
number of units outstanding
    
    
    18,953,968
    
    
    
    (40
    )
    
    
    18,953,928
 Statement of Earnings for the year ended
    
    Balance asDecember 31, 2004
    
    reported prior to
    
    
    Adjustments
    
    
    Balance asNCI restatement
    
    
    for NCI
    
    
    restatedDepletion, depreciation and accretion
    
    $
    35,438
    
    
    $
    538
    
    
    $
    35,976Future income tax recovery
    
    
    (71
    )
    
    
    (209
    )
    
    
    (280
    )Net earnings before non-controlling
interest
    
    
    14,764
    
    
    
    (329
    )
    
    
    14,435Non-controlling interest
    
    
    
    
    
    
    408
    
    
    
    408Net earnings
    
    
    14,764
    
    
    
    (737
    )
    
    
    14,027Net earnings per unit  basic
    
    $
    0.63
    
    (
    $
    0.01
    )
    
    $
    0.62Net earnings per unit  diluted
    
    $
    0.63
    
    (
    $
    0.01
    )
    
    $
    0.62
 54




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##### Table of Contents



Statement of Earnings for the year endedDecember 31, 2003
    
    Balance as
    
    
    Adjustmentsreported prior to
    
    
    for NCI for
    
    
    Balance asNCI restatement
    
    
    NCI
    
    
    restatedNon-controlling interest
    
    $
    
    
    (
    $
    332
    )
    (
    $
    332
    )Net earnings
    
    
    5.098
    
    
    
    (332
    )
    
    
    5,430Net earnings per unit  basic
    
    $
    0.27
    
    
    $
    0.02
    
    
    $
    0.29Net earnings per unit  diluted
    
    $
    0.27
    
    
    $
    0.00
    
    
    $
    0.27
 .
 U.S. Pronouncements
  (a)
    
    In December 2004, FASB issued statement 123R Share Based Payments that establishes
the standards for the accounting for transactions in which an entity exchanges its equity
for goods or services. The statement focused primarily on the accounting for transactions
in which an entity obtains employee services in exchange for share-based consideration.
The statement establishes a standard to account for such transactions using a
fair-value-based method. The effective date for implementation of this standard would be
the first interim or annual period beginning on or after December 15, 2005 for transactions
entered into on or after the effective date. Management has not yet assessed the impact of
this standard on our results of operations or financial position.(b)
    
    In December 2004, SFAS issued statement No. 153 Exchanges of Non-monetary Assets  an
amendment of APB Opinion No. 29. The statement eliminates the exception for non-monetary
exchanges of similar productive assets and replaces it with a general exception for
exchanges of non-monetary exchanges that do not have commercial substance. A non-monetary
exchange is defined as having commercial substance if the future cash flows of the entity
are expected to change significantly as a result of the exchange. This statement is
effective for non-monetary transactions in fiscal periods that begin after June 15, 2005.
Management does not expect the adoption of this statement to have any material impact on
our results of operations or financial position.
  55




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Comparison of the Year Ended December 31, 2003 to the Year Ended December 31, 2002
 Overview
  Summarized financial and operational data (in Thousands except for volumes and per unit amounts)
 2003
    
    
    2002
    
    
    ChangeExit production rate (boe per day)
    
    
    6,460
    
    
    
    5,335
    
    
    
    + 21
    %Average production revenue
    
    $
    72,097
    
    
    $
    25,746
    
    
    
    +180
    %Average production volumes (boe per day)
    
    
    5,024
    
    
    
    2,320
    
    
    
    +117
    %Cash provided by operating activities
    
    $
    20,971
    
    
    $
    22,474
    
    
    
    -  7
    %Average number of units outstanding (after giving effect
to trust conversion)
    
    
    18,752
    
    
    
    18,309
    
    
    
    +  2
    %Average price per bbl of oil
    
    $
    39.12
    
    
    $
    33.86
    
    
    
    + 16
    %Average price per mcf of natural gas
    
    $
    6.65
    
    
    $
    4.08
    
    
    
    + 63
    %Operating costs per boe
    
    $
    6.96
    
    
    $
    7.11
    
    
    
    -  2
    %General and administrative expenses per boe (cash portion)
    
    $
    1.69
    
    
    $
    1.99
    
    
    
    - 15
    %
 56




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##### Table of Contents



2 YEAR SUMMARY
 Summarized financial and operational data (in Thousands except for per unit amounts)
 2003
    
    
    2002Restated(2)Revenue
    
    $
    72,097
    
    
    $
    25,746Net earnings
    
    $
    5,430
    
    
    $
    4,881Net earnings per unit  basic
    
    $
    0.29
    
    
    $
    0.27Net earnings per unit  diluted
    
    $
    0.27
    
    
    $
    0.26Average number of units outstanding (after giving effect to trust conversion)
    
    
    18,752
    
    
    
    18,309Total assets
    
    $
    116,705
    
    
    $
    104,505Total long-term debt (including bank debt and capital leases)
    
    $
    38,129
    
    
    $
    29,358Distribution per unit (1)
    
    US$
    0.10
    
    
    
    N/A
 (1)
    
    Only one distribution for the month of December 2003, paid on January 15, 2004 for US$0.10 per unit.(2)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants issued EIC-151 Exchangeable Securities Issued by
Subsidiaries of Income Trusts. In accordance with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively reclassified to
non-controlling interest on the consolidated balance sheets. Additionally pursuant to this new standard, as certain exchangeable shares were issued by subsidiaries
of the Trust and initially recorded at book value all subsequent exchanges of these exchangeable shares for trust units must be measured at the fair value of the
trust units issued. The excess amounts of the book value over fair market value are allocated to property, plant and equipment, goodwill and future income tax. In
addition, a portion of consolidated earnings before non-controlling interest is reflected as a reduction to such earnings in the Trusts consolidated statements of
earnings and accumulated earnings. Prior periods have been retroactively restated. The retroactive restatements were required by the transitional provisions of
the new accounting standard.
 57




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##### Table of Contents



PRODUCTION REVENUE
    Production revenue (in Thousands except for volumes and pricing)
 2003
    
    
    2002
    
    
    ChangeCrude oil and natural gas liquids
    
    $
    55,185
    
    
    $
    18,075
    
    
    
    +205
    %Natural gas
    
    
    16,912
    
    
    
    7,671
    
    
    
    +120
    %Total production income
    
    $
    72,097
    
    
    $
    25,746
    
    
    
    +180
    %VolumesAverage oil production (in bbls/day)
    
    
    3,862
    
    
    
    1,460
    
    
    
    +164
    %Average gas production (in mcf/day)
    
    
    6,972
    
    
    
    5,157
    
    
    
    +35
    %Average total production (in boe/day)
    
    
    5,024
    
    
    
    2,320
    
    
    
    +117
    %Exit oil production (in bbls/day)
    
    
    4,890
    
    
    
    4,205
    
    
    
    +16
    %Exit gas production (in mcf/day)
    
    
    9,420
    
    
    
    6,780
    
    
    
    +39
    %Exit total production (in boe/day)
    
    
    6,460
    
    
    
    5,335
    
    
    
    +21
    %Commodity Pricing BenchmarksWest Texas Intermediate (US$/bbl)
    
    
    31.10
    
    
    
    26.13
    
    
    
    +19
    %Exchange rate (US$)
    
    
    0.72
    
    
    
    0.64
    
    
    
    +12
    %Edmonton Par ($/bbl)
    
    
    43.39
    
    
    
    40.20
    
    
    
    + 8
    %NYMEX (US$/mmbtu)
    
    
    5.49
    
    
    
    3.36
    
    
    
    +63
    %Alberta Spot ($/mcf)
    
    
    6.50
    
    
    
    3.96
    
    
    
    +64
    %Commodity Prices received by EnterraAverage price received per bbl of oil
    
    
    39.12
    
    
    
    33.86
    
    
    
    +16
    %Average price received per mcf of natural gas
    
    
    6.65
    
    
    
    4.08
    
    
    
    +63
    %
 PRODUCTION EXPENSES
  Production expenses (in Thousands except for percentages and per boe amounts)
 2003
    
    
    2002
    
    
    ChangeProduction expenses
    
    $
    12,763
    
    
    $
    6,018
    
    
    
    +112
    %As a percentage of production revenue
    
    
    18
    %
    
    
    23
    %
    
    
    -22
    %Production expenses per boe
    
    $
    6.96
    
    
    $
    7.11
    
    
    
    -2
    %
 58




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##### Table of Contents



ROYALTIES
  Royalties (in Thousands except for percentages and per boe amounts)
 2003
    
    
    2002
    
    
    ChangeRoyalties
    
    $
    17,656
    
    
    $
    4,203
    
    
    
    +320
    %As a percentage of production revenue
    
    
    24
    %
    
    
    16
    %
    
    
    +50
    %Royalties per boe
    
    $
    9.63
    
    
    $
    4.96
    
    
    
    +94
    %
 GENERAL AND ADMINISTRATIVE EXPENSES
  General and administrative expenses (in Thousands except for percentages and per boe amounts)
 2003
    
    
    2002
    
    
    ChangeGeneral and administrative expenses  cash portion
    
    $
    3,104
    
    
    $
    1,683
    
    
    
    +84
    %General and administrative expenses  non-cash portion
    
    $
    281
    
    
    
    As a percentage of production revenue (cash portion)
    
    
    4
    %
    
    
    7
    %
    
    
    -43
    %General and administrative expenses per boe (cash
portion)
    
    $
    1.69
    
    
    $
    1.99
    
    
    
    -15
    %
 INTEREST EXPENSE
  Interest expense (in Thousands except for percentages and per boe amounts)
 2003
    
    
    2002
    
    
    ChangeLong-term debt, including bank debt at end of period
    
    $
    38,128
    
    
    $
    29,358
    
    
    
    +30
    %Interest expense
    
    $
    1,749
    
    
    $
    1,236
    
    
    
    +42
    %As a percentage of production revenue
    
    
    2
    %
    
    
    5
    %
    
    
    -60
    %Interest expense per boe
    
    $
    0.95
    
    
    $
    1.46
    
    
    
    -35
    %
 59




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##### Table of Contents



DEPLETION AND DEPRECIATION
  Depletion and depreciation (in Thousands except for percentages and per boe amounts)
 2003
    
    
    2002
    
    
    ChangeDepletion and depreciation expense
    
    $
    23,306
    
    
    $
    9,449
    
    
    
    +146
    %As a percentage of production revenue
    
    
    32
    %
    
    
    36
    %
    
    
    -11
    %Depletion and depreciation expense per boe
    
    $
    12.71
    
    
    $
    10.99
    
    
    
    +16
    %
 INCOME AND CAPITAL TAXES
  Income and capital taxes in Thousands except for percentages)
 2003
    
    
    2002
    
    
    ChangeIncome tax expense
    
    $
    2,122
    
    
    $
    997
    
    
    
    +113
    %Combined federal and provincial income tax rate
    
    
    40.75
    %
    
    
    42.12
    %
    
    
    -3
    %Actual tax rate as a percentage of earnings
before income taxes and non-controlling
interest
    
    
    29.39
    %
    
    
    16.96
    %
    
    
    +72
    %Estimated tax pools at December 31Canadian oil and gas property expense (COGPE)
    
    $
    13,911
    
    
    $
    20,148Canadian exploration expense (CEE)
    
    $
    8,832
    
    
    $
    9,870Canadian development expense (CDE)
    
    $
    43,463
    
    
    $
    4,708Undepreciated capital cost (UCC)
    
    $
    31,308
    
    
    $
    27,109Other
    
    $
    2,906
    
    
    $
    2,331Total
    
    $
    100,420
    
    
    $
    64,166
    
    
    
    +56
    %
 60




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##### Table of Contents



EARNINGS
  Earnings (in Thousands except for per unit amounts)
 2003
    
    
    2002
    
    
    ChangeRestated(1)Earnings (loss) before income taxes
    
    $
    7,220
    
    
    $
    5,878
    
    
    
    +23
    %Deduct income taxes
    
    
    (2,122
    )
    
    
    (997
    )Add Non-controlling interest
    
    
    332
    
    
    
    Net earnings (loss)
    
    $
    5,430
    
    
    $
    4,881
    
    
    
    +11
    %Per unit informationPer unit information
Net earnings (loss) per unit
    
    $
    0.29
    
    
    $
    0.27
    
    
    
    7
    %Average number of units outstanding
    
    
    18,752
    
    
    
    18,309
    
    
    
    +2
    %
 1)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants
issued EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally pursuant
to this new standard, as certain exchangeable shares were issued by subsidiaries of the Trust and
initially recorded at book value all subsequent exchanges of these exchangeable shares for trust
units must be measured at the fair value of the trust units issued. The excess amounts of the book
value over fair market value are allocated to property, plant and equipment, goodwill and future
income tax. In addition, a portion of consolidated earnings before non-controlling interest is
reflected as a reduction to such earnings in the Trusts consolidated statements of earnings and
accumulated earnings. Prior periods have been retroactively restated. The retroactive
restatements were required by the transitional provisions of the new accounting standard.
 61




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##### Table of Contents



CASH PROVIDED BY OPERATING ACTIVITIES
   Cash provided by operating activities (in Thousands except for per unit amounts)
 2003
    
    
    2002
    
    
    ChangeRestated(1)Net earnings
    
    $
    5,430
    
    
    $
    4,881
    
    
    
    +11
    %Add back depletion and depreciation
    
    
    23,306
    
    
    
    9,449Add back (deduct) amortization of deferred financing charges
    
    
    262
    
    
    
    391Add back future income taxes
    
    
    1,988
    
    
    
    865Add back non-cash expense related to value of warrants
    
    
    282
    
    
    
    Deduct asset retirement expenditures
    
    
    (5
    )
    
    
    (49
    )Deduct amortization of deferred gain
    
    
    (238
    )
    
    
    (524
    )Deduct gain on redemption of preferred shares
    
    
    
    
    
    
    (3,111
    )Deduct non-controlling interest
    
    
    (332
    )
    
    
    Change in accounts receivable
    
    
    (1,429
    )
    
    
    (1,017
    )Change in prepaid expenses
    
    
    195
    
    
    
    (74
    )Change in accounts payable and accrued liabilities
    
    
    (8,453
    )
    
    
    11,672Change in income taxes payable
    
    
    (35
    )
    
    
    (8
    )Cash provided by operating activities
    
    
    20,971
    
    
    
    22,474
    
    
    
    -7
    %Cash provided by operating activities as a percentage of revenue
    
    
    29
    %
    
    
    87
    %
    
    
    -67
    %
 (1)
    
    On January 19, 2005, the Canadian Institute of Chartered Accountants
issued EIC-151 Exchangeable Securities Issued by Subsidiaries of Income Trusts. In accordance
with this new Canadian GAAP standard the Trusts exchangeable shares have been retroactively
reclassified to non-controlling interest on the consolidated balance sheets. Additionally pursuant
to this new standard, as certain exchangeable shares were issued by subsidiaries of the Trust and
initially recorded at book value all subsequent exchanges of these exchangeable shares for trust
units must be measured at the fair value of the trust units issued. The excess amounts of the book
value over fair market value are allocated to property, plant and equipment, goodwill and future
income tax. In addition, a portion of consolidated earnings before non-controlling interest is
reflected as a reduction to such earnings in the Trusts consolidated statements of earnings and
accumulated earnings. Prior periods have been retroactively restated. The retroactive
restatements were required by the transitional provisions of the new accounting standard.
 CAPITAL EXPENDITURES
  62




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##### Table of Contents



Capital expenditures (in Thousands except for percentages)
 2003
    
    
    2002
    
    
    ChangeProperty acquisitions
    
    $
    8,539
    
    
    $
    4,829Proceeds on disposal of properties
    
    
    (18,263
    )
    
    
    (5,810
    )Drilling (exploration and development)
    
    
    28,390
    
    
    
    21,519Facilities and equipment
    
    
    14,368
    
    
    
    9,347Other
    
    
    280
    
    
    
    235Total
    
    $
    33,314
    
    
    $
    30,120
    
    
    
    +11
    %
 CASH DISTRIBUTIONS
 th
    5 B. Liquidity and Capital Resources
        63




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##### Table of Contents



HEDGING SUMMARY
 Description
    
    Quantity
    
    PricingContracts Settled in 2004Oil contracts from January 1/2003 to June 30/2004
    
    500 bbls of oil/day
    
    US$26.75 per barrelOil contracts from January 1/2003 to June 30/2004
    
    500 bbls of oil/day
    
    US$26.68 per barrelOil contracts from January 1/2003 to June 30/2004
    
    1,000 bbls of oil/day
    
    C$38.50 per barrelOil contracts from July 1/2004 to December 31/2004
    
    500 bbls of oil/day
    
    C$40.50 per barrel
         64




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##### Table of Contents



5.C Research and development, patents and licenses, etc.
  5.D Trend information
    5.E Off balance sheet arrangements
  5.F Tabular disclosure of contractual obligations
  2005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    2010Minimum capital lease
payments
    
    $
    1,065,620
    
    
    $
    1,065,620
    
    
    $
    1,799,215
    
    
    $
    
    
    
    $
    
    
    
    $
    Rental payments  office
space
    
    
    795,963
    
    
    
    740,610
    
    
    
    640,332
    
    
    
    661,259
    
    
    
    662,130
    
    
    
    27,572$
    1,861,583
    
    
    $
    1,806,230
    
    
    $
    2,439,547
    
    
    $
    661,259
    
    
    $
    662,130
    
    
    $
    27,572
 65




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##### Table of Contents



ITEM 6. Directors, Senior Management and Employees
 A. Directors and senior management
  Name
    
    Age
    
    PositionReginald J. Greenslade
    
    
    41
    
    
    ChairmanE. Keith Conrad
    
    
    66
    
    
    Director, President, Chief Executive OfficerH.S. (Scobey) Hartley
    
    
    72
    
    
    DirectorNorman W. Wallace
    
    
    66
    
    
    DirectorWilliam E. Sliney
    
    
    66
    
    
    DirectorJohn Kalman
    
    
    46
    
    
    Chief Financial Officer
 Reginald (Reg) J. Greenslade.
 E. Keith Conrad.
 H.S. (Scobey) Hartley.
 Norman W. Wallace.
 William E. Sliney.
 John Kalman .
 66




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##### Table of Contents



67




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##### Table of Contents



B. Compensation
  Annual Compensation
    
    Long-Term CompensationAwards
    
    PayoutsSecurities
    
    RestrictedUnder
    
    Shares orOther Annual
    
    Options/
    
    Restricted
    
    LTIP
    
    All OtherSalary
    
    Bonus
    
    Compensation
    
    SARs Granted
    
    Share Units
    
    Payouts
    
    CompensationName and Principal Position
    
    Year
    
    ($)
    
    ($)
    
    ($)
    
    (#)
    
    ($)
    
    ($)
    
    ($)Reg J. Greenslade (1)
    
    
    2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    200,000
    
    
    
    
    
    
    
    
    
    
    
    Chairman, President, and
    
    
    2003
    
    
    
    200,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    274,000CEO
    
    
    2002
    
    
    
    157,500
    
    
    
    50,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Luc Chartrand (2)
    
    
    2004
    
    
    
    200,000
    
    
    
    195,458
    
    
    
    
    
    
    
    200,000
    
    
    
    
    
    
    
    
    
    
    
    President and Chief Executive
    
    
    2003
    
    
    
    178,060
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    274,000Officer
    
    
    2002
    
    
    
    158,355
    
    
    
    50,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Lynn Wiebe (3)
    
    
    2004
    
    
    
    120,000
    
    
    
    127,048
    
    
    
    
    
    
    
    120,000
    
    
    
    
    
    
    
    
    
    
    
    10,450Chief Financial Officer
    
    
    2003
    
    
    
    16,950
    
    
    
    
    
    
    
    
    
    
    
    5,000
    
    
    
    
    
    
    
    
    
    
    
    6,0002002
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
 (1)
    
    Mr. Greenslade resigned from the offices of President and Chief Executive Officer
on completion of Enterras plan of arrangement with the Trust on November 25, 2003. He was
reappointed President, and Chief Executive Officer on January 15, 2005 and resigned from
these offices on June 1, 2005.(2)
    
    Mr. Chartrand was Chief Financial Officer in 2001, 2002 and for most of 2003. He
became President and Chief Executive Officer of Enterra on November 25, 2003 and resigned
from these positions and as a director on January 15, 2005.(3)
    
    Ms. Wiebe became Chief Financial Officer of Enterra on November 25, 2003. Prior
thereto, Ms. Wiebe served Enterra on a consulting basis. She resigned on January 24, 2005.
 Bonus Plan
  Management Contracts
  Trust Units Options
  68




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##### Table of Contents



Trust Unit Options Granted During the Most Recently Completed Financial Year
  Option Grants During Fiscal Year Ended December 31, 2004
 Individual GrantsPercentage ofTotalOptions
    
    
    
    
    
    
    
    
    
    Potential Realizable ValueNumber of
    
    Granted to
    
    
    
    
    
    
    
    
    
    at Assumed Annual Rate ofShares of
    
    Employees in
    
    
    
    
    
    
    
    
    
    Stock Price AppreciationCommon
    
    Year Ending
    
    Exercise
    
    Expiration
    
    for Option Term (1)Stock
    
    Dec. 31, 2004
    
    Price Per Share
    
    Date
    
    5%
    
    10%Reg J. Greenslade
    
    
    120,000
    
    
    
    12.63
    %
    
    $
    14.00
    
    
    Jan 14, 2009
    
    $
    464,153
    
    
    $
    1,025,656Luc Chartrand
    
    
    200,000
    
    
    
    21.05
    %
    
    $
    14.00
    
    
    Jan 14, 2009
    
    $
    773,588
    
    
    $
    1,709,428Lynn Wiebe
    
    
    120,000
    
    
    
    12.63
    %
    
    $
    14.00
    
    
    Jan 14, 2009
    
    $
    464,153
    
    
    $
    1,025,656Norman W.G. Wallace
    
    
    120,000
    
    
    
    12.63
    %
    
    $
    14.00
    
    
    Jan 14, 2009
    
    $
    464,153
    
    
    $
    1,025,656Herman S. Hartley
    
    
    120,000
    
    
    
    12.63
    %
    
    $
    14.00
    
    
    Jan 14, 2009
    
    $
    464,153
    
    
    $
    1,025,656William E. Sliney
    
    
    120,000
    
    
    
    12.63
    %
    
    $
    14.00
    
    
    Jan 14, 2009
    
    $
    464,153
    
    
    $
    1,025,656William Turko
    
    
    120,000
    
    
    
    12.63
    %
    
    $
    14.00
    
    
    Jan 14, 2009
    
    $
    464,153
    
    
    $
    1,025,656
 
 (1)
    
    Assumed annual appreciation rates are established by regulations and are not a forecast of future appreciation. The amounts
shown are pre-tax and assume the options will be held throughout the entire five-year term. If trust units do not increase in value
after the grant date of the options, the options are valueless. Aggregated Option Exercises During the Most Recently Completed Financial Year and Financial
Year End Option Values
  Value ofUnexercisedin-the-Money OptionsUnexercised
    
    at FY-EndOptions at FY-End
    
    Exercisable/Securities
    
    Aggregate Value
    
    Exercisable/
    
    Unexercisable ($)Exercised (#)
    
    Realized ($)
    
    Unexercisable (#)
    
    (1)Reg J. Greenslade
    
    
    
    
    
    
    
    
    
    
    0/120,000
    
    
    
    0/2,677,200Luc Chartrand
    
    
    
    
    
    
    
    
    
    
    0/200,000
    
    
    
    0/4,462,000Lynn Wiebe
    
    
    
    
    
    
    
    
    
    
    0/120,000
    
    
    
    0/2,677,200
 
 (1)
    
    The closing price of our trust units on the Toronto Stock Exchange on the last
trading day in December 2004 was $18.91. 69




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##### Table of Contents



C. Board Practices
 Board of Directors
   Committees of the Board of Directors
  Audit Committee.
 Compensation Committee.
 Corporate Governance Committee.
 Reserves Committee
 D. Employees
   70




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##### Table of Contents



E. Share ownership
  
    
    each of our executive officers and directors; and
    
    all executive officers and directors as a group.
  Number of Trust Units/
    
    
    Percentage of TrustExchangeable Shares
    
    
    Units/ ExchangeableBeneficially Owned
    
    
    Shares OutstandingReginald J. Greenslade
    
    
    105,753/24,973
    
    
    
    0.4%/6.1
    %H.S. (Scobey) Hartley
    
    
    74,400
    
    
    
    0.28
    %Norman W. Wallace
    
    
    25,000
    
    
    
    0.1
    %William E. Sliney (1)
    
    
    127,500
    
    
    
    0.49
    %All directors and executive
officers as a group (five
persons)
    
    
    332,653/24,973
    
    
    
    1.27%/6.1
    %
 
 Notes:(1)
    
    Mr. Sliney did not become a director of Enterra until March 19, 2004. 71




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##### Table of Contents



ITEM 7. Major Shareholders and Related Party Transactions
 A. Major Shareholders
  B. Related Party Transactions
  C. Interests of Experts and Counsel
  
 ITEM 8. Financial Information
 A. Consolidated Statements and Other Financial Information
  B. Significant Changes
     72




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ITEM 9. The Offer and Listing
 A. Offer and Listing details
  Price Range of Common Stock and Trading Markets
   73




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##### Table of Contents



Toronto Stock
    
    NasdaqExchange/TSX
    
    Small Cap
    
    NasdaqVenture Exchange
    
    Market/Pink Sheets
    
    National Market(Cdn. $s)
    
    (U.S. $s)
    
    (U.S. $s)Five most recent full fiscal years:
    
    High
    
    Low
    
    High
    
    Low
    
    High
    
    LowYear ended December 31, 2004
    
    
    24.00
    
    
    
    13.01
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    19.47
    
    
    
    10.10Year ended December 31, 2003
    
    
    14.10
    
    
    
    4.995
    
    
    
    7.75
    
    
    
    3.245
    
    
    
    10.91
    
    
    
    4.625Year ended December 31, 2002
    
    
    5.75
    
    
    
    1.30
    
    
    
    3.75
    
    
    
    0.735
    
    
    
    n/a
    
    
    
    n/aYear ended December 31, 2001
    
    
    3.75
    
    
    
    1.15
    
    
    
    2.405
    
    
    
    0.825
    
    
    
    n/a
    
    
    
    n/aYear ended December 31, 2000
    
    
    3.90
    
    
    
    2.225
    
    
    
    2.305
    
    
    
    1.705
    
    
    
    n/a
    
    
    
    n/aYear ended December 31, 2004:Quarter ended December 31, 2004
    
    
    24.00
    
    
    
    17.64
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    19.47
    
    
    
    14.06Quarter ended September 30, 2004
    
    
    19.08
    
    
    
    16.81
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    15.04
    
    
    
    12.65Quarter ended June 30, 2004
    
    
    20.70
    
    
    
    15.50
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    15.90
    
    
    
    11.02Quarter ended March 31, 2004
    
    
    21.00
    
    
    
    13.01
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    16.19
    
    
    
    10.10Year ended December 31, 2003:Quarter ended December 31, 2003
    
    
    14.10
    
    
    
    5.775
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    10.91
    
    
    
    4.625Quarter ended September 30, 2003
    
    
    12.935
    
    
    
    8.54
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    9.625
    
    
    
    6.00Quarter ended June 30, 2003
    
    
    10.25
    
    
    
    8.925
    
    
    
    7.75
    
    
    
    4.045
    
    
    
    n/a
    
    
    
    n/aQuarter ended March 31, 2003
    
    
    7.00
    
    
    
    4.995
    
    
    
    4.75
    
    
    
    3.245
    
    
    
    n/a
    
    
    
    n/aSix most recent months ended:May 2005
    
    
    27.73
    
    
    
    23.01
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    22.49
    
    
    
    18.50June 2005 (
    
    
    29.34
    
    
    
    23.85
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    24.00
    
    
    
    19.00July 2005
    
    
    32.32
    
    
    
    29.30
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    26.75
    
    
    
    23.57August 2005
    
    
    30.37
    
    
    
    23.85
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    25.20
    
    
    
    19.80September 2005
    
    
    29.03
    
    
    
    22.50
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    24.99
    
    
    
    19.04October 2005
    
    
    28.79
    
    
    
    25.00
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    24.84
    
    
    
    21.33
  Shareholder Meeting Quorum Requirement
 Shareholder Approval Requirements:
 74




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##### Table of Contents



75




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##### Table of Contents



B. Plan of Distribution
  C. Markets
  D. Selling Shareholders
  E. Dilution
  F. Expenses of the issue
  76




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##### Table of Contents



ITEM 10. Additional information
 A. Share Capital
  B. Trust Indenture / Memorandum and Articles of Association
 The Trust
   Income Tax Act Income Tax Act Income Tax Act U.S. Investment Company Act of 1940.
     Enterra
    77




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##### Table of Contents



C. Material Contracts
  Governing Trust Documents
 (a) Trust Indenture
 (b) Administration Agreement
 (c) Enterra
Note Indenture
 d) Support
Agreement
   (a)
    
    additional Trust Units or securities convertible into Trust Units;
 78




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##### Table of Contents



(b)
    
    rights, options or warrants for the purchase of Trust Units; or(c)
    
    units or securities of the Trust other than Trust Units, evidences of
indebtedness of the Trust or other assets of the Trust;
     (e) Voting
and Exchange Trust Agreement
     Other Material Contracts
 (f) Amended
and Restated Agreement of Business Principles
 79




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##### Table of Contents



(g) Technical Services Agreement
 (h) RMAC Arrangement Agreement
 (i) RMAC Note Indenture
 (j) Trust Unit Sale Agreement
 (k) High Point Arrangement Agreement
 D. Exchange Controls
  80




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Investment
Canada Act North American Free Trade Agreement Implementation Act World Trade
Organization Agreement Implementation Act Investment Canada Act Investment Canada Act
 81




---



##### Table of Contents



E. Taxation
 Canadian Federal Income Tax Considerations
 Income Tax Act
    This summary is of a general nature only and is not intended to be relied on as legal or tax advice
or representations to any particular investor. Consequently, potential investors are urged to seek
independent tax advice in respect of the consequences to them of the acquisition of trust units
having regard to their particular circumstances.
 Residents of Canada
  Status of the Trust
   1.
    
    the sole undertaking of the Trust must be the investing of its funds in property (other than
real property or interests in real property), the acquiring, holding, maintaining, improving,
leasing or managing of any real property (or an interest in real property) that is capital
property of the Trust, or any combination of these activities;2.
    
    the Trust must comply on a continuous basis with certain requirements relating to the
qualification of the trust units for distribution to the public, the number of Unitholders and
the dispersal of ownership of trust units. In this regard, there must be at least 150
Unitholders, each of whom owns not less than one block of trust units having a fair market
value of not less than $500. A block of trust units means 100 trust units if the fair
market value of one trust unit is less than $25; and
 82




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##### Table of Contents



3.
    
    continuously from the time of its creation, all or substantially all of the Trusts property
must consist of property other than property that would be taxable Canadian property for
purposes of the Tax Act.
  If the Trust were not to so qualify as a mutual fund trust or were not to be registered as a
registered investment from inception, the income tax considerations would in some respects be
materially different from those described below.
 Taxation of the Trust
        83




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Taxation of Unitholders
 Income from trust units
   Taxation of Capital Gains and Capital Losses Taxation of Capital Gains and Capital Losses
  Cost of trust units
  Disposition of trust units
  84




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Taxation of Capital
Gains and Capital Losses
    Tax-Exempt Unitholders
   Taxation of Capital Gains and Capital Losses
  85




---



##### Table of Contents



Non-Residents of Canada
  Taxation of the Trust
  Taxation of Income from Trust Units
 Residents of Canada  Taxation of the Trust
  86




---



##### Table of Contents



Disposition of trust units
     Taxation of Capital Gains and Capital Losses on Dispositions of Taxable Canadian Property
    United States Federal Income Tax Considerations
   87




---



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Flow-through of Items of Income, Gain, Loss, Deduction and Credit
   Tax Rates and Creditability of Certain Canadian Income Taxes.
  United States Federal Income Tax Rates
   Credits for Canadian Income Taxes
  88




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##### Table of Contents



Tax Consequences if We are Determined to be a Passive Foreign Investment Company
   Tax-Exempt Organizations and Other Investors
    89




---



##### Table of Contents



Administrative Matters
 Information Returns and Audit Procedures
     Nominee Reporting
  §
    
    the name, address and taxpayer identification number of the beneficial owner and the nominee;§
    
    whether the beneficial owner is:
 (i)
    
    a person that is not a United States person;(ii)
    
    a foreign government, an international organization or any wholly owned
agency or instrumentality of either of the foregoing; or(iii)
    
    a tax-exempt entity;
 §
    
    the amount and description of trust units held, acquired or transferred for the beneficial owner; and§
    
    specific information including the dates of acquisitions and transfers means of
acquisitions and transfers, and acquisition cost for purchases, as well as the amount of
net proceeds from sales.
  90




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Registration as a Tax Shelter
  Issuance of a tax shelter registration number does not indicate that investment in us or the
claimed tax benefits have been reviewed, examined or approved by the Internal Revenue Service.
  Reportable Transactions
  Other Tax Considerations
  91




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F. Dividends and Paying Agents
  G. Statement by Experts
  H. Documents on Display
  www.sec.gov
  Enterra Energy Trust
Suite 2600, 500 
4 th Avenue S.W.
Calgary, Alberta, Canada
T2P 2V6
(403) 213-2502
 I. Subsidiary Information
  92




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ITEM 11. Qualitative and Quantitative Disclosures about Market Risk
  Credit Risk
  Foreign Exchange Risk
  Commodity Price Risk
   Interest Rate Risk
   93




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##### Table of Contents



Sensitivities
    
    Estimated 2005 impact on:Cash Provided ByOperatingNet Earnings
    
    
    ActivitiesCrude oil  US$1.00/bbl change in WTI
    
    $
    1,300,000
    
    
    $
    2,000,000Natural Gas  US$0.50/mcf change
    
    $
    800,000
    
    
    $
    1,200,000Foreign Exchange  $0.01 change in U.S. to CDN dollar
    
    $
    500,000
    
    
    $
    400,000Interest rate  1% change
    
    $
    300,000
    
    
    $
    400,000
 
 ITEM 12. Description of Securities Other Than Equity Securities
  94




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Part II
 
 ITEM 13. Defaults, Dividends Arrearages and Delinquencies
  
 ITEM 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
  
 ITEM 15. Controls and Procedures
 (a) Disclosure controls and procedures.
  (b) Managements annual report on internal control over financial reporting.
  (c) Attestation report of the registered public accounting firm.
  (d) Changes in internal controls.
  95




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##### Table of Contents



ITEM 16. [Reserved]
 ITEM 16A. Audit Committee Financial Expert
  ITEM 16B. Code of Ethics
  ITEM 16C. Principal Accountant Fees and Services
 Audit Fees
  Audit-Related Fees
  Tax Fees
  All Other Fees
  Pre-Approval Policies and Procedures
  ITEM 16D. Exemptions from the Listing Standards for Audit Committees
  ITEM 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers
  96




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PART III
 
 ITEM 17. Financial Statements
  
 ITEM 18. Financial Statements
        REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
       
 97




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Comments by Auditor for US Readers on Canada-US Reporting Differences
  
 98




---



##### Table of Contents



REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
       
 Comments by Independent Registered Chartered Accountants on Canada-United States of America
Reporting Differences
   
 99




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##### Table of Contents



Enterra Energy Trust
Consolidated Balance Sheets
As at December 31  (Expressed in thousand Canadian Dollars)
 2004
    
    
    2003(restated see
    
    
    (restated see notesnote 3(d))
    
    
    3(c) and 3(d))AssetsCurrent assetsCash
    
    $
    4,779
    
    
    $
    66Accounts receivable
    
    
    15,613
    
    
    
    8,742Prepaid expenses and deposits
    
    
    518
    
    
    
    46220,910
    
    
    
    9,270Deposit on land purchase (notes 4 and 17)
    
    
    2,400
    
    
    
    2,015Property, plant and equipment (note 6)
    
    
    148,458
    
    
    
    105,260Deferred financing charges
    
    
    90
    
    
    
    123Goodwill (notes 3(d) and 5)
    
    
    49,270
    
    
    
    37$
    221,128
    
    
    $
    116,705LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities
    
    $
    8,570
    
    
    $
    12,208Due to JED Oil Inc. (note 1)
    
    
    4,493
    
    
    
    Distributions payable to unitholders
    
    
    4,398
    
    
    
    2,451Income taxes payable
    
    
    1,068
    
    
    
    120Bank indebtedness (note 8)
    
    
    43,930
    
    
    
    33,960Current portion of capital lease (note 9)
    
    
    805
    
    
    
    78363,264
    
    
    
    49,522Asset retirement obligations (note 7)
    
    
    14,836
    
    
    
    2,188Future income tax liability (note 12)
    
    
    22,128
    
    
    
    13,939Capital lease (note 9)
    
    
    2,580
    
    
    
    3,386102,808
    
    
    
    69,035Non-controlling interest (note 3(d) and 10)
    
    
    3,349
    
    
    
    3,125Unitholders EquityUnitholders capital (note 11)
    
    
    132,207
    
    
    
    32,879Contributed surplus (note 11)
    
    
    78
    
    
    
    Accumulated earnings
    
    
    27,498
    
    
    
    14,117Accumulated distributions
    
    
    (44,812
    )
    
    
    (2,451
    )114,971
    
    
    
    44,545Commitments, contingencies and guarantees
(notes 14, 15 and 16)Subsequent events (note 17)
    
    $
    221,128
    
    
    $
    116,705
 Approved on behalf of the BoardReg Greenslade
    
    Bill SlineyDirector
    
    Director
 See accompanying notes to consolidated financial statements
 100




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##### Table of Contents



Enterra Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings
Years Ended December 31,  (Expressed in thousand Canadian Dollars)
 2004
    
    
    2003
    
    
    2002restated seenotes 3(c) and
    
    
    restated seerestated see note 3(d)
    
    
    3(d)
    
    
    note 3(c)RevenueOil and gas
    
    $
    108,293
    
    
    $
    72,097
    
    
    $
    25,746ExpensesRoyalties
    
    
    24,527
    
    
    
    17,656
    
    
    
    4,203Production
    
    
    23,492
    
    
    
    12,763
    
    
    
    6,018General and administrative
    
    
    4,440
    
    
    
    3,385
    
    
    
    1,683Interest
    
    
    2,222
    
    
    
    1,749
    
    
    
    1,236Amortization of deferred financing charges
    
    
    33
    
    
    
    262
    
    
    
    390Depletion, depreciation and accretion
    
    
    35,976
    
    
    
    23,306
    
    
    
    9,449Financial derivative loss
    
    
    3,188
    
    
    
    
    
    
    
    Gain on redemption of preferred shares
    
    
    
    
    
    
    
    
    
    
    (3,111
    )Restructuring charges (note 1)
    
    
    
    
    
    
    5,756
    
    
    
    93,878
    
    
    
    64,877
    
    
    
    19,868Earnings before income taxes and
non-controlling interest
    
    
    14,415
    
    
    
    7,220
    
    
    
    5,878Income taxes (reduction) (note 12)Current
    
    
    260
    
    
    
    134
    
    
    
    132Future
    
    
    (280
    )
    
    
    1,988
    
    
    
    865(20
    )
    
    
    2,122
    
    
    
    997Net earnings before non-controlling interest
    
    
    14,435
    
    
    
    5,098
    
    
    
    4,881Non-controlling interest (note 3(d) and 10)
    
    
    408
    
    
    
    (332
    )
    
    
    Net earnings
    
    
    14,027
    
    
    
    5,430
    
    
    
    4,881Accumulated earnings, beginning of year, as
previously stated
    
    
    13,937
    
    
    
    8,933
    
    
    
    3,956Change in accounting policy related to
asset retirement obligations (note 3(c))
    
    
    (152
    )
    
    
    (246
    )
    
    
    96Change in accounting policy related to unit
based compensation (note 3(d))
    
    
    (646
    )
    
    
    
    
    
    
    Change in accounting policy related to
non-controlling interest (note 3(d))
    
    
    332Accumulated earnings, end of year
    
    $
    27,498
    
    
    $
    14,117
    
    
    $
    8,933Earnings per unit (note 11)Basic
    
    $
    0.62
    
    
    $
    0.29
    
    
    $
    0.27Diluted
    
    $
    0.62
    
    
    $
    0.27
    
    
    $
    0.26
  101




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Enterra Energy Trust
Consolidated Statements of Cash Flows
Years Ended December 31  (Expressed in thousand Canadian Dollars)
 2004
    
    
    2003
    
    
    2002restated see note
    
    
    (restated see notes
    
    
    (restated see3(d)
    
    
    3(c) and 3(d))
    
    
    note 3(c))Cash provided by (used in):OperationsNet earnings
    
    $
    14,027
    
    
    $
    5,430
    
    
    $
    4,881Add non-cash items:Depletion, depreciation and accretion
    
    
    35,976
    
    
    
    23,306
    
    
    
    9,449Future income taxes
    
    
    (280
    )
    
    
    1,988
    
    
    
    865Amortization of deferred gain
    
    
    
    
    
    
    (238
    )
    
    
    (524
    )Amortization of deferred financing charges
    
    
    33
    
    
    
    262
    
    
    
    390Non-controlling interest
    
    
    408
    
    
    
    (332
    )Unit based compensation
    
    
    78
    
    
    
    
    
    
    
    Gain on redemption of preferred shares
    
    
    
    
    
    
    
    
    
    
    (3,111
    )Valuation of warrants
    
    
    
    
    
    
    282
    
    
    
    Expenditures on asset retirement obligations
    
    
    
    
    
    
    (5
    )
    
    
    (49
    )Change in non-cash working capital items:Accounts receivable
    
    
    (4,393
    )
    
    
    (1,429
    )
    
    
    (1,017
    )Prepaid expenses
    
    
    (57
    )
    
    
    195
    
    
    
    (74
    )Accounts payable and accrued liabilities
    
    
    (3,607
    )
    
    
    (8,453
    )
    
    
    11,672Income taxes payable
    
    
    160
    
    
    
    (35
    )
    
    
    (8
    )42,345
    
    
    
    20,971
    
    
    
    22,474FinancingDistributions paid
    
    
    (40,414
    )
    
    
    
    
    
    
    Bank indebtedness
    
    
    2,305
    
    
    
    9,523
    
    
    
    6,028Due to JED Oil Inc.
    
    
    2,400
    
    
    
    
    
    
    
    Capital lease
    
    
    (783
    )
    
    
    (753
    )
    
    
    4,704Deferred financing charges
    
    
    
    
    
    
    (101
    )
    
    
    (550
    )Redemption of preferred shares
    
    
    
    
    
    
    (637
    )
    
    
    (2,557
    )Issue of trust units, net of issue costs
    
    
    36,838
    
    
    
    
    
    
    
    Repurchase of shares
    
    
    
    
    
    
    
    
    
    
    (60
    )Exercise of options and warrants
    
    
    
    
    
    
    6,284
    
    
    
    97346
    
    
    
    14,316
    
    
    
    7,662InvestingProperty and equipment additions
    
    
    (30,409
    )
    
    
    (51,577
    )
    
    
    (35,881
    )Deposit on land purchases
    
    
    (385
    )
    
    
    (2,015
    )
    
    
    Proceeds on disposal of property and equipment
    
    
    1,178
    
    
    
    18,263
    
    
    
    5,810Acquisition of Rocky Mountain Energy Corp.
(note 5)
    
    
    (8,362
    )
    
    
    
    
    
    
    (37,978
    )
    
    
    (35,329
    )
    
    
    (30,071
    )Increase (decrease) in cash
    
    
    4,713
    
    
    
    (42
    )
    
    
    65Cash, beginning of year
    
    
    66
    
    
    
    108
    
    
    
    43Cash, end of year
    
    $
    4,779
    
    
    $
    66
    
    
    $
    108
  See accompanying notes to consolidated financial statements
 102




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##### Table of Contents



Enterra Energy Trust  Notes to Consolidated Financial Statements
 1.
    
    Structure of the Trust and Basis of PresentationEnterra Energy Trust (the Trust) was established on November 25, 2003 under a Plan of
Arrangement involving the Trust, Enterra Energy Corp. (Enterra), Big Horn Resources Ltd.,
Enterra Production Partnership and Enterra Saskatchewan Ltd. (Plan of Arrangement). The Trust
is an open-end unincorporated investment trust governed by the laws of the Province of Alberta
and created pursuant to a trust indenture (the Trust Indenture). The beneficiaries of the
Trust are the holders of the Trust Units (the Unitholders).Under the Plan of Arrangement, the shareholders of Enterra exchanged their shares for two Trust
Units or two Exchangeable Shares, which may be exchanged into Trust Units. Under the Plan of
Arrangement, Enterra became a wholly owned subsidiary of the Trust, through amalgamation of
Enterra, Big Horn Resources Ltd. and Enterra Saskatchewan Ltd. on November 25, 2003.Prior to the implementation of the Plan of Arrangement, the consolidated financial statements
included the accounts of Enterra and its subsidiaries. After giving effect to the Plan of
Arrangement, the consolidated financial statements have been prepared on a continuity of
interests basis, which recognizes the Trust as the successor entity to Enterra. Accordingly,
these consolidated financial statements reflect the financial position, results of operations
and cash flows as if the Trust, (together with its wholly-owned subsidiaries), had always
carried on the business formerly carried on by Enterra with all assets and liabilities recorded
at the carrying values of Enterra.Restructuring costs associated with the Plan of Arrangement totaled $5,756,000 that included
legal, accounting and advisory costs of $2,057,000 and employee bonus payments of $3,699,000.Relationship with JED Oil Inc.Effective January 1, 2004, the Trust and JED Oil Inc. (JED) entered into a Technical Services
Agreement, which provides for services required to manage the Trusts field operations and
governs the allocation of general and administrative expenses between the two entities. Under
the Technical Services Agreement, the Trust and JED allocate the costs of management,
development, exploitation, operations and general and administrative activities on the basis of
production and capital expenditures, or as otherwise agreed to between the Trust and JED. The
Technical Services Agreement has no set termination date and can be cancelled with six months
notice.Under an Agreement of Business Principles, properties acquired by Enterra will be contract
operated and drilled by JMG Exploration, Inc. (JMG), if they are exploration properties, and
contract operated and drilled by JED if they are development projects. Exploration of the
properties will be done by JMG, which will pay 100% of the exploration costs to earn a 70%
working interest in the properties. If JMG discovers commercially viable reserves on the
exploration properties, Enterra will have the right to purchase 80% of JMGs working interest in
the properties at a fair value as determined by independent engineers. Should Enterra elect to
have JED develop the properties, development will be done by JED, which will pay 100% of the
development costs to earn 70% of the interests of both JMG and Enterra. Enterra will have a
first right to purchase assets developed by JED.On December 23, 2004, JED loaned to Enterra $2,400,000. The terms of the loan call for interest
calculated at a Canadian chartered bank prime lending rate plus 0.4% per annum. The loan is
repayable on or before June 29, 2005. Subsequent to December 31, 2004, JED loaned additional
funds of $9,600,000 under the same terms. On March 18, 2005, Enterra repaid the original loan
amount of $2,400,000 together with accrued interest. At December 31, 2004, Enterra owed
$2,093,000 to JED for general and administrative expenses and capital expenditures paid by JED
on behalf of Enterras joint venture partners.
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 2.
    
    Significant Accounting PoliciesManagement of the Trust has prepared the consolidated financial statements in accordance with
Canadian Generally Accepted Accounting Principles (GAAP). The following significant accounting
policies are presented to assist the reader in evaluating these consolidated financial
statements, and, together with the following notes, should be considered an integral part of the
consolidated financial statements.
 (a)
    
    Organization and Basis of AccountingThese consolidated financial statements include the accounts of the Trust, its wholly owned
subsidiaries Enterra Energy Commercial Trust, Rocky Mountain Acquisition Corp., Enterra
Energy Corp. and Enterras 100% partnership interest in Enterra Production Partnership
(collectively the Trust for purposes of the following notes to the consolidated financial
statements). All material inter-company accounts and transactions have been eliminated.Substantially all exploration, development and production activities related to the Trusts
oil and gas business are conducted jointly with others and the accounts reflect only the
Trusts proportionate interest.(b)
    
    CashCash consists of cash on hand and balances invested in short-term securities with original
maturities less than 90 days.(c)
    
    Revenue RecognitionRevenue associated with the sale of crude oil, natural gas and natural gas liquids is
recognized when the title passes from the Trust to its customers.(d)
    
    Petroleum and natural gas propertiesThe Trust follows the full cost method of accounting for petroleum and natural gas
properties. All costs related to the exploration for and the development of oil and gas
reserves are capitalized into a single cost center. Costs capitalized include land
acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped
properties and costs of drilling productive and non-productive wells and production
equipment.General and administrative costs are capitalized if they are directly related to successful
acquisitions or capital projects.Proceeds from the disposal of oil and natural gas properties are applied as a reduction of
cost without recognition of a gain or loss except where such disposals would result in a 20%
change in the depletion rate.Repair and maintenance costs are expensed as incurred.(e)
    
    Impairment TestThe Trust places a limit on the carrying value of property and equipment, which may be
depleted against revenues of future periods (the ceiling test). The carrying value is
assessed to be recoverable when the sum of the undiscounted cash flows expected from the
production of proved reserves, the lower of cost and market of unproved properties and the
cost of major development projects exceeds the carrying value. When the carrying value is
not assessed to be recoverable, an impairment loss is recognized to the extent that the
carrying value of petroleum and natural gas properties exceeds the sum of the discounted
cash flows expected from the production of proved and probable reserves, the lower of cost
and market of unproved properties and
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 the cost of major development projects. The cash flows are estimated using expected future
product prices and costs are discounted using a risk-free interest rate. The carrying value
of property and equipment subject to the ceiling test includes asset retirement costs.(f)
    
    Per Unit AmountsPer unit amounts are calculated using the weighted average number of units (or common shares
to November 24, 2003) and reflect the two for one exchange ratio pursuant to the Plan of
Arrangement. The Trust follows the treasury stock method to determine dilutive effect of
options and other dilutive instruments. Under the treasury stock method, only in-the-money
dilutive instruments impact the diluted calculations.(g)
    
    Estimates and AssumptionsThe preparation of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, and the disclosure of contingent assets and liabilities
at the dates of the financial statements and the reported amounts of revenue and expenses
during the reporting periods.The amounts recorded for depletion, depreciation and the asset retirement obligation are
based on estimates. The ceiling test calculation is based on estimates of reserves,
production rates, oil and natural gas prices, future costs and other relevant assumptions.
By their nature, these estimates are subject to measurement uncertainty and may impact the
consolidated financial statements of future periods.(h)
    
    Depletion and DepreciationThe provision for depletion and depreciation of petroleum and natural gas properties is
calculated using the unit-of-production method based on the Trusts share of estimated
proved reserves before royalties. Natural gas reserves and production are converted to
equivalent units of crude oil using their approximate relative energy content.(i)
    
    GoodwillThe Trust recognizes goodwill relating to acquisitions when the total purchase price exceeds
the fair value of the net identifiable assets and liabilities acquired. The goodwill balance
is assessed for impairment annually at year-end or as events occur that could result in an
impairment. To assess impairment, the fair value of the Trust is compared to its book value.
If the fair value is less than the book value, a second test is performed to determine the
amount of impairment. The amount of impairment is measured by allocating the fair value to
the Trusts identifiable assets and liabilities as if it had been acquired in a business
combination for a purchase price equal to its fair market value. If goodwill determined in
this manner is less than the carrying value of goodwill, an impairment loss is recognized in
the period in which it occurs. Goodwill is stated at cost less impairment.(j)
    
    Asset Retirement ObligationsThe Trust recognizes a liability for the estimated fair value of the future retirement
obligations associated with property and equipment. The fair value of the estimated asset
retirement obligations is recorded as a liability with a corresponding increase in the
carrying amount of the related asset. The capitalized amount is depleted on the
unit-of-production method based on proved reserves. The Trust estimates the liability based
on the estimated costs to abandon and reclaim its net ownership interest in all wells and
facilities and the estimated timing of the costs to be incurred in future periods. This
estimate is evaluated on a periodic basis and any adjustment to the estimate is
prospectively applied. As time passes, the change in net present value of the future
retirement obligation is expensed through accretion. Retirement obligations settled during
the period reduce the future retirement liability.
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Enterra Energy Trust Notes to Consolidated Financial Statements
 (k)
    
    Income TaxesThe Trust is a taxable entity under the Canadian Income Tax Act and is taxable only on
income that is not distributed or distributable to the Trusts unitholders. As the Trust
allocates all of its taxable income to the unitholders in accordance with the Trust
Indenture, and meets the requirements of the Canadian Income Tax Act (Canada) applicable to
the Trust, no provision for income tax expense has been made in the Trust.The Trusts corporate subsidiaries follow the liability method of accounting for income
taxes. Under this method, income tax liabilities and assets are recognized based on the
differences between the amounts reported in the financial statements of the Trusts
corporate subsidiaries and their respective tax bases, using substantively enacted income
tax rates. The effect of a change in income tax rates on future income tax liabilities and
assets is recognized in income in the period that the change occurs.(l)
    
    Derivative Financial InstrumentsThe Trust uses derivative financial instruments such as collars and swaps to manage its
exposure to commodity price fluctuations. The Trust uses the fair value method for reporting
derivative financial instruments whereby a derivative financial instrument is recorded as an
asset or a liability on the balance sheet, and changes in the fair value relating to a
financial period are charged to net earnings and net earnings per unit for the period.(m)
    
    Trust Unit Compensation PlansThe Trust has a unit based compensation plan, which is described in note 10. Compensation
expense associated with the unit based compensation plan is recognized in earnings over the
vesting period of the plan with a corresponding increase in contributed surplus. Any
consideration received upon the exercise of the unit-based compensation together with the
amount of non-cash compensation expense recognized in contributed surplus is recorded as an
increase in unitholders capital. Compensation expense is based on the fair value of the
unit-based compensation at the date of grant using a Black-Scholes option-pricing model.(n)
    
    Deferred Financing ChargesDeferred financing charges relating to a capital lease are being amortized over the term of
the capital lease. A total of $164,000 was initially deferred with a remaining $90,000 to
be amortized until the end of the lease.(o)
    
    Foreign Currency TransactionsTransactions completed in United States dollars are reflected in Canadian dollars at the
exchange rates prevailing at the time of the transactions. Current assets and liabilities
denominated in United States dollars are reflected in the financial statements at the
Canadian equivalent at the rate of exchange prevailing at the balance sheet date.
Translation gains and losses are included in earnings.(p)
    
    Office Furniture and EquipmentOffice furniture and equipment is depreciated on a 20% declining balance basis.(q)
    
    Comparative FiguresCertain comparative figures have been reclassified to conform with the presentation adopted
in the current year.
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 3.
    
    Changes in Accounting Policies
 (a)
    
    Full Cost AccountingEffective January 1, 2004, the Trust prospectively adopted new Canadian accounting standards
relating to full cost accounting for oil and gas entities, as outlined in note 2. The new
standard modifies the ceiling test to be performed in two stages. The first stage requires
the carrying value to be tested for recoverability using undiscounted future cash flows from
proved reserves using forward indexed prices. If the carrying value is not recoverable, the
second stage, which is based on the calculation of discounted future cash flows from proved
plus probable reserves, will determine the impairment to the fair value of the asset. There
was no write down of the Trusts property and equipment as at January 1, 2004, as a result
of adopting this standard.(b)
    
    Derivative Financial InstrumentsOn January 1, 2004, the Trust prospectively adopted new Canadian accounting standards
relating to accounting for derivative financial instruments. The new standards establish
certain conditions for when hedge accounting may be applied and addresses the
identification, designation, documentation and effectiveness of hedging transactions. Where
hedge accounting does not apply, any changes in the mark to market values of the derivative
financial instrument relating to a financial period can either reduce or increase net
earnings and net earnings per trust unit for that period. The Trust has elected not to apply
hedge accounting to any of its financial instruments.The following table summarizes the changes in the financial derivative liability and the
deferred financial derivative loss accounts during the year.
 Financial Derivative Liability at January 1, 2004
    
    $
    958Financial instruments settled
    
    
    (3,188
    )Mark to market realized loss
    
    
    2,230Financial Derivative Liability at December 31, 2004
    
    $
    Deferred Financial Derivative Loss at January 1, 2004
    
    $
    958Amortization of deferred financial loss
    
    
    (958
    )Deferred Financial Derivative Loss at December 31, 2004
    
    $
    
 (c)
    
    Asset Retirement Obligations (ARO)Effective January 1, 2004, the Trust retroactively adopted with restatement of prior
periods, new Canadian accounting standards relating to asset retirement obligations as
outlined in note 2. Prior to adopting the new standard, the Trust recognized a provision for
future site restoration costs over the life of the oil and natural gas properties using a
unit-of-production method.The following tables summarize the changes resulting from this restatement.
 Balance as reported
    
    
    
    
    
    
    Balance prior toBalance Sheet as at
    
    prior to ARO
    
    
    
    
    
    
    note 3(d)December 31, 2003
    
    restatement
    
    
    Adjustments for ARO
    
    
    restatementProperty, plant and equipment
    
    $
    104,821
    
    
    $
    432
    
    
    $
    105,253Asset retirement obligations
    
    
    1,529
    
    
    
    659
    
    
    
    2,188Future income tax liability
    
    
    14,011
    
    
    
    (75
    )
    
    
    13,936Accumulated earnings
    
    
    13,937
    
    
    
    (152
    )
    
    
    13,785
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 Balance as reported
    
    
    
    
    
    
    Balance prior toStatement of Earning for the year ended
    
    prior to ARO
    
    
    
    
    
    
    note 3(d)December 31, 2003
    
    restatement
    
    
    Adjustments for ARO
    
    
    restatementDepletion, depreciation and accretion
    
    $
    23,447
    
    
    $
    (141
    )
    
    $
    23,306Future income tax expense
    
    
    1,941
    
    
    
    47
    
    
    
    1,988Net earnings
    
    
    5,004
    
    
    
    94
    
    
    
    5,098Net earnings per unit  basic and diluted
    
    $
    0.26
    
    
    $
    0.01
    
    
    $
    0.27
 Balance as reported
    
    
    
    
    
    
    Balance prior toStatement of Earning for the year
    
    prior to ARO
    
    
    
    
    
    
    note NCIended December 31, 2002
    
    restatement
    
    
    Adjustments for ARO
    
    
    restatementDepletion, depreciation and accretion
    
    $
    9,307
    
    
    $
    142
    
    
    $
    9,449Future income tax expense
    
    
    911
    
    
    
    (46
    )
    
    
    865Net earnings
    
    
    4,977
    
    
    
    (96
    )
    
    
    4,881Net earnings per unit  basic
    
    $
    0.27
    
    
    
    
    
    
    $
    0.27Net earnings per unit  diluted
    
    $
    0.26
    
    
    
    
    
    
    $
    0.26
 (d)
    
    Non-controlling interest NCI)
      108




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 Balance as reportedBalance Sheet as at
    
    prior to NCIDecember 31, 2004
    
    restatement
    
    
    Adjustments for NCI
    
    
    Balance as restatedProperty, plant and equipment
    
    $
    146,910
    
    
    $
    1,548
    
    
    $
    148,458Goodwill
    
    
    29,991
    
    
    
    19,279
    
    
    
    49,270Future income tax liability
    
    
    21,526
    
    
    
    602
    
    
    
    22,128Non-controlling interest
    
    
    
    
    
    
    3,349
    
    
    
    3,349Unitholders capital
    
    
    111,653
    
    
    
    20,554
    
    
    
    132,207Exchangeable shares
    
    
    3,276
    
    
    
    (3,276
    )
    
    
    Accumulated earnings
    
    
    27,903
    
    
    
    (405
    )
    
    
    27,498Basic weighted average
number of units outstanding
    
    
    23,327,728
    
    
    
    (809,355
    )
    
    
    22,518,373Diluted weighted average
number of units outstanding
    
    
    23,560,785
    
    
    
    (318,825
    )
    
    
    23,241,960
 Balance as reportedBalance Sheet as at
    
    prior to NCIDecember 31, 2003
    
    restatement
    
    
    Adjustments for NCI
    
    
    Balance as restatedProperty, plant and equipment
    
    $
    105,253
    
    
    $
    7
    
    
    $
    105,260Goodwill
    
    
    
    
    
    
    37
    
    
    
    37Future income tax liability
    
    
    13,936
    
    
    
    3
    
    
    
    13,939Non-controlling interest
    
    
    
    
    
    
    3,125
    
    
    
    3,125Unitholders capital
    
    
    32,838
    
    
    
    41
    
    
    
    32,879Exchangeable shares
    
    
    3,457
    
    
    
    (3,457
    )
    
    
    Accumulated earnings
    
    
    13,785
    
    
    
    332
    
    
    
    14,117Basic weighted average
number of units outstanding
    
    
    18,953,968
    
    
    
    (202,334
    )
    
    
    18,751,634Diluted weighted average
number of units outstanding
    
    
    18,953,968
    
    
    
    (40
    )
    
    
    18,953,928
 Balance as reportedStatement of Earning for the year
    
    prior to NCIended December 31, 2004
    
    restatement
    
    
    Adjustments for NCI
    
    
    Balance as restatedDepletion, depreciation and accretion
    
    $
    35,438
    
    
    $
    538
    
    
    $
    35,976Future income tax recovery
    
    
    (71
    )
    
    
    (209
    )
    
    
    (280
    )Net earnings before non-controlling
interest
    
    
    14,764
    
    
    
    (329
    )
    
    
    14,435Non-controlling interest
    
    
    
    
    
    
    408
    
    
    
    408Net earnings
    
    
    14,764
    
    
    
    (737
    )
    
    
    14,027Net earnings per unit  basic
    
    $
    0.63
    
    
    
    ($0.01
    )
    
    $
    0.62Net earnings per unit  diluted
    
    $
    0.63
    
    
    
    ($0.01
    )
    
    $
    0.62
 109




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 Balance as reportedStatement of Earning for the
    
    prior to NCI
    
    
    Adjustments for NCIyear ended December 31, 2003
    
    restatement
    
    
    for NCI
    
    
    Balance as restatedNon-controlling interest
    
    $
    
    
    
    ($
    332
    )
    
    ($
    332
    )Net earnings
    
    
    5,098
    
    
    
    (332
    )
    
    
    5,430Net earnings per unit  basic
    
    $
    0.27
    
    
    $
    0.02
    
    
    $
    0.29Net earnings per unit  diluted
    
    $
    0.27
    
    
    
    
    
    
    $
    0.27
 .
 (e)
    
    Unit-based compensationEffective January 1, 2004, the Trust adopted the fair value method of accounting for options
on a retroactive basis, without prior period adjustments. In the past, the Trust measured
stock option compensation cost based on the intrinsic value of the award at the date of
issuance. As the exercise price and the market price were the same at the date of grant, no
compensation expense was recognized on any option issuance. In 2003, the Trust disclosed
pro forma net earnings and earnings per unit as if the compensation expense for the Trusts
unit-based compensation plan had been determined based on the fair value at the date of
grant for awards made under the plan subsequent to January 1, 2002.As a result of the adoption of this policy, the Trust has recorded a charge to accumulated
earnings of $646,000 as at January 1, 2004 to reflect the cost related to options granted in
2002 and 2003. In 2004, the earnings of the Trust were reduced by $78,000 as a result of
this change in policy.
 4.
    
    Property AcquisitionOn January 30, 2004, the Trust acquired certain oil and natural gas properties in East Central
Alberta for net consideration of $19,609,000. Results from operations of the East Central
Alberta assets acquired subsequent to January 30, 2004 are included in the Trusts consolidated
financial statements. At December 31, 2003, the Trust had made a refundable deposit on the
property purchased in the amount of $2,015,000.
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 5.
    
    Corporate AcquisitionOn September 29, 2004, the Trust acquired all of the issued and outstanding shares of Rocky
Mountain Energy Corp. for $49,524,000, through its subsidiary Rocky Mountain Acquisition Corp.
(RMAC). The acquisition was accounted for using the purchase method of accounting with the
allocation of the purchase price and consideration paid as follows:
 Allocation of purchase price:Current assets, including cash of $16,270
    
    $
    2,493Property, plant and equipment
    
    
    36,008Goodwill (with no tax base)
    
    
    29,990Current liabilities
    
    
    (2,849
    )Bank indebtedness
    
    
    (7,665
    )Assets retirement obligations
    
    
    (793
    )Future income tax liability
    
    
    (7,660
    )$
    49,524Cost of acquisition:Cash
    
    $
    7,234RMAC Exchangeable Units (341,882 issued)
    
    
    6,147Trust Units (1,946,576 issued)
    
    
    34,999Transaction costs
    
    
    1,144$
    49,524
    111




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 6.
    
    Property, Plant and Equipment
 2004Accumulateddepletion andCost
    
    
    depreciation
    
    
    NetPetroleum and natural gas
properties
    
    $
    223,637
    
    
    $
    76,505
    
    
    $
    147,132Office furniture and equipment
    
    
    2,158
    
    
    
    832
    
    
    
    1,326$
    225,795
    
    
    $
    77,337
    
    
    $
    148,458
 2003Accumulateddepletion andCost
    
    
    depreciation
    
    
    NetPetroleum and natural gas
properties
    
    $
    145,885
    
    
    $
    41,601
    
    
    $
    104,284Office furniture and equipment
    
    
    1,603
    
    
    
    627
    
    
    
    976$
    147,488
    
    
    $
    42,228
    
    
    $
    105,260
     Foreign
    
    Edmonton LightWTI Oil
    
    Exchange
    
    Crude Oil
    
    AECO GasYear
    
    ($U.S./bbl)
    
    Rate
    
    ($Cdn/bbl)
    
    ($Cdn/GJ)2005
    
    
    42.00
    
    
    
    1.2048
    
    
    
    49.60
    
    
    
    6.452006
    
    
    39.50
    
    
    
    1.2048
    
    
    
    46.60
    
    
    
    6.202007
    
    
    37.00
    
    
    
    1.2048
    
    
    
    43.50
    
    
    
    6.052008
    
    
    35.00
    
    
    
    1.2048
    
    
    
    41.10
    
    
    
    5.802009
    
    
    34.50
    
    
    
    1.2048
    
    
    
    40.50
    
    
    
    5.702010
    
    
    34.30
    
    
    
    1.2048
    
    
    
    40.20
    
    
    
    5.60Escalate
Thereafter
    
    2.0% per year
    
    
    
    
    
    2.0% per year
    
    Average 2.0% per year
  112




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 7.
    
    Asset Retirement Obligations
   2004
    
    
    2003Asset retirement obligation, beginning of year
    
    $
    2,188
    
    
    $
    3,090Increases in liabilities during the year related to:Acquisitions
    
    
    10,512
    
    
    
    Additions
    
    
    262
    
    
    
    744Revisions
    
    
    1,128
    
    
    
    Accretion expense
    
    
    867
    
    
    
    112Dispositions
    
    
    (121
    )
    
    
    (1,753
    )Liabilities settled during the year
    
    
    
    
    
    
    (5
    )Asset retirement obligation, end of year
    
    $
    14,836
    
    
    $
    2,188
 8.
    
    Bank indebtednessBank indebtedness represents the outstanding balance under lines of credit totaling $45,000,000
(2003  $34,650,000). The credit facility consists of two revolving lines of credit of
$36,000,000 and $5,000,000, and a demand subordinated debt facility of $4,000,000. Drawings on
the revolving facility bear interest at 1.6% above the banks prime lending rate and the
subordinated debt facility bears interest at prime plus 2.0%. Bankers acceptance fees are
originally set at 165 basis points and are subject to adjustment up or down prospectively, on a
three month basis as determined by the Trusts consolidated debt to cash flow ratio. Security is
provided by a first charge over all of the Trusts assets. The amount available under the
subordinated debt facility will decrease by $1,000,000 each month until April 30, 2005.The credit facilities are subject to review by the lenders. Such review is scheduled for
completion prior to May 31, 2005. The outcome of the review is not yet determinable.As at December 31, 2004, the Trust was not in compliance with certain non-financial covenants of
its credit facility. The Trust is seeking a waiver of these covenants from its lenders.
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 9.
    
    Capital Lease Obligation
 Description
    
    2004
    
    
    2003Capital lease bearing interest at 8.605%, repayable
monthly at $88,802, including interest. The lease
term is for 60 months, due October 1, 2007, with a
purchase option of $1,000,000 and secured by the
related equipment
    
    $
    3,385
    
    
    $
    4,125Capital lease that bore interest at 12.15%, repayable
monthly at $4,448 including interest. The lease term
was 24 months due December 19, 2004 with a purchase
option of $100 and secured by the related equipment
    
    
    
    
    
    
    443,385
    
    
    
    4,169Less current portion
    
    
    (805
    )
    
    
    (783
    )$
    2,580
    
    
    $
    3,386
 Interest expense includes $327,000 (2003  $358,000; 2002  $106,000) related to the capital
leases.10.
    
    Non-controlling interestOn January 19, 2005, the CICA issued EIC-151 Exchangeable Securities Issued by Subsidiaries of
Income Trusts that states that equity interests held by third parties in subsidiaries of an
income trust should be reflected as either non-controlling interest or debt in the consolidated
balance sheet unless they meet certain criteria. EIC-151 requires that the shares be
nontransferable in order to be classified as equity. The Trusts exchangeable shares are
transferable and, in accordance with EIC-151, have been reclassified to non-controlling interest
on the consolidated balance sheets. In addition, a portion of consolidated earnings before
non-controlling interest is reflected as a reduction to such earnings in the Trusts
consolidated statements of earnings and accumulated earnings. As required by the new accounting
standard prior periods have been retroactively restated.
 Enterra
    
    
    RMAC Exchangeable
    
    
    TotalExchangeable Shares
    
    
    Shares
    
    
    Exchangeable Shares
    
    
    AmountIssued pursuant to
Plan of Arrangement
    
    
    2,000,000
    
    
    
    
    
    
    
    2,000,000
    
    
    $
    3,465Exchanged for trust units
    
    
    (4,404
    )
    
    
    
    
    
    
    (4,404
    )
    
    
    (8
    )Non-controlling interest in
net earnings (loss)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (332
    )Balance at December 31, 2003
    
    
    1,995,596
    
    
    
    
    
    
    
    1,995,596
    
    
    
    3,125Issued on acquisition of
Rocky Mountain Energy Corp.
    
    
    
    
    
    
    341,882
    
    
    
    341,882
    
    
    
    6,147Exchanged for trust units
    
    
    (1,584,826
    )
    
    
    (199,438
    )
    
    
    (1,784,264
    )
    
    
    (6,331
    )Non-controlling interest in
net earnings
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    408Balance at December 31, 2004
    
    
    410,770
    
    
    
    142,444
    
    
    
    553,214
    
    
    $
    3,349
  114




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Enterra Energy Trust  Notes to Consolidated Financial Statements
    11.
    
    Unitholders EquityAuthorized Trust UnitsAn unlimited number of Trust Units may be issued pursuant to the Trust Indenture.Issued Trust Units
 Number ofUnits/Shares
    
    
    AmountBalance at December 31, 2001
    
    
    18,301,244
    
    
    $
    29,568Issued upon exercise of options and warrants
    
    
    51,406
    
    
    
    97Balance at December 31, 2002
    
    
    18,352,650
    
    
    $
    29,665Issued upon exercise of options and warrants
    
    
    2,598,906
    
    
    
    6,283Contributed surplus transferred on exercise of warrants
    
    
    
    
    
    
    347Issued pursuant to plan of arrangement:Shares exchanged for exchangeable shares and cancelled
    
    
    (2,000,000
    )
    
    
    (3,465
    )Shares exchanged for trust units and cancelled
    
    
    (18,951,556
    )
    
    
    (32,831
    )Trust units issued
    
    
    18,951,556
    
    
    
    32,831Issued for exchangeable shares
    
    
    4,404
    
    
    
    49Balance at December 31, 2003
    
    
    18,955,960
    
    
    $
    32,879Adopt fair value method of unit based compensation (note
3(d))
    
    
    
    
    
    
    646Issued pursuant to private placements
    
    
    2,699,400
    
    
    
    37,676Issued pursuant on acquisition of Rocky Mountain Energy
Corp.
    
    
    1,946,576
    
    
    
    34,999Issued for exchangeable shares
    
    
    1,824,864
    
    
    
    26,844Unit share issue costs
    
    
    
    
    
    
    (837
    )Balance at December 31, 2004
    
    
    25,426,800
    
    
    $
    132,207
  115




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 Contributed surplus
 Balance at December 31, 2002
    
    $
    65Value assigned to 200,000 warrants
    
    
    282Transfer on exercise of warrants
    
    
    (347
    )Balance at December 31, 2003
    
    $
    Trust unit option based compensation
    
    
    78Balance at December 31, 2004
    
    $
    78
 Trust unit optionsEnterra has granted trust unit options to directors, officers, employees and consultants of the
Trust and JED. Each trust unit option permits the holder to purchase one trust unit at the
stated exercise price. All options vest over a 3-year period and have a term of 5 years. At the
time of grant, the exercise price is equal to the market price.Prior to November 25, 2003, Enterra had granted options to purchase common shares to directors,
officers, employees and consultants. Each option permitted the holder to purchase one common
share of Enterra at the stated exercise price. All options vested over a 4-year period and had
a term of 5 years. At the time of grant, the exercise price was equal to the market price.
Pursuant to the Plan of Arrangement, a total of 899,453 options vested and were exercised at
prices ranging from $4.00 to $18.58.The following options have been granted:
 Weighted-Number of
    
    
    average exerciseOptions
    
    
    priceBalance at December 31, 2001
    
    
    800,000
    
    
    $
    4.00Options granted
    
    
    232,000
    
    
    
    5.30Options exercised
    
    
    (44,511
    )
    
    
    3.84Options cancelled
    
    
    (115,786
    )
    
    
    4.03Balance at December 31, 2002
    
    
    871,703
    
    
    $
    4.35Options granted
    
    
    31,500
    
    
    
    15.74Options exercised
    
    
    (899,453
    )
    
    
    4.74Options cancelled
    
    
    (3,750
    )
    
    
    4.41Balance at December 31, 2003
    
    
    
    
    
    $
    Options granted
    
    
    950,000
    
    
    
    14.22Balance at December 31, 2004
    
    
    950,000
    
    
    $
    14.22Exercisable at December 31, 2004
    
    
    
    
    
    $
    
 116




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 Estimated fair value of stock optionsThe estimated fair value of options was determined using the Black-Scholes model under the
following assumptions:
 2004
    
    
    2003
    
    
    2002Weighted-average fair value of options granted ($/option)
    
    $
    0.33
    
    
    $
    7.75
    
    
    $
    2.83Risk-free interest rate (%)
    
    
    3.8
    
    
    
    5.0
    
    
    
    5.0Estimated hold period prior to exercise (years)
    
    
    5
    
    
    
    5
    
    
    
    5Expected volatility (%)
    
    
    21
    
    
    
    50
    
    
    
    55Expected cash distribution yield (%)
    
    
    11
    
    
    Nil
    
    Nil
 Pro forma net earnings  fair value based method of accounting for optionsIn 2003, had the Trust recorded compensation cost for the Trusts unit-based compensation plan
based on the fair value at the grant date for awards made under the plan subsequent to January
1, 2002, consistent with the fair value method of accounting for stock-based compensation, the
Trusts earnings and earnings per unit for options granted in 2004 and 2003 would have
been as follows:
 2004
    
    
    2003
    
    
    2002Net earnings, as reported
    
    $
    14,027
    
    
    $
    5,430
    
    
    $
    4,881Deduct:Stock-based employee compensation expense determined
under fair value based method for all awards
    
    
    
    
    
    
    (631
    )
    
    
    (47
    )Pro forma net earnings
    
    $
    14,027
    
    
    $
    4,799
    
    
    $
    4,834Pro forma net earnings per unit  basic
    
    $
    0.62
    
    
    $
    0.26
    
    
    $
    0.26 diluted
    
    
    0.62
    
    
    $
    0.24
    
    
    $
    0.26
 Reconciliation of Earnings per Unit CalculationsFor the year ended December 31, 2004
 Weighted AverageNet Earnings
    
    
    Units Outstanding
    
    
    Per UnitBasic
    
    $
    14,027
    
    
    
    22,518,373
    
    
    $
    0.62Exchangeable shares / Non-controlling interest
    
    
    408
    
    
    
    490,530Options assumed exercised
    
    
    
    
    
    
    950,000Units assumed purchased
    
    
    
    
    
    
    (716,943
    )Diluted
    
    $
    14,435
    
    
    
    23,241,960
    
    
    $
    0.62
 117




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 For the year ended December 31, 2003
 Weighted AverageNet Earnings
    
    
    Units Outstanding
    
    
    Per UnitBasic
    
    $
    5,430
    
    
    
    18,751,634
    
    
    $
    0.29Exchangeable shares / Non-controlling interest
    
    
    (332
    )
    
    
    202,293Diluted
    
    $
    5,098
    
    
    
    18,953,968
    
    
    $
    0.27
 There were no options outstanding as at December 31, 2003.and therefore no dilutive effect on earnings
per unit.For the year ended December 31, 2002
 Weighted AverageNet Earnings
    
    
    Units Outstanding
    
    
    Per UnitBasic
    
    $
    4,881
    
    
    
    18,308,982
    
    
    $
    0.27Options assumed exercised
    
    
    
    
    
    
    1,607,998Units assumed purchased
    
    
    
    
    
    
    (1,091,766
    )Diluted
    
    $
    4,881
    
    
    
    18,825,214
    
    
    $
    0.26
 Warrants
 Number of
    
    
    WeightedWarrants
    
    
    Average PriceBalance, December 31, 2001
    
    
    1,100,000
    
    
    US$
    3.67Issued pursuant to debt financing
    
    
    100,000
    
    
    US$
    2.60Expired
    
    
    (1,000,000
    )
    
    US$
    3.50Balance, December 31, 2002
    
    
    200,000
    
    
    US$
    4.00Issued pursuant to debt financing agreement amendment
    
    
    200,000
    
    
    US$
    3.65Exercised pursuant to Plan of Arrangement
    
    
    (400,000
    )
    
    US$
    3.83Balance, December 31, 2003
    
    
    
    
    
    $
    
 During 2003, 200,000 warrants with a weighted average exercise price of $3.65 were granted to an
arms length United States based consulting firm in connection with a potential debt financing
in the United States. The fair value was determined using the Black Scholes Option Pricing model
using an interest rate of 5% and a volatility factor of 50%. At the May, 2003 shareholders
meeting, the terms were amended to provide for immediate vesting of these warrants as of the
April 16, 2002 date of the agreement. The estimated fair value of the warrants of $282,000 was
expensed in 2003.
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 Trust Unit Savings PlanIn 2004, the Trust established a Trust Unit Savings Plan whereby the Trust will match an
employees contributions to the plan to a maximum of 9.0% of their salary. Both the employees
and the Trusts contributions are used to purchase Trust Units on the NASDAQ National Markets
system. During the year the Trust expensed approximately $23,000 relating to the Trusts
contributions to the plan.12.
    
    Income TaxesThe income tax provision is calculated by applying Canadian federal and provincial statutory tax
rates to pre-tax income with adjustments as set out in the following table:
 2004
    
    
    2003
    
    
    2002Earnings before income taxes and
non-controlling interest
    
    $
    14,415
    
    
    $
    7,220
    
    
    $
    5,878Combined federal and provincial income tax rate
    
    
    38.87
    %
    
    
    40.75
    %
    
    
    42.12
    %Computed income tax provision
    
    
    5,603
    
    
    
    2,942
    
    
    
    2,476Increase (decrease) resulting from:Interest component of trust distributions
    
    
    (7,038
    )
    
    
    (723
    )
    
    
    Resource allowance
    
    
    (4,669
    )
    
    
    (3,260
    )
    
    
    (1,627
    )Non-deductible crown royalties, net of ARTC
    
    
    5,239
    
    
    
    5,412
    
    
    
    1,313Value of warrants expensed for book purposes
    
    
    
    
    
    
    115
    
    
    
    Effect of change in tax pools
    
    
    
    
    
    
    (1,247
    )
    
    
    Effect of reduction in corporate tax rates
    
    
    
    
    
    
    (1,579
    )
    
    
    Non-taxable portion of capital gains
    
    
    
    
    
    
    
    
    
    
    (1,311
    )Capital taxes
    
    
    260
    
    
    
    134
    
    
    
    132Other
    
    
    585
    
    
    
    328
    
    
    
    14$
    (20
    )
    
    $
    2,122
    
    
    $
    997
 The components of the net future income tax liability at December 31 were as follows:
 2004
    
    
    2003Future income tax assets:Non-capital loss carry-forwards
    
    $
    12,127
    
    
    $
    Asset retirement obligation
    
    
    4,988
    
    
    
    760Unit issue costs
    
    
    179
    
    
    
    399$
    17,294
    
    
    $
    1,159Future income tax liabilities:Property and equipment
    
    
    39,422
    
    
    
    15,098Net future income tax liability
    
    $
    22,128
    
    
    $
    13,939
 Non-capital loss carry-forwards expire from time to time to 2011.
 13.
    
    Financial instrumentsThe Trusts financial instruments recognized on the consolidated balance sheets include cash,
accounts receivable, accounts payable and accrued liabilities, distributions payable to
unitholders, income taxes payable, bank indebtedness and long-term debt. The fair values of
financial instruments other than the capital lease approximate their carrying amounts due to the
short-term nature of the instruments. The carrying value of bank indebtedness approximates its
fair value due to floating interest terms; the fair value of the capital lease approximates its
carrying value due to current rates for comparable terms of long-term debt.
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 Due to the nature of its operation, the Trust is exposed to fluctuations in commodity prices,
foreign-currency exchange rates, interest rates and credit risk. The Trust recognizes these
risks and manages its operations to minimize the exposure to the extent practical and, to a
lesser extent, using derivative instruments. The Trust uses non-exchange traded forwards, swaps
and options, which may be settled in cash or by delivery of the
physical commodity. Management monitors the Trusts exposure to the above risks and regularly
reviews its derivative activities and all outstanding positions.
 (a)
    
    Commodity prices risksThe Trusts most significant market risk exposure relates to crude oil prices fluctuation.
Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC
actions, political events and supply and demand fundamentals.To a lesser extent the Trust is also exposed to natural gas price movements. Natural gas
prices are generally influenced by North American supply and demand, and to a lesser extent
local market conditions.The Trust has previously entered into derivative financial instruments and fixed price
physical contracts to minimize the risk of exposure to fluctuations in the crude oil and
natural gas prices. At December 31, 2004, the Trust did not have any derivative financial
instruments or fixed price physical sales contracts in place.(b)
    
    Foreign currency exchange riskThe Trust is exposed to foreign currency fluctuations as crude oil and natural gas prices
received are referenced to U.S. dollar denominated prices.(c)
    
    Credit riskA substantial portion of the Trusts accounts receivable are with customers and joint
venture partners in the oil and gas industry and are subject to normal industry credit
risks. Purchasers of the Trusts natural gas, crude oil and natural gas liquids are subject
to an internal credit review to minimize the risk of non-payment.(d)
    
    Interest rate riskInterest rate risk exists principally with respect to our indebtedness that bears interest
at floating rates. At December 31, 2004, the Trust had $43,930,000 of indebtedness bearing
interest at floating rates and $3,386,000 of capital lease bearing interest at a fixed rate.
 14.
    
    CommitmentsThe Trust has commitments for the following payments over the next five years and thereafter:
 2005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    2010Minimum capital
lease payments
    
    $
    806
    
    
    $
    877
    
    
    $
    1,702
    
    
    $
    
    
    
    $
    
    
    
    $
    Imputed interest
    
    
    260
    
    
    
    188
    
    
    
    97
    
    
    
    
    
    
    
    
    
    
    
    Capital lease
obligations
    
    
    1,066
    
    
    
    1,065
    
    
    
    1,799
    
    
    
    
    
    
    
    
    
    
    
    Rental payments
re-office space
    
    
    796
    
    
    
    741
    
    
    
    640
    
    
    
    661
    
    
    
    662
    
    
    
    28$
    1,862
    
    
    $
    1,806
    
    
    $
    2,439
    
    
    $
    661
    
    
    $
    662
    
    
    $
    28
 120




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 During 2004 total rental expense was $81,339 (2003 - $
299,000; 2002 - $241,000).15.
    
    ContingenciesOn October 24, 2003, a statement of claim was filed with the Court of Queens Bench of Alberta
against Enterra in the amount of approximately $12.0 million or as proven by trial. The claimant
is requesting the Trust complete a property purchase that Enterra had ended negotiations for in
2003. The Trust has filed a statement of defense and a counter claim. At December 31, 2004,
the eventual outcome of this claim is not determinable.16.
    
    GuaranteesThe Trust has indemnified all of the directors and officers of the Trust and all the officers,
directors, shareholders, employees and agents of JED. There is no pending litigation or
proceeding for which a claim is being sought, nor is the Trust aware of any threatened
litigation that may result in claims.17.
    
    Subsequent events
 (a)
    
    On January 26, 2005 the Trust closed an acquisition of petroleum and natural gas
properties for cash consideration of $12.3 million. At December 23, 2004, the Trust had
made a refundable deposit on the property purchased in the amount of $2.4 million.(b)
    
    The Trust has a bonus plan that was presented for unitholder approval at the 2005
annual general meeting. As the payment of the bonus was subject to unitholder approval it
was not accrued for in the 2004 financial statements. The plan was approved by the
Unitholders at the 2005 annual meeting resulting in the payment of a $1.6 million bonus in
2005 to officers and former officers, directors, employees and consultants of the Trust.(c)
    
    On February 20, 2005 the Trust completed a private placement of 500,000 Trust Units at
a price of US$19.00 per unit for gross proceeds of US $9.5 million.(d)
    
    On February 25, 2005 the Trust entered into a Letter of Intent with Rocky Mountain Gas,
Inc. for the Trust to acquire all the issued and outstanding shares of Rocky Mountain Gas,
Inc. On June 1, 2005, the acquisition closed for consideration of approximately $23.8
million, including $0.3 million of transaction cost. The consideration consisted of
736,842 exchangeable shares (exchangeable on a one-to-one basis into trust units) valued at
$16.7 million, 275,474 trust units valued at $6.3 million and $0.6 million in cash.(e)
    
    On April 27, 2005, the Trust announced an arrangement with Kingsbridge Capital Limited
whereby Kingsbridge has committed to purchase U.S.$100 million Enterra trust units. The
Trust is not obligated to access any of the capital available under this commitment yet has
an option to draw on this commitment through installments for a period of 24 months or
until the $100 million is fully drawn. In conjunction with the agreement, Kingsbridge was
granted 301,000 warrants to purchase Trust Units at initially U.S.$25.77 per trust unit.(f)
    
    On May 31, 2005, the Trust and High Point Resources Inc. (High Point) entered into an
agreement for the acquisition by the Trust of all of the issued and outstanding shares of
High Point. On August 17, 2005, the acquisition closed for consideration of approximately
$201.0 million, including $1.3 million of transaction cost. In addition the Trust assumed
$75 million in debt. The consideration consisted of 7,490,898 trust units valued at $168.5
million and 1,407,177 exchangeable shares (exchangeable on a one-to-one basis into trust
units) valued at $31.7 million.(g)
    
    In August, 2005 the Trust resolved the statement of claims referred to in note 15 at no
cost to the Trust.
 121




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 18.
    
    Differences between Generally Accepted Accounting Principles in Canada and the United States
of AmericaThe Trusts consolidated financial statements have been prepared in Canadian Dollars and in
accordance with generally accepted accounting principles in Canada (Canadian GAAP), which
differ in some respects from those in the United States of America (U.S. GAAP). Any
differences in accounting principles as they pertain to the consolidated financial statements as
at December 31, 2004 and 2003 and for each of the years in the three year period ended December
31, 2004 were insignificant except as described below:
 (a)
    
    Property and equipmentUnder Canadian GAAP, the Trust performs an impairment test that limits the capitalized costs
of its oil and natural gas assets to the discounted estimated future net revenue from proved
and probable oil and natural gas reserves using forecasted prices plus the costs of unproved
properties less impairment. The discount rate used is a risk free interest rate. Under
U.S. GAAP, the full cost method of accounting for oil and natural gas activities require the
Trust to perform an impairment test using after tax future net revenue from proved oil and
natural gas reserves discounted at 10%. The prices and costs used under the U.S. GAAP
ceiling test are those in effect at year-end. Where the amount of a ceiling test write-down
under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge
for depletion will differ in the year and subsequent years.There were ceiling test impairments recognized under U.S. GAAP at December 31, 2004 and
2001. No impairment existed at December 31, 2003 or 2002. At December 31, 2004 the Trust
recognized a U.S. GAAP ceiling test write-down of $10.0 million ($6.3 million after tax) and
at December 31, 2001 a write-down of $28.7 million ($17.5 million after tax).As a result of these write-downs, the 2004 combined depletion and ceiling test expense under
U.S. GAAP was higher than depletion for Canadian GAAP by $8.0 million ($4.9 million after
tax) and lower for 2003 and 2002 (2003  $5.7 million; ($3.4 million after tax); 2002  $3.6
million; ($2.1 million after tax)).(b)
    
    Financial instrumentsPrior to the Trust adopting AcG-13 in 2004 for Canadian GAAP purposes, a difference existed
in that under U.S. GAAP, SFAS 133, Accounting for Derivative Instruments and Hedging
Activities requires that all derivative instruments be recorded on the consolidated balance
sheet as either an asset or liability measured at fair value, and requires that changes in
fair value be recognized in income unless specific hedge accounting criteria are met. Hedge
accounting requires that an entity formally document, designate and assess the effectiveness
of derivative instruments before it can use this accounting treatment.Effective January 1, 2004, the Trust adopted Canadian standards with respect to financial
instruments which are similar to SFAS 133. Upon adoption of the Canadian standards the fair
value of the Trusts financial instruments was recorded on the balance sheet at January 1,
2004 with a corresponding deferred charge, which was fully amortized in 2004 being the term
of the contracts. The $1.0 million ($0.6 million after tax) amortization of the deferred
charge recorded in 2004 under Canadian GAAP has been reversed as this amount was recognized
in 2003 under U.S. GAAP.The Trust did not have any derivative instruments or hedging contracts outstanding at
December 31, 2004. At December 31, 2003 for U.S. GAAP purposes, the Trust recognized the
negative fair value of outstanding financial instruments of $1.0 million ($0.6 million
after tax). The financial instruments were not formally documented and designated as
hedging relationships and as such were not eligible for hedge accounting treatment.At December 31, 2002 under Canadian GAAP, the Trust had a deferred gain of $0.2 million
($0.1 million after taxes) that was being amortized over the term of the contract and
resulted from the settlement of a
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 fixed contract. Under U.S. GAAP, this gain, net of income
taxes, was included in income in 2001, as it did not qualify for hedge accounting under SFAS
133.The Trust has routinely entered into commodity contracts to minimize its exposure to
fluctuations in commodity prices relating to its future sales of crude oil. While such
contracts meet the criteria of SFAS 133 as derivatives they are eligible for the normal
purchase and sale exception under SFAS 138, Accounting for Certain Derivative Instrument
and Certain Hedging Activities  An Amendment of SFAS 133. Contracts that meet the
criteria for exception are not recognized on the balance sheet as either an asset or
liability measured at fair value. The negative fair value of such contracts at December 31,
2003 was $0.7 million (2002  $0.6 million). There were no such contracts outstanding at
December 31, 2004.(c)
    
    Unit-based compensationPrior to 2004, the Trust accounted for unit-based compensation under the recognition and
measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and
related Interpretations. No stock-based compensation costs were reflected in the 2003 and
2002 net earnings for options granted to employees, as all options granted to employees had
an exercise price equal to the market value of Trust Units on the date of grant.Effective January 1, 2004, the Trust adopted the fair value recognition provisions of SFAS
123, Accounting for Stock-Based Compensation. Under the modified prospective method of
adoption selected by the Trust, compensation cost recognized in 2004 is the same as that which would
have been recognized had the recognition provisions of SFAS 123 been applied from its
original effective date. Results for prior years have not been restated.Under Canadian GAAP, on January 1, 2004 the Trust adopted similar standards as SFAS 123. On
adoption in 2004, $0.6 million of accumulated stock-based compensation expense for the
period from January 1, 2002 to the date of adoption was charged to accumulated earnings and
an offsetting decrease entered to unitholders equity. Under U.S. GAAP there is no such
charge.The following table illustrates the effect on net earnings and earnings per share if the
fair value based method had been applied to all outstanding and unvested awards to employees
in each period.
 2003
    
    
    2002Net earnings, as reported  U.S. GAAP
    
    $
    6,510
    
    
    $
    6,748Less: Total stock-based employee compensation
expense determined under fair value based method for
all awards
    
    
    (737
    )
    
    
    (110
    )Pro forma net earnings
    
    $
    5,773
    
    
    $
    6,638Earnings per unit:Basic  as reported
    
    $
    0.34
    
    
    $
    0.37Basic  pro forma
    
    $
    0.30
    
    
    $
    0.36Diluted  as reported
    
    $
    0.34
    
    
    $
    0.36Diluted  pro forma
    
    $
    0.30
    
    
    $
    0.35
 During 2001, the Trust granted 119,500 stock options to non-employees. The value
associated with these stock options was $0.1 million for U.S. GAAP purposes. There was no
value assigned to these non-employee options for Canadian GAAP purposes.
 123




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 (d)
    
    EarningsUnder U.S. GAAP interest and amortization of deferred financing charges would be presented
in the non-operating section of the statement of earnings.(e)
    
    Comprehensive IncomeThere are no items that would be part of Comprehensive Income other than net income.(f)
    
    Asset Retirement Obligations (ARO)Effective January 1, 2004, the Trust retroactively adopted the Canadian standards for
accounting for asset retirement obligations and prior periods were restated. These
standards are equivalent to SFAS No. 143, Accounting for Asset Retirement Obligations,for
fiscal periods beginning on or after January 1, 2003 except that the transitional provisions
between Canadian and U.S. GAAP differ, as Canadian GAAP requires a restatement of
comparative amounts whereas U.S. GAAP does not allow restatement.The adoption of SFAS 143 in 2003 resulted in a cumulative effect of change in accounting
principle in the consolidated statement of earnings of a loss of $1.1 million, net of income
taxes of $0.6 million. Under the U.S. GAAP accounting rules, the Trusts results would have
been as follows:
 2002Net earnings   US GAAPAs reported
    
    $
    6,748Cumulative effect of change in accounting principleDepreciation, depletion, amortization and accretion, net of tax
    
    
    (202
    )Adjusted
    
    $
    6,546Earnings per unit/shareBasic as reported
    
    $
    0.37Adjusted
    
    $
    0.36Diluted as reported
    
    $
    0.36Adjusted
    
    $
    0.35
 Had SFAS 143 been applied during all periods presented, the asset retirement obligation
would have been reported as follows for U.S. GAAP:
 January 1, 2002
    
    $
    1,913December 31, 2002
    
    $
    3,090December 31, 2003
    
    $
    2,188
 In September 2004, the SEC issued SAB 106 concerning SFAS 143. The bulletin outlines the
requirement to eliminate the impact of asset retirement from the estimated present value of
net revenues prior to conducting the ceiling test calculation. The requirement is made
necessary as a result of the adoption of SFAS 143 by the Trust. The Trust has complied with
the requirement of SAB 106.
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Enterra Energy Trust  Notes to Consolidated Financial Statements
 (g)
    
    Unitholders Mezzanine equityUnder Canadian GAAP, the Trust Units are considered to be permanent equity and are presented
as Unitholders Capital. A U.S. GAAP difference exists due to the redemption feature
attached to each trust unit. The Trust Units are redeemable at the option of the holder
based on the lesser of 90% of the average market trading price of the trust units for the 10
trading days after the date of redemption or the closing market price of the trust units on
the date of redemption. Trust units can be redeemed to a cash limit of $100,000 per year
or a greater limit at the discretion of the Trust. Redemptions in excess of the cash limit
shall be satisfied first by the issuance of Series A Notes by a subsidiary of the Trust and
second by issuance of promissory notes by the Trust.Previously, U.S. GAAP accounting treatment for trust units was based on the assessment that
the redemption feature was sufficiently restrictive to avoid classification as mezzanine
equity. This assessment was based upon industry practice and standard industry
interpretation of EITF D-98: Classification and Measurement of Redeemable Securities
prevailing at the date of the prior year balance sheet. Subsequently industry practice has
changed and the Trust has concluded that the redemption feature causes the Trust Units to be
classified as mezzanine equity.Accordingly the Trust has reclassified its Unitholders Capital, both trust units and
exchangeable shares, as Mezzanine Equity to meet U.S. GAAP requirements. Mezzanine Equity
is valued at an amount equal to the redemption value of the trust units at the balance sheet
date. Prior year comparative balances have been restated to conform to this presentation.
Any increase or decrease in the redemption value during a period is charged to accumulated
earnings and reflected in the calculation of net income per trust unit.As at December 31, 2004, Unitholders Capital was reduced by $132.0 million and
Non-controlling interest was reduced by $3.3 million (2003 - $32.8 million and $3.1 million,
respectively) and the redemption value of the trust units and exchangeable units of $529.8
million (2003 - $261.8 million) was recorded as Mezzanine Equity. The increase in the
redemption value of the trust units and exchangeable units for the year ended December 31,
2004 of $189.9 million (2003 - $225.4 million, 2002 - Nil) was recorded as a reduction in
accumulated earnings.As a result of adopting this presentation as at November 25, 2003, the date the Trust was
formed, Trust Unitholders Capital decreased by $32.8 million, Non-controlling interest
decreased by $3.5 million, Mezzanine Equity increased by $245.8 million and accumulated
earnings decreased by $209.4 million.(h)
    
    Non-controlling interest  Exchangeable Securities Issued by Subsidiaries of
Income Trusts pursuant to EIC-151On January 19, 2005, the CICA issued EIC-151 Exchangeable Securities Issued by
Subsidiaries of Income Trusts that states that equity interests held by third parties in
subsidiaries of an income trust should be reflected as either non-controlling interest or
debt in the consolidated balance sheet unless they meet certain criteria. EIC-151 requires
that the shares be nontransferable to be classified as equity. The Trusts exchangeable
shares are transferable and, in accordance with EIC-151, have been reclassified to
non-controlling interest on the Canadian GAAP consolidated balance sheets.Since the Enterra exchangeable shares (note 10) were not initially recorded at fair
value, subsequent exchanges for Trust Units are measured at the fair value of the Trust
Units issued. The amounts in excess of the carrying value of exchangeable shares are
allocated to property, plant and equipment, to the extent possible, with any excess amounts
being allocated to goodwill. In addition, a portion of consolidated earnings before
non-controlling interest is reflected as a reduction to such earnings in the Trusts
consolidated statements of earnings and accumulated earnings.
 125




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 This new Canadian GAAP standard creates several differences with U.S. GAAP as under U.S.
GAAP the trust units and exchangeable shares are considered mezzanine equity. The
adjustments made under Canadian GAAP to implement EIC-151 as detailed in note 3(d) are
reversed under U.S. GAAP.(i)
    
    Balance sheetsThe adjustments using U.S. GAAP would result in the following changes to the consolidated
balance sheets of the Trust:
 2004
    
    
    2003Cdn. GAAP
    
    
    U.S. GAAP
    
    
    Cdn. GAAP
    
    
    U.S. GAAP.(restated)
    
    
    
    
    
    
    (restated)
    
    
    (restated)Assets:Current assets
    
    $
    20,910
    
    
    $
    20,910
    
    
    $
    9,270
    
    
    $
    9,270Deposit on land purchase
    
    
    2,400
    
    
    
    2,400
    
    
    
    2,015
    
    
    
    2,015Property and Equipment
(a)(f)(h)
    
    
    148,458
    
    
    
    117,940
    
    
    
    105,260
    
    
    
    84,288Goodwill (h)
    
    
    49,270
    
    
    
    29,991
    
    
    
    37
    
    
    
    Deferred financing charges
    
    
    90
    
    
    
    90
    
    
    
    123
    
    
    
    123$
    221,128
    
    
    $
    171,331
    
    
    $
    116,705
    
    
    $
    95,696Liabilities:Current liabilities
    
    $
    63,264
    
    
    $
    63,264
    
    
    $
    49,522
    
    
    $
    49,522Capital lease
    
    
    2,580
    
    
    
    2,580
    
    
    
    3,386
    
    
    
    3,386Financial derivative
liabilities (b)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    958Future income taxes (a) (b)
(f) (h)
    
    
    22,128
    
    
    
    10,614
    
    
    
    13,939
    
    
    
    5,644Asset retirement obligation (f)
    
    
    14,836
    
    
    
    14,836
    
    
    
    2,188
    
    
    
    2,188102,808
    
    
    
    91,294
    
    
    
    69,035
    
    
    
    61,698Non-controlling interest (h)
    
    
    3,349
    
    
    
    
    
    
    
    3,125
    
    
    
    Mezzanine equity (g)
    
    
    
    
    
    
    529,764
    
    
    
    
    
    
    
    261,810Unitholders equity:Unitholders equity (g)
    
    
    132,207
    
    
    
    
    
    
    
    32,879
    
    
    
    Contributed surplus
    
    
    78
    
    
    
    78
    
    
    
    
    
    
    
    Accumulated earnings (deficit)
    
    
    27,498
    
    
    
    (404,993
    )
    
    
    14,117
    
    
    
    (225,361
    )Accumulated distributions
    
    
    (44,812
    )
    
    
    (44,812
    )
    
    
    (2,451
    )
    
    
    (2,451
    )114,971
    
    
    
    80,037
    
    
    
    44,545
    
    
    
    33,998$
    221,128
    
    
    $
    171,331
    
    
    $
    116,705
    
    
    $
    95,696
 126




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 (j)
    
    Income statementsThe adjustments using U.S. GAAP would result in the following changes to the consolidated
statement of earnings of the Trust:
 2004
    
    
    2003
    
    
    2002(restated)
    
    
    (restated)
    
    
    (restated)Net earnings under Canadian GAAP
    
    $
    14,027
    
    
    $
    5,430
    
    
    $
    4,881Adjustments:Hedging gain (b)
    
    
    
    
    
    
    (238
    )
    
    
    (524
    )Related income taxes
    
    
    
    
    
    
    97
    
    
    
    221Depletion and accretions (a)(h)
    
    
    (7,467
    )
    
    
    5,676
    
    
    
    3,583Related income taxes
    
    
    2,802
    
    
    
    (2,312
    )
    
    
    (1,509
    )Implementation of ARO for Canadian GAAP (f)
    
    
    
    
    
    
    (141
    )
    
    
    141Related income taxes
    
    
    
    
    
    
    46
    
    
    
    (45
    )Unrealized loss on financial instruments (b)
    
    
    958
    
    
    
    (958
    )
    
    
    Related income taxes
    
    
    (390
    )
    
    
    390
    
    
    
    Non  controlling interest (h)
    
    
    408
    
    
    
    (332
    )Net earnings before undernoted items under
U.S. GAAP
    
    
    10,338
    
    
    
    7,658
    
    
    
    6,748Cumulative effect of change in accounting
principle  FAS #143 (f)
    
    
    
    
    
    
    (1,756
    )
    
    
    Related income taxes
    
    
    
    
    
    
    608
    
    
    
    Net earnings under U.S. GAAP before change in
redemption value of trust units
    
    
    10,338
    
    
    
    6,510
    
    
    
    6,748Change in redemption value of trust units
    
    
    (189,970
    )
    
    
    (225,424
    )
    
    
    Net earnings under U.S. GAAP after change in
redemption value of trust units
    
    
    ($179,632
    )
    
    
    ($218,914
    )
    
    $
    6,748Net earnings per unit/share before under
noted items under US GAAP:Basic
    
    $
    0.44
    
    
    $
    0.40
    
    
    $
    0.37Diluted
    
    $
    0.44
    
    
    $
    0.40
    
    
    $
    0.36Net earnings per unit/share relating to
change in accounting principle:Basic
    
    
    
    
    
    $
    (0.06
    )
    
    
    Diluted
    
    
    
    
    
    $
    (0.06
    )
    
    
    Net earnings per unit/share under US GAAP
-before change in redemption value of trust
units:Basic
    
    $
    0.44
    
    
    $
    0.34
    
    
    $
    0.37Diluted
    
    $
    0.44
    
    
    $
    0.34
    
    
    $
    0.36Net earning (loss) per unit/share under U.S.
GAAP -after change in redemption value of
Trust Units:Basic
    
    $
    (7.70
    )
    
    $
    (11.55
    )
    
    $
    0.37Diluted
    
    $
    (7.70
    )
    
    $
    (11.55
    )
    
    $
    0.37
 127




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 (k)
    
    Additional disclosure under U.S. GAAP
 As at December 31
    
    2004
    
    
    2003Components of accounts receivableTrade
    
    $
    8,095
    
    
    $
    8,475Accruals
    
    
    9,014
    
    
    
    267Allowance for doubtful accounts
    
    
    (1,496
    )
    
    
    $
    15,613
    
    
    $
    8,742
 As at December 31
    
    2004
    
    
    2003Components of prepaid expensePrepaid expenses
    
    $
    278
    
    
    $
    263Funds on deposit
    
    
    240
    
    
    
    199$
    518
    
    
    $
    462
 As at December 31
    
    2004
    
    
    2003Components of accounts payableAccounts payable
    
    $
    3,928
    
    
    $
    10,046Accrued liabilities
    
    
    4,642
    
    
    
    2,162$
    8,570
    
    
    $
    12,208
 (l)
    
    Pro forma information (unaudited)The following unaudited pro forma summary information provides an indication of what the
Trusts results of operation might have been had the acquisition of Rocky Mountain Energy
Corp. (note 5) taken place on January 1, 2004 and 2003 under both Canadian and U.S. GAAP.
 2004
    
    
    2003(unaudited)
    
    
    (unaudited)Cdn. GAAP
    
    
    U.S. GAAP
    
    
    Cdn. GAAP
    
    
    U.S. GAAPRevenue
    
    $
    122,474
    
    
    $
    122,474
    
    
    $
    88,894
    
    
    $
    88,894Net earnings before
change in
redemption value of
trust units and the
effect of accounting changes
    
    $
    10,429
    
    
    $
    12,583
    
    
    $
    5,092
    
    
    $
    6,824Cumulative effect
of accounting
changes
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    (1281
    )Net earnings (loss)
    
    $
    10,429
    
    
    $
    (177,387
    )
    
    $
    5,092
    
    
    $
    (247,098
    )Earnings (loss) per
trust unit  basic
    
    $
    0.46
    
    
    $
    (7.08
    )
    
    $
    0.27
    
    
    $
    (11.63
    )Earnings (loss) per
trust unit 
diluted
    
    $
    0.46
    
    
    $
    (7.02
    )
    
    $
    0.25
    
    
    $
    (11.63
    )
 128




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Enterra Energy Trust  Notes to Consolidated Financial Statements
 19.
    
    New Accounting PronouncementsThe following standards issued by the FASB do not impact us at this time:
 (a)
    
    In December 2004, FASB issued statement 123R Share Based Payments that establishes
the standards for the accounting for transactions in which an entity exchanges its equity
for goods or services. The statement focused primarily on the accounting for transactions
in which an entity obtains employee services in exchange for share-based consideration.
The statement establishes a standard to account for such transactions using a
fair-value-based method. The effective date for implementation of this standard would be
the first interim or annual period beginning on or after June 15, 2005 for transactions
entered into on or after the effective date. Management has not yet assessed the impact if
any, of this standard on its consolidated financial statements.(b)
    
    In December 2004, SFAS issued statement No. 153 Exchanges for Non-monetary Assets  an
amendment of APB Opinion No. 29. The statement eliminates the exception for non-monetary
exchanges of similar productive assets and replaces it with a general exception for
exchanges of non-monetary exchanges that do not have commercial substance. A non-monetary
exchange is defined as having commercial substance if the future cash flows of the entity
are expected to change significantly as a result of the exchange. Management does not
expect this statement to have a material impact on this consolidated financial statementsThe Trust will continue to assess the applicability of these standards in the future.
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Enterra Energy Trust  Supplemental Disclosure About Oil and Gas Producing Activities (Unaudited)
  (a)
    
    Capitalized CostsThe aggregate amounts of costs capitalized for gas and oil producing activities, and related
aggregate amounts of accumulated depreciation, depletion and amortization at December 31, 2004,
2003 and 2002 as follows:
 2004
    
    
    2003
    
    
    2002Capitalized costs of:Proved properties being amortized
    
    $
    181,778
    
    
    $
    112,220
    
    
    $
    80,138Undeveloped land not being amortized
    
    
    3,430
    
    
    
    5,037
    
    
    
    3,967Total capitalized costs
    
    
    185,208
    
    
    
    117,257
    
    
    
    84,105Less accumulated depletion,
depreciation, future site restoration
and amortization
    
    
    (67,268
    )
    
    
    (32,969
    )
    
    
    (15,797
    )Net Capitalized costs
    
    $
    117,940
    
    
    $
    84,288
    
    
    $
    68,308
 The following costs were incurred in oil and gas-producing activities during the years ended
December 31, 2004, 2003 and 2002:
 2004
    
    
    2003
    
    
    2002Property acquisition costs: (1)Proved properties
    
    $
    45,265
    
    
    $
    
    
    
    $
    512Unproved properties
    
    
    8,062
    
    
    
    8,028
    
    
    
    3,643Exploration costs
    
    
    4,289
    
    
    
    766
    
    
    
    168Development costs
    
    
    8,800
    
    
    
    42,503
    
    
    
    31,558Total costs incurred
    
    $
    66,416
    
    
    $
    51,297
    
    
    $
    35,881
 (1)
    
    Includes costs related to corporate acquisitions.
 (b)
    
    Reserve Quantity InformationEstimated net quantities of proved gas and oil (including condensate) reserves at December 31,
2004, 2003 and 2002, and changes in the reserves during those years, are shown in the following
two tables. Reserve volumes are reported on both net and gross of royalties basis.
 2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Net
    
    
    Net
    
    
    Net
    
    
    Gross
    
    
    Gross
    
    
    GrossProved developed and undeveloped
reserves  Oil (mboe)At January 1
    
    
    4,457
    
    
    
    4,193
    
    
    
    3,472
    
    
    
    5,149
    
    
    
    5,234
    
    
    
    4,127Changes in reserves:Extensions, discoveries and
other additions
    
    
    139
    
    
    
    1,962
    
    
    
    2,054
    
    
    
    158
    
    
    
    2,267
    
    
    
    2,564Revisions of previous estimates
    
    
    (96
    )
    
    
    (214
    )
    
    
    (195
    )
    
    
    65
    
    
    
    (458
    )
    
    
    (61
    )Production
    
    
    (1,672
    )
    
    
    (1,062
    )
    
    
    (446
    )
    
    
    (2,161
    )
    
    
    (1,406
    )
    
    
    (533
    )Purchases of oil in place
    
    
    2,363
    
    
    
    98
    
    
    
    
    
    
    
    2,684
    
    
    
    113Sales of oil in place
    
    
    (21
    )
    
    
    (520
    )
    
    
    (692
    )
    
    
    (24
    )
    
    
    (601
    )
    
    
    (863
    )At December 31
    
    
    5,170
    
    
    
    4,457
    
    
    
    4,193
    
    
    
    5,871
    
    
    
    5,149
    
    
    
    5,234
 130




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Enterra Energy Trust  Supplemental Disclosure About Oil and Gas Producing Activities (Unaudited)
 Proved developed reserves  OilAt January 1
    
    
    4,457
    
    
    
    3,239
    
    
    
    3,131
    
    
    
    5,149
    
    
    
    3,952
    
    
    
    3,734At December 31
    
    
    5,069
    
    
    
    4,457
    
    
    
    3,239
    
    
    
    5,755
    
    
    
    5,149
    
    
    
    3,952Proved developed and undeveloped
reserves  Gas (mboe)At January 1
    
    
    744
    
    
    
    1,706
    
    
    
    1,342
    
    
    
    1018
    
    
    
    2,174
    
    
    
    1,794Changes in reserves:Extensions, discoveries and
other additions
    
    
    25
    
    
    
    462
    
    
    
    752
    
    
    
    28
    
    
    
    534
    
    
    
    939Revisions of previous estimates
    
    
    (167
    )
    
    
    (167
    )
    
    
    (70
    )
    
    
    (124
    )
    
    
    (183
    )
    
    
    (176
    )Production
    
    
    (322
    )
    
    
    (322
    )
    
    
    (263
    )
    
    
    (416
    )
    
    
    (427
    )
    
    
    (314
    )Purchases of gas in place
    
    
    637
    
    
    
    23
    
    
    
    
    
    
    
    723
    
    
    
    26Sales of gas in place
    
    
    
    
    
    
    (958
    )
    
    
    (55
    )
    
    
    
    
    
    
    (1,106
    )
    
    
    (69
    )At December 31
    
    
    917
    
    
    
    744
    
    
    
    1,706
    
    
    
    1,229
    
    
    
    1,018
    
    
    
    2,174Proved developed reserves  GasAt January 1
    
    
    744
    
    
    
    1,606
    
    
    
    1,233
    
    
    
    1,018
    
    
    
    2,038
    
    
    
    1,650At December 31
    
    
    909
    
    
    
    744
    
    
    
    1,606
    
    
    
    1,219
    
    
    
    1,018
    
    
    
    2,038
 (c)
    
    Standardized Measure of Discounted Future Net Cash Flows and Changes ThereinThe following tabulation has been prepared in accordance with the FASBs rules for disclosure of
a standardized measure of discounted future net cash flows relating to proved gas and oil
reserve quantities owned by the Trust.
 2004
    
    
    2003
    
    
    2002Future cash inflows (1)
    
    $
    260,750
    
    
    $
    207,948
    
    
    $
    309,953Less:Future development costs
    
    
    (677
    )
    
    
    (200
    )
    
    
    (7,487
    )Future production, royalty and abandonment costs
    
    
    (145,563
    )
    
    
    (83,332
    )
    
    
    (109,383
    )Future income tax expense
    
    
    (18,272
    )
    
    
    (15,174
    )
    
    
    (54,959
    )Future cash flows
    
    
    96,238
    
    
    
    109,242
    
    
    
    138,124Less annual discount (10% a year)
    
    
    (15,118
    )
    
    
    (18,683
    )
    
    
    (31,453
    )Standardized measure of discounted future net cash flows
    
    $
    81,120
    
    
    $
    90,559
    
    
    $
    106,671
 (1)
    
    Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year end.
 In the foregoing determination of future cash inflows, sales prices for gas and oil were
based on contractual arrangements or market prices at year-end. Future costs of developing and
producing the proved gas and oil reserves reported at the end of each year shown were based on
costs determined at each such year end, assuming the continuation of existing economic
conditions. Future income taxes were computed by applying the appropriate year-end or future
statutory tax rate to future pretax net cash flows, less the tax basis of the properties
involved, and giving effect to tax deductions, permanent differences and tax credits.It is not intended that the FASBs standardized measure of discounted future net cash flows
represent the fair market value of the Trusts proved reserves. The Trust cautions that the
disclosures shown are based on estimates of proved reserve quantities and future production
schedules that are inherently imprecise and subject to revision, and the 10 percent discount
rate is arbitrary. In addition, costs and prices as of the measurement date are used in the
determinations, and no value may be assigned to probable or possible reserves.The following tabulation is a summary of changes between the total standardized measure of
discounted future net cash flows at the beginning and end of each year.
 131




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Enterra Energy Trust  Supplemental Disclosure About Oil and Gas Producing Activities (Unaudited)
 2004
    
    
    2003
    
    
    2002Standardized measure of discounted future net cash flows at
January 1
    
    $
    90,559
    
    
    $
    106,671
    
    
    $
    52,377Changes in the year resulting from:Sales and transfers of oil and gas produced during the year,
net of production costs
    
    
    (60,274
    )
    
    
    (41,679
    )
    
    
    (15,525
    )Net change in sales and transfer prices, net of production costs
    
    
    7,140
    
    
    
    (45,194
    )
    
    
    21,167Extensions, discoveries and other additions, net of future
production and development cost
    
    
    4,244
    
    
    
    46,433
    
    
    
    69,718Change in estimated future development costs
    
    
    488
    
    
    
    9
    
    
    
    (209
    )Development costs incurred during the period that reduced
future development costs
    
    
    
    
    
    
    7,486
    
    
    
    3,251Revisions of previous quantity estimates
    
    
    314
    
    
    
    (8,106
    )
    
    
    (2,801
    )Accretion of discount
    
    
    9,056
    
    
    
    10,667
    
    
    
    5,238Net change in income taxes
    
    
    (2,174
    )
    
    
    30,391
    
    
    
    (25,983
    )Purchases of proved reserves in place
    
    
    32,179
    
    
    
    
    
    
    
    Sales of proved reserves in place
    
    
    (412
    )
    
    
    (18,263
    )
    
    
    (5,810
    )Change in production rates (timing) and other
    
    
    
    
    
    
    2,144
    
    
    
    5,248Standardized measure of discounted future net cash flows at
December 31
    
    $
    81,120
    
    
    $
    90,559
    
    
    $
    106,671
 132




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##### Table of Contents



ITEM 19. Exhibits
 Number
    
    Exhibit2.1
    
    Amalgamation Agreement dated May 27, 1998 between Temba Resources Ltd. and PTR Resources Ltd. pursuant to which
the Registrant was amalgamated under the Business Corporations Act
(Alberta) on June 30,
1998.12.2
    
    Letter Agreement dated August 12, 1999 pursuant to which the Registrant acquired all of the issued and outstanding
shares of 759795 Alberta Ltd.22.3
    
    Notice of Intention to File a Normal Course Issuer Bid.33.1
    
    Certificate of Amalgamation and attached Articles of Amalgamation of the Registrant dated and filed June 30, 1998.43.2
    
    By-laws of the Registrant.53.3
    
    Enterra Energy Trust Amended And Restated Trust Indenture.64.1
    
    Amendment Agreement to the Trust Unit Purchase Agreement.74.2
    
    Form of Warrant Agreement between the Registrant and the Representatives providing for the issuance of the
Underwriters Warrants.84.3
    
    Credit Facility Letter Agreement between the Alberta Treasury Branches and the Registrant as Borrower dated April
19, 2000.94.4
    
    Promissory Notes dated June 5, 2000 granted by Westlinks to each of Glenn Russell, Patrick Williams Advisors,
William J. Gordica, F. Jack Wright, Lawrence W. Underwood and Sapphire Capital Inc.104.5
    
    Purchase and Sale Agreement dated April 6, 2000 between Sabre Exploration Ltd. and the Registrant.114.6
    
    Consulting Agreement dated October 13, 2000 between Westlinks Resources Ltd. and Wells Gray Resort & Resources
Ltd.124.7
    
    Arrangement Agreement among
Westlinks Resources Ltd. and 3779041 Canada Ltd. and Big Horn Resources Ltd.134.8
    
    Note Indenture.*4.10
    
    Administration Agreement.*4.13
    
    Second Amended and Restated
Agreement of Business Principles.*4.14
    
    Technical Services Agreement.*4.15
    
    Arrangement Agreement.*4.16
    
    Trust Unit Purchase Agreement.*12.1
    
    Certifications of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act12.2
    
    Certifications of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act13.1
    
    Certifications of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act13.2
    
    Certifications of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act99.1
    
    Consent from KPMG LLP99.2
    
    Consent from Deloitte & Touche LLP99.3
    
    Consent from McDaniel & Associates Consultants Ltd.
 
 *
    
    Previously filed.1
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 2.1, filed with the SEC 2000-06-21
(No. 333-39826).2
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 2.2, filed with the SEC 2000-06-21
(No. 333-39826).3
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 2.3, filed with the SEC 2000-06-21
(No. 333-39826).4
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 3.1, filed with the SEC 2000-06-21
(No. 333-39826).5
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 3.2, filed with the SEC 2000-06-21
(No. 333-39826).6
    
    Incorporated by reference to the Companys
Registration Statement on Form 8-A12G/A, filed 2003-11-28 (No. 000-32115).7
    
    Incorporated by reference to the Companys Form
6-K dated July 15, 2005.8
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 4.2, filed with the SEC 2000-06-21
(No. 333-39826).9
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 4.3, filed with the SEC 2000-06-21
(No. 333-39826).10
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 4.4, filed with the SEC 2000-06-21
(No. 333-39826).11
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1, Exhibit 4.5, filed with the SEC 2000-06-21
(No. 333-39826).12
    
    Incorporated by reference to the Companys
Registration Statement on Form F-1/A, Exhibit 4.6, filed with the SEC
2000-12-01 (No. 333-39826)13
    
    Incorporated by reference to the Companys
Annual Report on Form 20-F, Exhibit 1, filed with the SEC on 2001-06-18
(No. 000-32115). 133




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SIGNATURES
  Date: November 7, 2005Enterra Energy Trust/s/ E. Keith ConradE. Keith Conrad
President and Chief Executive Officer
(Duly Authorized Signing Officer)
 134