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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
  
 FORM 20-F
 (Mark One) o
    
    Registration statement pursuant to Section 12(b) or 12(g) of the Securities Exchange
Act of 1934.
 or þ
    
    Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
 For the fiscal year ended December 31, 2004. Or o
    
    Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934. For the transition period from  to 
 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) Securities registered or to be registered pursuant to Section 12(b) of the Act: Title of Each Class
    
    Name of Each Exchange On Which RegisteredNone
    
    N/A
 Securities registered or to be registered pursuant to Section 12(g) of the Act: Trust Units Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None Indicate the number of outstanding shares of each of the issuers classes of capital or common
stock as of the close of the period covered by the annual report. Trust Units, without par value at December 31, 2004: 25,426,800 Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such
shorter period that the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes þ No o  Item 17 o Item 18 þ




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TABLE OF CONTENTS 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
    
    
    21ITEM 5. Operating and Financial Review and Prospects
    
    
    44ITEM 6. Directors, Senior Management and Employees
    
    
    65ITEM 7. Major Shareholders and Related Party Transactions
    
    
    71ITEM 8. Financial Information
    
    
    71ITEM 9. The Offer and Listing
    
    
    73ITEM 10. Additional information
    
    
    76ITEM 11. Qualitative and Quantitative Disclosures about Market Risk
    
    
    92ITEM 12. Description of Securities Other Than Equity Securities
    
    
    93ITEM 13. Defaults, Dividends Arrearages and Delinquencies
    
    
    94ITEM 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
    
    
    94ITEM 15. Controls and Procedures
    
    
    94ITEM 17. Financial Statements
    
    
    96ITEM 18. Financial Statements
    
    
    96ITEM 19. Exhibits
    
    
    97Certifications of CEO Pursuant to Section 302Certification of CFOCertification of CEO pursuant to Section 906Certification of CFO Pursuant to Section 906Consent of KPMG LLPConsent from Deloitte & Touche LLPConsent of McDaniel & Associates Consultants Ltd
 2




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##### Table of Contents



PART I 
 ITEM 1. Identity of Directors, Senior Management and Advisors Not applicable 
 ITEM 2. Offer Statistics and Expected Timetable Not applicable 
 ITEM 3. Key Information A. Selected Financial Data The financial data set forth below as at December 31, 2004, 2003, 2002, 2001 and 2000 and for each
of the years in the five-year period ended December 31, 2004 have been derived from our audited
consolidated financial statements and should be read in conjunction with those financial
statements. The financial data has been prepared in accordance with Canadian Generally Accepted
Accounting Principles (GAAP), the application of which, in the case of Enterra Energy Trust,
conforms in all material respects for the periods presented with US GAAP, except as disclosed in
footnotes to the financial statements. The following table presents a summary of our consolidated statement of operations derived from our
financial statements for the years ended December 31, 2004, 2003, 2002, 2001 and 2000. The
monetary amounts in the table are in Canadian dollars (C$). All data presented below should be
read in conjunction with ITEM 5 Operating and Financial Review and Prospects and ITEM 18 Financial
Statements and accompanying notes included in this Form 20-F. 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(1)
    
    
    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
    
    $
    14,953
    
    
    $
    7,220
    
    
    $
    5,878
    
    
    $
    2,423
    
    
    $
    3,880Net earnings
    
    $
    14,764
    
    
    $
    5,098
    
    
    $
    4,881
    
    
    $
    1,700
    
    
    $
    2,256Basic earnings per unit/share
    
    $
    0.63
    
    
    $
    0.27
    
    
    $
    0.27
    
    
    $
    0.12
    
    
    $
    0.26Diluted earnings per unit/share
    
    $
    0.63
    
    
    $
    0.27
    
    
    $
    0.26
    
    
    $
    0.12
    
    
    $
    0.25Dividends paid on preferred shares
    
    $
    
    
    
    $
    33
    
    
    $
    23
    
    
    $
    
    
    
    $
    Dividends paid on common shares
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Weighted average units/shares outstanding  basic
    
    
    23,561
    
    
    
    18,954
    
    
    
    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
    
    $
    (7.70
    )
    
    $
    (11.55
    )
    
    $
    0.36
    
    
    $
    (1.11
    )
    
    $
    0.52Dividends paid on preferred shares
    
    $
    
    
    
    $
    33
    
    
    $
    23
    
    
    $
    
    
    
    $
    Dividends paid on common shares
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
 4




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The following table indicates a summary of our consolidated balance sheets as of December 31, 2004,
2003, 2002, 2001 and 2000. The monetary amounts in the table are in
Canadian dollars (C$). Consolidated balance sheet data: (In thousands) As at December 31,2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000C$
    
    
    C$
    
    
    C$
    
    
    C$
    
    
    C$Restated(1)
    
    
    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
    
    $
    146,910
    
    
    $
    105,253
    
    
    $
    96,142
    
    
    $
    74,130
    
    
    $
    19,588Total assets
    
    $
    200,301
    
    
    $
    116,661
    
    
    $
    104,505
    
    
    $
    81,054
    
    
    $
    23,354Total Unitholders equity
    
    $
    98,095
    
    
    $
    47,629
    
    
    $
    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 recommendationsrequire 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)
    
    For further information on the US GAAP reconciliation, see ITEM 18 Financial
Statements  Note 17. 5




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NON-GAAP ITEMS Management uses cash flow (before changes in non-cash working capital) to analyze operating
performance and leverage. It is managements view, based on its communications with investors
during events like conference calls, webcasts or road shows, that cash flow from operations is most
relevant to our investors and unitholders, especially since the Trusts conversion to an oil and
gas income trust. Cash flow from operations is extremely relevant to investors because it is the
starting point for setting the monthly distribution level. Cash flow as presented does not have
any standardized meaning prescribed by Canadian generally accepted accounting principles, (GAAP)
and therefore it may not be comparable with the calculation of similar measures for other entities.
Cash flow as presented is not intended to represent operating cash flow or operating profits for
the period nor should it be viewed as an alternative to cash flow from operating activities, net
earnings or other measures of financial performance calculated in accordance with Canadian GAAP.
All references to cash flow and cash flow from operations throughout this report are based on cash
flow before changes in non-cash working capital. The calculation of barrels of oil equivalent (boe) is based on a conversion ratio of six thousand
cubic feet of natural gas to one barrel of oil to estimate relative energy content and does not
represent a value equivalency at the wellhead. BOEs may be misleading, particularly if used in
isolation SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS This report includes forward-looking statements. All statements other than statements of
historical facts contained in this report, including statements regarding our future financial
position, estimated amounts and timing of capital expenditures, royalty rates and exchange rates,
plans for drilling, exploration and development, business strategy and plans and objectives of
management for future operations, are forward-looking statements. The words believe, may,
will, estimate, continue, anticipate, intend, should, plan, expect and similar
expressions, as they relate to us, are intended to identify forward-looking statements. We have
based these forward-looking statements largely on our current expectations and projections about
future events and financial trends that we believe may affect our financial condition, results of
operations, business strategy and financial needs. These forward-looking statements are subject to
a number of risks, uncertainties and assumptions described in Risk Factors and elsewhere in this
report. Statements concerning oil and gas reserves contained in this report may be deemed to be
forward-looking statements as they involve the implied assessment that the resources described can
be profitably produced in the future, based on certain estimates and assumptions. These risks and uncertainties include:  
    
    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. Other sections of this report may include additional factors that could adversely affect our
business and financial performance. Moreover, we operate in a very competitive and rapidly
changing environment. New risk factors emerge from time to time and it is not possible for our
management to predict all risk factors, nor can we assess the impact of all factors on our business
or the extent to which any factor, or combination of factors, may cause actual results to differ
materially from those contained in any forward-looking statements. 6




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We undertake no obligation to update publicly or revise any forward-looking statements. You should
not rely upon forward-looking statements as predictions of future events or performance. We cannot
assure you that the events and circumstances reflected in the forward-looking statements will be
achieved or occur. Although we believe that the expectations reflected in the forward-looking
statements are reasonable, we cannot guarantee future results, levels of activity, performance or
achievements. 7




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Exchange Rate Information We publish our consolidated financial statements in Canadian dollars. In this report, except where
otherwise indicated, all dollar amounts are stated in Canadian dollars. References to $ or C$
are to Canadian dollars and references to US$ are to U.S. dollars. The following table sets
forth for each period indicated the period end exchange rates for conversion of U.S. dollars to
Canadian dollars, the average exchange rates on the last day of each month during such period and
the high and low exchange rates during such period. These rates are based on the noon buying rate
in New York City, expressed in U.S. dollars, for cable transfers in Canadian dollars as certified
for customs purposes by the Federal Reserve Bank of New York. The exchange rates are presented as
Canadian dollars per $1.00. On June 15, 2005, the noon buying rate was US$1.00 equals Cdn.$1.2397
and the inverse noon buying rate was Cdn.$1.00 equals US$0.8067. 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 December 2004
    
    
    January 2005
    
    
    February 2005
    
    
    March 2005
    
    
    April 2005
    
    
    May 2005High
    
    
    0.8447
    
    
    
    0.8333
    
    
    
    0.8161
    
    
    
    0.8331
    
    
    
    0.8265
    
    
    
    0.8081Low
    
    
    0.8053
    
    
    
    0.8102
    
    
    
    0.7962
    
    
    
    0.8037
    
    
    
    0.7945
    
    
    
    0.7874
 B. Capitalization and Indebtedness Not applicable C. Reasons for the Offer and Use of Proceeds Not applicable 8




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D. Risk Factors Certain risk factors that could materially adversely affect our cash flow, operating results,
financial condition or the business of our operating subsidiaries are set out below. Investors
should carefully consider these risk factors before making investment decisions involving our trust
units. Our results of operations and financial condition are dependent on the prices received for our oil
and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are subject to
fluctuations in response to relatively minor changes in supply, demand, market uncertainty and
other factors that are beyond our control. These factors include, but are not limited to,
worldwide political instability, foreign supply of oil and natural gas, the level of consumer
product demand, government regulations and taxes, the price and availability of alternative fuels
and the overall economic environment. Any decline in crude oil or natural gas prices may have a
material adverse effect on our operations, financial condition, borrowing ability, reserves and the
level of expenditures for the development of oil and natural gas reserves. Any resulting decline
in our cash flow could reduce distributions. We use financial derivative instruments and other hedging mechanisms to try to limit a portion of
the adverse effects resulting from changes in natural gas and oil commodity prices. To the extent
we hedge our commodity price exposure, we forego the benefits we would otherwise experience if
commodity prices were to increase. In addition, our commodity hedging activities could expose us
to losses. Such losses could occur under various circumstances, including where the other party to
a hedge does not perform its obligations under the hedge agreement, the hedge is imperfect or our
hedging policies and procedures are not followed. Furthermore, we cannot guarantee that such
hedging transactions will fully offset the risks of changes in commodities prices. In addition, we regularly assess the carrying value of our assets in accordance with Canadian
generally accepted accounting principles under the full cost method. If oil and natural gas prices
become depressed or decline, the carrying value of our assets could be subject to downward
revision. 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. Higher operating costs for our underlying properties will directly decrease the amount of cash flow
received by the Trust and, therefore, may reduce distributions to our Unitholders. Electricity,
chemicals, supplies, reclamation and abandonment and labor costs are a few of the operating costs
that are susceptible to material fluctuation. The level of production from our existing properties may decline at rates greater than anticipated
due to unforeseen circumstances, many of which are beyond our control. A significant decline in
our production could result in materially lower revenues and cash flow and, therefore, could reduce
the amount available for distributions to Unitholders. 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. To the extent that we use cash flow to finance acquisitions, development costs and other
significant expenditures, the net cash flow that the Trust receives that is available for
distribution to Unitholders will be reduced. Hence, the timing and amount of capital expenditures
may affect the amount of net cash flow received by the Trust and, as a consequence, the amount of
cash available to distribute to Unitholders. Therefore, distributions may be reduced, or even
eliminated, at times when significant capital or other expenditures are made. The board of directors of Enterra Energy Corp., the principal operating subsidiary of the Trust,
has the discretion to determine the extent to which cash flow from Enterra will be allocated to the
payment of debt service charges as well as the repayment of outstanding debt, including under the
credit facility. As a consequence, the amount of funds retained by Enterra to pay debt service
charges or reduce debt will reduce the amount of cash available for distribution to Unitholders
during those periods in which funds are so retained. 9




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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. Our business depends in part upon the availability, proximity and capacity of gas gathering
systems, pipelines and processing facilities. Canadian federal and provincial, as well as United
States federal and state, regulation of oil and gas production, processing and transportation, tax
and energy policies, general economic conditions, and changes in supply and demand could adversely
affect our ability to produce and market oil and natural gas. If market factors change and inhibit
the marketing of our production, overall production or realized prices may decline, which could
reduce distributions to our Unitholders. 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. The price that we receive for a majority of our oil and natural gas is based on United States
dollar denominated benchmarks, and therefore the price that we receive in Canadian dollars is
affected by the exchange rate between the two currencies. A material increase in the value of the
Canadian dollar relative to the United States dollar may negatively impact net production revenue
by decreasing the Canadian dollars received for a given United States dollar price. We could be
subject to unfavorable price changes to the extent that we have engaged, or in the future engage,
in risk management activities related to foreign exchange rates, through entry into forward foreign
exchange contracts or otherwise. If we are unable to acquire additional reserves, the value of our trust units and distributions to
Unitholders may decline. We do not actively explore for oil and natural gas reserves. Instead, we add to our oil and
natural gas reserves primarily through development, exploitation and acquisitions. As a result,
future oil and natural gas reserves are highly dependent on our success in exploiting existing
properties and acquiring additional reserves. We also distribute the majority of our net cash flow
to Unitholders rather than reinvesting it in reserve additions. Accordingly, if external sources
of capital, including the issuance of additional trust units, become limited or unavailable on
commercially reasonable terms, our ability to make the necessary capital investments to maintain or
expand our oil and natural gas reserves will be impaired. To the extent that we are required to
use cash flow to finance capital expenditures or property acquisitions, the level of cash flow
available for distribution to Unitholders will be reduced. Additionally, we cannot guarantee that
we will be successful in developing additional reserves or acquiring additional reserves on terms
that meet our investment objectives. Without these reserve additions, our reserves will deplete
and as a consequence, either production from, or the average reserve life of, our properties will
decline. Either decline may result in a reduction in the value of our trust units and in a
reduction in cash available for distributions to Unitholders. 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. The reserve and recovery information contained in the independent engineering report prepared by
McDaniel & Associates Consultants Ltd. (McDaniel) relating to our reserves is only an estimate
and the actual production and ultimate reserves from our properties may be greater or less than the
estimates prepared by McDaniel. The value of our trust units depends upon, among other things, the reserves attributable to our
properties. Estimating reserves is inherently uncertain. Ultimately, actual reserves attributable
to our properties will vary from estimates, and those variations may be material. The reserve
figures contained herein are only estimates. A number of factors are considered and a number of
assumptions are made when estimating reserves. These factors and assumptions include, among
others:  
    
    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; 10




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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. Reserve estimates are based on the relevant factors, assumptions and prices on the date the
relevant evaluations were prepared. Many of these factors are subject to change and are beyond our
control. If these factors, assumptions and prices prove to be inaccurate, actual results may vary
materially from reserve estimates. As we expand our operations beyond oil and natural gas production in western Canada, we face new
challenges and risks. If we were unsuccessful in managing these challenges and risks, our results of operations and
financial condition could be adversely affected, which could affect the market price of our trust
units and distributions to Unitholders. Our operations and expertise have been focused on conventional oil and gas production and
development in the Western Canadian Sedimentary Basin. Recently, we acquired oil and gas
properties outside this geographic area which are also non-conventional assets, being coal bed
methane. In addition, the Trust Indenture does not limit the activities to oil and gas production
and development, and we could acquire other energy related assets, such as oil and natural gas
processing plants or pipelines. Expansion of our activities into new areas presents challenges and
risks that we have not faced in the past. If we do not manage these challenges and risks
successfully, our results of operations and financial condition could be adversely affected. 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. The price we are willing to pay for reserve acquisitions is based largely on estimates of the
reserves to be acquired. Actual reserves could vary materially from these estimates.
Consequently, the reserves we acquire may be less than expected, which could adversely impact cash
flows and distributions to Unitholders. An initial assessment of an acquisition may be based on a
report by engineers or firms of engineers that have different evaluation methods and approaches
than those of our engineers, and these initial assessments may differ significantly from our
subsequent assessments. 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. The continuing production from a property, and to some extent the marketing of that production, is
dependent upon the ability of the operators of those properties. At December 31, 2004,
approximately 5% of our daily production was from properties operated by third parties. To the
extent a third-party operator fails to perform its functions efficiently or becomes insolvent, our
revenue may be reduced. Third party operators also make estimates of future capital expenditures
more difficult. Further, the operating agreements, which govern the properties not operated by us, typically
require the operator to conduct operations in a good and workmanlike manner. These operating
agreements generally provide, however, that the operator has no liability to the other
non-operating working interest owners, such as Unitholders, for losses sustained or liabilities
incurred, except for liabilities that may result from gross negligence or willful misconduct. Delays in business operations could adversely affect distributions to Unitholders and the market
price of our trust units. 11




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In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of
our properties, and the delays of those operators in remitting payment to us, payments between any
of these parties may also be delayed by:  
    
    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. Any of these delays could reduce the amount of cash available for distribution to Unitholders in a
given period and expose us to additional third party credit risks. 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. The payments of interest and principal, and other costs, expenses and disbursements to our lenders
reduce amounts available for distribution to Unitholders. Variations in interest rates and
scheduled principal repayments could result in significant changes to the amount of the cash flow
required to be applied to the debt before payment of any amounts to the Unitholders. The
agreements governing our credit facility provide that if we are in default under the credit
facility, exceed certain borrowing thresholds or fail to comply with certain covenants, we must
repay the indebtedness at an accelerated rate, and the ability to make distributions to Unitholders
may be restricted. Our lenders have been provided with a security interest in substantially all of our assets. If we
are unable to pay the debt service charges or otherwise commit an event of default, such as
bankruptcy, our lenders may foreclose on and sell the properties. The proceeds of any sale would
be applied to satisfy amounts owed to the creditors. Only after the proceeds of that sale were
applied towards the debt would the remainder, if any, be available for distribution to Unitholders. Our current credit facility and any replacement credit facility may not provide sufficient
liquidity. The amounts available under our existing credit facility may not be sufficient for future
operations, or we may not be able to obtain additional financing on economic terms attractive to
us, if at all. Our current credit facility consists of a revolving operating demand loan, and a
demand subordinated debt facility. Repayment of all outstanding amounts may be demanded at any
time. If this occurs, we may need to obtain alternate financing. Any failure to obtain suitable
replacement financing may have a material adverse effect on our business, and distributions to
Unitholders may be materially reduced. 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. Under the terms of the Kingsbridge Purchase Agreement, we may, at our sole discretion, sell to
Kingsbridge, and Kingsbridge would be obligated to purchase, Trust Units for up to US$100 million
in proceeds to us. We may not sell Trust Units to Kingsbridge, however, unless we satisfy the
conditions of the Kingsbridge Purchase Agreement which are described under The Committed Equity
Financing Facility with Kingsbridge. The price at which we may sell Trust Units under the
Kingsbridge Purchase Agreement is based on a discount to the volume weighted 12




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average market price of the Trust Units for fifteen trading days following each of our elections to
sell Trust Units. For each election, we select the lowest threshold price at which our Trust Units
may be sold, but the threshold price cannot be lower than US$11.04 per share. We also may not sell
any Trust Units with respect to any day in the fifteen day pricing period in which the price at
which Trust Units would be sold under the facility is less than 85% of the volume weighted average
trading price of the Trust Units during the previous five trading days. If the market price of our
Trust Units falls below US$12.00 per Trust Unit, which after giving effect to the discount would
result in a price per Trust Unit lower than the US$11.04 minimum threshold price, or with respect
to any period in which the price at which Trust Units would be sold is less than the 85% of the
volume weighted average trading price for the five previous trading days, the committed equity
financing facility will not be an available source of financing. Our agreement with Kingsbridge permits Kingsbridge to terminate the committed equity financing
facility if Kingsbridge determines that a material and adverse event has occurred affecting our
business, operations, properties or financial condition, or if any situation occurs that would
interfere with our ability to perform any of our obligations under the agreement. If we are unable to draw down on the committed equity financing facility, and are otherwise unable
to obtain capital from other sources on a timely basis or on terms favorable to us, we may be
required to fail to take advantage of acquisitions or other opportunities, scale back our
operations, or sell some of our assets. 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. The first draw down under the committed equity financing facility is limited to US$10 million.
Each draw down election we make thereafter is limited to a maximum of 4% of our market
capitalization at the time of the election, and cannot in any case exceed US$25 million. We must
also wait at least five trading days after the end of a fifteen trading day draw down period before
we can commence the next draw down. In addition, the committed equity financing facility limits
the beneficial ownership of Kingsbridge to 9.9% of our outstanding Trust Units, which percentage
includes any Trust Units purchased pursuant to the committed equity financing facility or that we
may issue to Kingsbridge as liquidated damages, or that may be issued upon exercise of the
Kingsbridge Warrant. Depending on the market price of our Trust Units and Kingsbridges other
holdings of our Trust Units, this restriction may limit the maximum amount we can draw down under
the committed equity financing facility. If Kingsbridges beneficial ownership were to exceed 9.9%
of our outstanding Trust Units, together with the total amount of our Trust Units that would be
outstanding upon completion of a draw down, we would not be able to draw down on the committed
equity financing facility until such time as Kingsbridge sells enough Trust Units of our Trust
Units or our number of Trust Units outstanding increases, which may not occur. Therefore, we may
not be able to draw down on the full US$100 million commitment. The 9.9% limitation on
Kingsbridges beneficial ownership will not prevent Kingsbridge from selling some of its holdings
and then receiving additional Trust Units, such that the total number of Trust Units that we may
sell to Kingsbridge under the committed equity financing facility that it may resell under this
prospectus is greater than 9.9% of our outstanding Trust Units. 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. To the extent that Kingsbridge sells Trust Units issued under the committed equity financing
facility under this prospectus, our Trust Unit price may decrease due to the additional selling
pressure in the market. The perceived risk of dilution from sales of Trust Units to or by
Kingsbridge or otherwise pursuant to this report may cause holders of our Trust Units to sell their
Trust Units, which could contribute to a decline in our Trust Unit price. 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. A significant downward pressure on the price of our Trust Units caused by the sale of material
amounts of Trust Units under the committed equity financing facility could encourage short sales by
third parties. In a short sale, a prospective seller borrows Trust Units from a unitholder or
broker and sells the borrowed Trust Units. The prospective seller hopes that the Trust Unit price
will decline, at which time the seller can purchase Trust Units at a 13




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lower price to repay the lender. The seller profits when the Trust Unit price declines because it
is purchasing Trust Units at a price lower than the sale price of the borrowed Trust Units. Such
sales could place downward pressure on the price of our Trust Units by increasing the number of
Trust Units being sold, which could contribute to the future decline of our Trust Unit price. 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 actual number of Trust Units that we will issue under the committed equity financing facility
in any particular draw down, and in total, is uncertain. Subject to the limitations in our
agreement with Kingsbridge, we have the discretion to draw down funds at any time throughout the
term of the committed equity financing facility, and we have not determined the amount of proceeds,
if any, we will seek to raise through the committed equity financing facility. Also, the number of
Trust Units we must issue after giving a draw down notice will fluctuate based on the market price
of our Trust Units over the fifteen trading days after we give a draw down notice, and Kingsbridge
will receive more Trust Units if our Trust Unit price declines. During each fifteen trading day draw down period, Kingsbridge is permitted to sell the Trust Units
to be issued with respect to each trading day once the discount purchase price for such day (and
therefore the number of Trust Units to be purchased for such day) is determined. These permitted
sales during a draw down period may cause the volume weighted average price of our Trust Units to
decline on immediately subsequent days, resulting in the sale of additional Trust Units to
Kingsbridge on immediately subsequent days for the same monetary proceeds to us. The further sale
of Trust Units priced on those immediately subsequent days could then cause further price declines
on later days, resulting in the sale of increasing number of Trust Units for the same monetary
proceeds as the draw down period progresses. Furthermore, Kingsbridges 9.9% beneficial ownership limitation is determined on, and based on the
amount of our Trust Units outstanding on, each settlement date. As the Trust Units outstanding on
each settlement date increases, Kingsbridge may be required to purchase more Trust Units during a
draw down period than would have been apparent on the date that we sent the draw down notice to
Kingsbridge. The committed equity financing facility imposes certain liquidated damages, which may impair our
liquidity and ability to raise capital. The terms of the committed equity financing facility require us to pay liquidated damages in the
event that a registration statement is not available for the resale of securities purchased by
Kingsbridge under the committed equity financing facility. These liquidated damages provisions
generally require us to pay an amount based on the decline in value, if any, of Trust Units held by
Kingsbridge during the time a registration statement is unavailable. See The Committed Equity
Financing Facility with Kingsbridge for a further description of these liquidated damages
provisions. The liquidated damages could adversely affect our liquidity, or to the extent we are
permitted to and decide to pay such damages through the issuance of Trust Units, cause significant
dilution to holders of our Trust Units. 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. Our credit facilities are classified as a short-term liability on our balance sheet as they are on
a demand basis and may be called at any time. Accordingly, at December 31, 2004, we had a working
capital deficiency of $ 42.4 million, which means our current liabilities exceeded our current
assets by that amount. Although we are not subject to and do not expect to make principal
repayments under our current banking arrangement, they could be called for repayment at any time.
Other than in the event of a default or a breach of covenants, we do not expect to make any
principal payments in 2005, except for those required to stay within the limits of our decreasing
subordinated debt facility. 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. 14




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We carry debt that is secured by our assets. A decrease in the amount of our production or the
price we receive for it could make it difficult for us to service our debt or may cause the bank
that issued our loan to determine that our assets are insufficient security for our bank debt. The oil and natural gas industry is highly competitive. We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to
drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and
refining capacity and in many other respects with a substantial number of other organizations, many
of which may have greater technical and financial resources than we do. Some of these
organizations not only explore for, develop and produce oil and natural gas but also carry on
refining operations and market oil and other products on a worldwide basis. As a result of these
complementary activities, some of our competitors may have greater and more diverse competitive
resources to draw on than we do. Given the highly competitive nature of the oil and natural gas
industry, this could adversely affect the market price of our trust units and distributions to
Unitholders. The industry in which we operate exposes us to potential liabilities that may not be covered by
insurance. Our operations are subject to all of the risks associated with the operation and development of oil
and natural gas properties, including the drilling of oil and natural gas wells, and the production
and transportation of oil and natural gas. These risks include encountering unexpected formations
or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents,
cratering, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse
weather conditions, pollution, other environmental risks, fires and spills. A number of these
risks could result in personal injury, loss of life, or environmental and other damage to our
property or the property of others. We cannot fully protect against all of these risks, nor are
all of these risks insurable. We may become liable for damages arising from these events against
which we cannot insure or against which we may elect not to insure because of high premium costs or
other reasons. Any costs incurred to repair these damages or pay these liabilities would reduce
funds available for distribution to Unitholders. The operation of oil and natural gas wells could subject us to environmental claims and liability. The oil and natural gas industry is subject to extensive environmental regulation pursuant to
local, provincial and federal legislation. A breach of that legislation may result in the
imposition of fines or the issuance of clean up orders. Legislation regulating the oil and
natural gas industry may be changed to impose higher standards and potentially more costly
obligations. For example, the 1997 Kyoto Protocol to the United Nations Framework Convention on
Climate Change, known as the Kyoto Protocol, was ratified by the Canadian government in December
2002 and will require, among other things, significant reductions in greenhouse gases. The impact
of the Kyoto Protocol on us is uncertain and may result in significant additional costs (future)
for our operations. Although we record a provision in our financial statements relating to our
estimated future environmental and reclamation obligations, we cannot guarantee that we will be
able to satisfy our actual future environmental and reclamation obligations. We are not fully insured against certain environmental risks, either because such insurance is not
available or because of high premium costs. In particular, insurance against risks from
environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not
available on economically reasonable terms. Accordingly, our properties may be subject to liability due to hazards that cannot be insured
against, or that have not been insured against due to prohibitive premium costs or for other
reasons. Any site reclamation or abandonment costs actually incurred in the ordinary course of
business in a specific period will be funded out of cash flow and, therefore, will reduce the
amounts available for distribution to Unitholders. Should we be unable to fully fund the cost of
remedying an environmental problem, we might be required to suspend operations or enter into
interim compliance measures pending completion of the required remedy. 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. We changed our method of accounting for petroleum and natural gas properties from the successful
efforts method to the full cost method in 2001. All costs related to the exploration for and
the development of oil and gas reserves are capitalized into a single cost center representing
Enterras activity, which is undertaken exclusively in 15




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Canada. Costs capitalized include land acquisition costs, geological and geophysical
expenditures, lease rentals on undeveloped properties and costs of drilling productive and
non-productive wells. Proceeds from the disposal of properties are applied as a reduction of cost
without recognition of a gain or loss except where such disposals would result in a major change in
the depletion rate. Capitalized costs are depleted and depreciated using the unit-of-production method based on the
estimated gross proven oil and natural gas reserves before royalties as determined by independent
engineers. Units of natural gas are converted into barrels of equivalents on a relative energy
content basis. Effective January 1, 2004, we prospectively adopted new Canadian accounting standards relating to
full cost accounting for oil and gas entities. 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 proven 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 the standard. Under U.S. GAAP, companies using the full cost method of accounting for oil and gas producing
activities perform a ceiling test using estimated future net revenue from proven oil and gas
reserves using a discount factor of 10%. Prices used in the U.S. GAAP ceiling tests performed for
this reconciliation were those in effect at the applicable year-end. Financing and administration
costs are excluded from the calculation under U.S. GAAP. At December 31, 2001 Enterra realized a
U.S. GAAP ceiling test write-down of Cdn.$17.5 million, after tax. At December 31, 2004 Enterra
realized a U.S. GAAP ceiling test write-down of Cdn.$6.3 million, after tax. The risk that we will be required to write down the carrying value of crude oil and natural gas
properties increases when crude oil and natural gas prices are low or volatile. We may experience
additional ceiling test write-downs in the future. Unforeseen title defects may result in a loss of entitlement to production and reserves. Although we conduct title reviews in accordance with industry practice prior to any purchase of
resource assets, such reviews do not guarantee that an unforeseen defect in the chain of title will
not arise and defeat our title to the purchased assets. If such a defect were to occur, our
entitlement to the production from such purchased assets could be jeopardized and, as a result,
distributions to Unitholders may be reduced. Aboriginal Land Claims. The economic impact on us of claims of aboriginal title is unknown. Aboriginal people have claimed
aboriginal title and rights to a substantial portion of western Canada. We are unable to assess
the effect, if any, that any such claim would have on our business and operations. Changes in tax and other laws may adversely affect Unitholders. Income tax laws, other laws or government incentive programs relating to the oil and gas industry,
such as the treatment of mutual fund trusts and resource allowance, may in the future be changed or
interpreted in a manner that adversely affects the Trust and Unitholders. Tax authorities having
jurisdiction over the Trust or the Unitholders may disagree with the manner in which we calculate
our income for tax purposes or could change their administrative practices to our detriment or the
detriment of Unitholders. The Department of Finance (Canada) has indicated that it will continue
to evaluate the development of the income trust market as part of its ongoing monitoring and
assessment of Canadian financial markets and the Canadian tax system. Accordingly, changes in this
area are possible. Income Tax Matters. On October 31, 2003, the Department of Finance (Canada) released, for public comment, proposed
amendments to the Tax Act that relate to the deductibility of interest and other expenses for
income tax purposes for taxation years commencing after 2004. In general, the proposed amendments
may deny the realization of losses in respect of a 16




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business if there is no reasonable expectation that the business will produce a cumulative profit
over the period that the business can reasonably be expected to be carried on. If such proposed
amendments were enacted and successfully invoked by the CRA against the Trust or a subsidiary
entity, it could materially adversely affect the amount of distributable cash available. However,
Enterra believes that it is reasonable to expect the Trust and each subsidiary entity to produce a
cumulative profit over the expected period that the business will be carried on. Expenses incurred by Enterra are only deductible to the extent they are reasonable. Although the
Trust is of the view that all expenses to be claimed by the Trust and its subsidiary entities
should be reasonable and deductible, there can be no assurance that CRA will agree. If CRA were to
successfully challenge the deductibility of such expenses, the return to Unitholders may be
adversely affected. The Trust Indenture provides that an amount equal to the taxable income of the Trust will be
payable each year to Unitholders in order to reduce the Trusts taxable income to zero. Where in a
particular year, the Trust does not have sufficient available cash to distribute such an amount to
Unitholders, the Trust Indenture provides that additional trust units must be distributed to
Unitholders in lieu of cash payments. Unitholders will generally be required to include an amount
equal to the fair market value of those trust units in their taxable income, notwithstanding that
they do not directly receive a cash payment. As noted above, the Department of Finance (Canada) has indicated that it will continue to evaluate
the development of the income trust market as part of its ongoing monitoring and assessment of
Canadian financial markets and the Canadian tax system. Accordingly, changes in this area are
possible. Such changes could result in the income tax considerations described under the heading
Canadian Federal Income Tax Considerations being materially different in certain respects. There would be material adverse tax consequences if the Trust lost its status as a mutual fund
trust under Canadian tax laws. It is intended that the Trust continue to qualify as a mutual fund trust for purposes of the Tax
Act. The Trust may not, however, always be able to satisfy any future requirements for the
maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be
lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise
for the Trust and Unitholders. Some of the significant consequences of losing mutual fund trust
status are as follows:  
    
    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.  
    
    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. In addition, we may take certain measures in the future to the extent we believe them necessary to
ensure that the Trust maintains its status as a mutual fund trust. These measures could be adverse
to certain holders of trust units. Rights as a unitholder differ from those associated with other types of investments. 17




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The trust units do not represent a traditional investment in the oil and natural gas sector and
should not be viewed by investors as shares in the Trust. The trust units represent an equal
fractional beneficial interest in the Trust and, as such, the ownership of the trust units does not
provide Unitholders with the statutory rights normally associated with ownership of shares of a
corporation, including, for example, the right to bring oppression or derivative actions. The
unavailability of these statutory rights may also reduce the ability of Unitholders to seek legal
remedies against other parties on our behalf. The trust units are also unlike conventional debt instruments in that there is no principal amount
owing to Unitholders. The trust units will have minimal value when reserves from our properties
can no longer be economically produced or marketed. Unitholders will only be able to obtain a
return of the capital they invested during the period when reserves may be economically recovered
and sold. Accordingly, cash distributions do not represent a yield in the traditional sense as
they represent both return of capital and return on investment and the distributions received over
the life of the investment may not meet or exceed the initial capital investment. Changes in market-based factors may adversely affect the trading price of our trust units. The market price of our trust units is primarily a function of anticipated distributions to
Unitholders and the value of our properties. The market price of our trust units is therefore
sensitive to a variety of market-based factors, including, but not limited to, interest rates and
the comparability of our trust units to other yield oriented securities. Any changes in these
market-based factors may adversely affect the trading price of the trust units. Our operations are entirely independent from the Unitholders and loss of key management and other
personnel could impact our business. Unitholders are entirely dependent on the management of Enterra with respect to the acquisition of
oil and gas properties and assets, the development and acquisition of additional reserves, the
management and administration of all matters relating to our oil and natural gas properties and the
administration of the Trust. The loss of the services of key individuals who currently comprise
the management team could have a detrimental effect on the Trust. Investors should carefully
consider whether they are willing to rely on the existing management before investing in the trust
units. There may be future dilution. One of our objectives is to continually add to our reserves through acquisitions and through
development. Since we do not reinvest a material portion of our cash flow, our success is, in
part, dependent on our ability to raise capital from time to time by selling additional trust
units. Unitholders will suffer dilution as a result of these offerings if, for example, the cash
flow, production or reserves from the acquired assets do not reflect the additional number of trust
units issued to acquire those assets. Unitholders may also suffer dilution in connection with
future issuances of trust units to effect acquisitions. There may not always be an active trading market for the trust units. While there is currently an active trading market for our trust units in the United States and
Canada, we cannot guarantee that an active trading market will be sustained. The limited liability of Unitholders is uncertain. By virtue of the enactment of the Income Trusts Liability Act(Alberta) on July 1, 2004,
Unitholders of the Trust (as an Alberta income trust) are now suppose to be protected from
liabilities of the Trust to the same extent that a shareholder is protected from liabilities of a
corporation but this protection only applies in respect of any act, default, obligation or
liability of the Trust or any of the trustees thereof which arose or occurred after July 1, 2004.
Notwithstanding the legislation, Unitholders may not be protected from certain liabilities of the
Trust, in particular, those which arose or occurred on or prior to July 1, 2004. Accordingly, a
Unitholder could be held personally liable for obligations of the Trust in respect of contracts or
undertakings which the Trust has entered into and for certain liabilities arising otherwise than
out of contracts including claims in tort, claims for taxes and possibly certain other statutory
liabilities. Although every written contract or commitment of the Trust must contain an express
disavowal of liability of the Unitholders and a limitation of liability to Trust property, such
protective provisions may not 18




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operate to avoid unitholder liability. Further, although the Trust has agreed to indemnify and
hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges and losses
suffered by the Unitholder resulting from or arising out of that Unitholder not having limited
liability, the Trust cannot guarantee that any assets would be available in these circumstances to
reimburse Unitholders for any such liability. The redemption rights of Unitholders are limited. Unitholders have a limited right to require the Trust to repurchase their trust units, which is
referred to as a redemption right. It is anticipated that the redemption right will not be the
primary mechanism for Unitholders to liquidate their investment. The Trusts ability to pay cash
in connection with a redemption is subject to limitations. Any securities which may be distributed
in specie to Unitholders in connection with a redemption may not be listed on any stock exchange
and a market may not develop for such securities. In addition, there may be resale restrictions
imposed by law upon the recipients of the securities pursuant to the redemption right. Taxation of Enterra. Enterra is subject to taxation in each taxation year on its income for the year, after deducting
interest paid to the Trust on the Notes. During the period that Exchangeable Shares issued by
Enterra are outstanding, a portion of the cash flow from operations will be subject to tax to the
extent that there are not sufficient resource pool deductions, capital cost allowance or
utilization of prior years non-capital losses to reduce taxable income to zero. Enterra intends to
deduct, in computing its income for tax purposes, the full amount available for deduction in each
year associated with its income tax resource pools, undepreciated capital cost (UCC) and
non-capital losses, if any. If there are not sufficient resource pools, UCC and non-capital losses
carried forward to shelter the income of Enterra, then cash taxes would be payable by Enterra. In
addition, there can be no assurance that taxation authorities will not seek to challenge the amount
of interest expense relating to the Notes. If such a challenge were to succeed against Enterra, it
could materially adversely affect the amount of cash flow available for distribution to
Unitholders. Further, interest on the Notes accrues at the Trust level for income tax purposes whether or not
actually paid. The Trust Indenture provides that an amount equal to the taxable income of the
Trust will be distributed each year to Unitholders in order to reduce the Trusts taxable income to
zero. Where interest payments on the Notes are due but not paid in whole or in part, the Trust
Indenture provides that any additional amount necessary to be distributed to Unitholders may be
distributed in the form of Units rather than in cash. Unitholders will be required to include such
additional amount in income even though they do not receive a cash distribution. 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. A component of future growth will depend on the ability to identify, negotiate, and acquire
additional companies and assets that complement or expand existing operations. However we may be
unable to complete any acquisitions, or any acquisitions we may complete may not enhance our
business. Any acquisitions could subject us to a number of risks, including:  
    
    diversion of managements attention;  
    
    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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We have been organized under the laws of Alberta, Canada and the majority of our assets are located
outside the U.S. In addition, a majority of the members of our Board of Directors and our officers
and many of the experts named in this report are residents of countries other than the U.S. As a
result, it may be impossible for you to effect service of process upon us or these individuals
within the U.S. or to enforce any judgments in civil and commercial matters, including judgments
under U.S. federal securities laws. In addition, a Canadian court may not permit you to bring an
original action in Canada or to enforce in Canada a judgment of a U.S. court based upon civil
liability provisions of the U.S. federal securities laws. 20




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ITEM 4. Information on the Trust A. History and development of The Trust Enterra Energy Trust (the Trust and, together with its direct and indirect subsidiaries and
partnerships, we, our or us) is an open ended unincorporated investment trust governed by the
laws of the Province of Alberta and created pursuant to a trust indenture dated as of October 24,
2003, between Enterra Energy Corp. and Olympia Trust Company (the Trust Indenture). The
registered office of the Trust is located at Suite 3300, 421  7th Avenue S.W., Calgary, Alberta,
T2P 4K9 and its head office is located at Suite 2600, 500-4th Avenue S.W., Calgary, Alberta T2P
2V6; phone 403-263-0262. As a result of the completion of a plan of arrangement involving the Trust, Enterra Energy Corp.
(Old Enterra), Enterra Acquisition Corp. and Enterra Energy Commercial Trust (EEC Trust or
Commercial Trust) (the Arrangement) on November 25, 2003, former holders of common shares of
Old Enterra received two trust units or two Exchangeable Shares of Enterra Acquisition Corp., in
accordance with the elections made by such holders, and Old Enterra became a subsidiary of the
Trust. Old Enterra was subsequently amalgamated with Enterra Acquisition Corp. to form Enterra
Energy Corp. (New Enterra). The principal undertaking of the Trust is to issue trust units and to acquire and hold debt
instruments, royalties and other interests. The direct and indirect wholly owned subsidiaries of
the Trust carry on the business of acquiring and holding interests in petroleum and natural gas
properties and assets related thereto. We make monthly cash distributions to Unitholders from our net cash flow. Our primary sources of
cash flow are interest payments from Enterra, and Rocky Mountain Acquisition Corp (RMAC) of
interest on the Notes and payments from EEC Trust of principal and interest on the CT Notes. Olympia Trust Company has been appointed as trustee under the Trust Indenture. The beneficiaries
of the Trust are holders of the outstanding trust units. The principal and head office of Olympia
Trust Company is located at 2300, 125  9th Avenue S.E., Calgary, Alberta T2G 0P6. Enterra Enterra is the principal operating subsidiary of the Trust. Enterra was formed on the amalgamation
of Enterra Acquisition Corp., Big Horn Resources Ltd., Enterra Sask. Ltd. and Old Enterra on
November 25, 2003 pursuant to the Arrangement and is governed by the laws of the Province of
Alberta. EEC Trust is the sole holder of voting shares of Enterra. All of the crude oil and
natural gas properties and related assets in which the Trust has an interest are held, directly or
indirectly, through Enterra, RMAC and Rocky Mountain Gas Inc. (RMG). RMAC Rocky Mountain Acquisition Corp. is a corporation created under the laws of Alberta and is another
operating subsidiary of the Trust in addition to Enterra. RMAC was created by the amalgamation of
a predecessor corporation (Old RMAC) with Rocky Mountain Energy Corp. (RME). Old RMAC was
incorporated for the purpose of acquiring RME and immediately following such acquisition, Old RMAC
and RME were amalgamated to form RMAC. EEC Trust is the sole holder of voting shares of RMAC. All
of the crude oil and natural gas properties and related assets in which the Trust has an interest
are held, directly or indirectly, through Enterra, RMAC and RMG. EUSA Enterra US Acquisitions Inc. (EUSA) is a corporation incorporated under the laws of Washington
for the purpose of acquiring RMG. EUSA is an indirect subsidiary of EEC Trust. RMG is a corporation incorporated under the laws of Wyoming. RMG was acquired effective June 1,
2005 and holds coal bed methane assets in Wyoming and Montana. All of the crude oil and natural
gas properties and related assets in which the Trust has an interest are held, directly and
indirectly, through Enterra, RMAC and RMG. The Partnership 21




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Enterra Production Partnership (the Partnership) was formed as a general partnership under the
laws of the Province of Alberta on August 16, 2001. The Partnership currently holds a significant
portion of our producing crude oil and natural gas properties from which we ultimately derive our
cash flow. The partners of the Partnership are Enterra (as to 99.99%) and Partnerco (as to 0.01%). EEC Trust Enterra Energy Commercial Trust is a commercial trust governed by the laws of the Province of
Alberta. The Trust holds 100% of the issued and outstanding trust units of EEC Trust. EEC Trust
holds 100% of the issued and outstanding common shares of Enterra and RMAC. History Old Enterra (formerly Westlinks Resources Ltd.) was organized on June 30, 1998 by the statutory
amalgamation of Temba Resources Ltd. and PTR Resources Ltd. pursuant to the provisions of the
Business Corporations Act(Alberta). Temba Resources Ltd. was incorporated in Alberta on July 31,
1996. Immediately prior to the amalgamation, which created Old Enterra, Temba Resources Ltd.,
amalgamated with its wholly owned subsidiary, Rainee Resources Ltd. PTR Resources Ltd. was
incorporated in Alberta on September 18, 1992 as 542275 Alberta Ltd., changed its name to Ablevest
Holdings Ltd. on June 14, 1993, and to PTR Resources Ltd. on December 1, 1997. In 1998, Old Enterra acquired a non-operated working interest averaging approximately 20% in a Dina
sand oil pool located in the Sounding Lake area of Alberta, consisting of 1,270 acres and
approximately 35 producing wells. In September 1999, Old Enterra acquired a 94% working interest in four producing oil wells and a
saltwater disposal well in the Sylvan Lake area of Alberta. In May 2000, Old Enterra acquired, effective January 1, 2000, further working interests in the
Sounding Lake area of Alberta, consisting of a further 36% working interest in the Dina sand oil
pool as well as working interests averaging approximately 91% in 21 producing oil wells. The
purchase price for such interests was $11,900,000. On November 15, 2000, Old Enterra sold, effective October 1, 2000, all of its interests in the
Bigoray area of Alberta for cash consideration of $4,494,500. Proceeds from the sale were used to
reduce Old Enterras bank debt and to fund its 2001 acquisition program. On December 6, 2000, Old Enterra acquired a 25% working interest in a producing gas well in the
Altares area of northeast British Columbia for cash consideration of $1,000,000. On January 17, 2001, Old Enterra completed a secondary public offering in the United States of
1,000,000 units, each unit consisting of one common share and one share purchase warrant, for U.S.
$4.55 per unit. The share purchase warrants were exercisable for six months at U.S. $4.50 per
share. Net proceeds from the offering were used for Old Enterras 2001 acquisition and drilling
program. On February 28, 2001, Old Enterra entered into a farm-out and option agreement whereby it was
granted the ability to earn an interest in over 12,000 acres of land in the Altares region of
northeast British Columbia. Under the terms of the farm-out and option agreement, Old Enterra was
obligated to drill a minimum of two wells and had an option to drill up to four more wells to earn
an interest in all of the lands. On March 27, 2001, Old Enterra acquired an average 67% working interest in 8,705 gross acres of
land and 34 producing oil wells in the Grand Forks area of southern Alberta for cash consideration
of $5,500,000. The effective date of the acquisition was January 1, 2001. On April 23, 2001, Old Enterra entered into the EuroGas Agreement. On June 5, 2001, Old Enterra
completed the acquisition of an aggregate of 8,275,500 Big Horn shares from EuroGas. 22




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On June 12, 2001, Old Enterra entered into an agreement with a private company to acquire certain
oil and gas assets in the Superb area of Saskatchewan. The purchase price for the assets was
$2,800,000, which amount was satisfied by the payment of $1,500,000 in cash and through the
issuance of Common Shares. Through this acquisition, Old Enterra acquired a 91% working interest
in four existing Waseca heavy oil wells with a combined production rate of approximately 180
bbls/d. Effective August 16, 2001, Westlinks and Big Horn Resources Ltd. entered into an agreement under
Section 192 of the Canada Business Corporations Act, whereby Big Horn shareholders were issued
Westlinks common shares and options in exchange for Big Horn common shares and options. Big Horn
was incorporated under the laws of the Province of Saskatchewan on February 16, 1960 as Contact
Gold Mines Ltd. On July 7, 1969, Big Horn changed its name to Contact Ventures Ltd. Big Horn was
continued under the Business Corporations Act(Saskatchewan) on December 28, 1979 and subsequently
continued under the Canada Business Corporations Acton September 9, 1982. On April 15, 1988, Big
Horn changed its name to West Pride Industries Corp. and on April 2, 1991 Big Horn consolidated its
common shares on a 4 for 1 basis. Effective September 7, 1993 Big Horn further consolidated its
common shares on a 7 for 1 basis and changed its name to Big Horn Resources Ltd. Effective December 10, 2001, Westlinks Resources Ltd. (i.e., Old Enterra) changed its name to
Enterra Energy Corp. On March 26, 2002, Old Enterra redeemed 6,123,870 of its Series I Preferred Shares for $2,300,000,
resulting in a gain of $2,905,290. On April 12, 2002, Old Enterra was granted a 30-day extension for the 1,000,000 share purchase
warrants which were exercisable until April 17, 2002. The expiry date was extended to May 17,
2002. The warrants expired on May 17, 2002 without being exercised. On October 8, 2002, Old Enterra raised $5 million for a sale-leaseback arrangement on some of its
production equipment. Old Enterra received $18.3 million in 2003 as proceeds on the sale of miscellaneous non-core
properties. These proceeds were applied to reduce bank debt and improve working capital. On June 20, 2003, Old Enterras common shares commenced trading on the Toronto Stock Exchange under
the symbol ENT. They were previously trading on the TSX Venture Exchange. On August 5, 2003, Old Enterra announced its intention to reorganize itself into an oil and gas
income trust. On September 30, 2003, Old Enterra redeemed all 611,803 outstanding Series I Preferred Shares for
$520,032. On October 27, 2003 The American Stock Exchange began trading in options in Old Enterra under the
symbol EMU Old Enterras plan of arrangement in respect of the reorganization of Old Enterra into Enterra
Energy Trust received overwhelming approval at the special shareholder meeting held on November 24,
2003. Shareholders voted 99.37% in favor of the arrangement resolution. The transaction also
received the approval of the Court of Queens Bench of Alberta on November 24, 2003. The
transaction became effective on November 25, 2003. The trust units of Enterra Energy Trust
commenced trading on the Nasdaq National Market System under EENC and the Toronto Stock Exchange
under ENT.UN on Friday November 28, 2003. After the transaction, the Trust had a total of
18,951,556 trust units issued and outstanding. In addition, Enterra had a total of 2,000,000
exchangeable shares issued and outstanding. On January 16, 2004 the Trust entered into a financing agreement whereby it issued 1,650,000 Trust
Units at a price of US$10.00 per unit for gross proceeds of US$16,500,000. The funds received from
this financing were applied to pay down debt and for corporate general purposes. The financing
closed on June 29, 2004. 23




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On January 30, 2004 Enterra closed the acquisition from an unrelated oil and gas company, of
properties in Central Alberta. The purchase price after final adjustments was C$19,609,000. Upon
closing, the acquisition added 1,800 boe/d of net production, consisting of 1,600 bbl/d of oil and
1,200 mcf/d of gas along with 22,166 gross acres of undeveloped land. On February 20, 2004 the Trust completed a private placement of 1,049,400 Trust Units at a price of
US$11.25 per unit for gross proceeds of US$11,805,750 (US$10,265,463 net of financing costs).
Funds received were used to repay debt. In June 2004, Enterra sold a small producing property in Provost area of Central Alberta with
proven reserves of 55.2 Mboe for C$263,366. In August 2004, Enterra sold a non-producing well in the Sylvan Lake area of Central Alberta for
C$400,000. On September 29, 2004, the Trust, through its subsidiary RMAC, completed the acquisition of RME by
way of a plan of arrangement whereby RMAC acquired all of the issued and outstanding shares of RME.
The transaction was valued at approximately C$55 million. RME shareholders received approximately
85% of the consideration in the form of Trust Units or Exchangeable Shares and 15% in cash. The
Trust issued 1,946,576 Trust Units and 341,882 Exchangeable Shares. The acquisition of RME added
approximately 1,000 boe/d of production to the Trust together with the potential to drill 22
additional wells. On April 22, 2005, the Trust entered into a committed equity financing facility with Kingsbridge
Capital Limited, pursuant to which Kingsbridge committed, subject to certain significant
limitations and conditions precedent, to purchase up to US$100 million of Trust Units. On May 30, 2005, the Trust and High Point Resources Inc. entered into an arrangement agreement for
the acquisition by the Trust of all of the issued and outstanding common shares of High Point. The
acquisition is to be completed by way of a plan of arrangement pursuant to which shareholders of
High Point will receive for each share of High Point held 0.105 of a trust unit of the Trust. The
closing price of the Trust Units on Friday, May 27th was C$25.41, valuing the common shares of High
Point at C$2.67 per share. High Point has approximately 85 million shares outstanding. The
transaction, including assumption of High Points debt of approximately US$67 million, has been
valued at approximately US$250 million. The Trust will be issuing approximately 8.9 million units
or approximately 34% of the total number of Trust Units currently outstanding. On June 1, 2005, the acquisition of Rocky Mountain Gas, Inc. closed. RMG holds natural gas assets
in Montana and Wyoming. A portion of the Wyoming assets currently generates net/net production of
approximately 2.2 million BTUs per day. RMG has approximately 130,000 net acres of production
rights to coal bed methane. The consideration consisted of US$14 million by the issuance of
exchangeable shares (exchangeable on a one-to-one basis into Trust Units), US$5.5 million by the
issuance of Trust Units and US$0.5 million in cash, which was paid as a deposit when the
acquisition agreement was signed. 24




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B. Business Overview Enterra Energy Trust operates as an oil and gas income trust. For the year ended December 31,
2004, our production averaged 6,957 boe/d and our proved and probable reserves were approximately
9.4 MBOE. We pay monthly cash distributions on the 15th day of each month to
Unitholders of record on the immediately preceding distribution record date. This amount was set
at US$0.10 per unit for the first three distributions. The following table sets forth the amount
of monthly cash distributions paid per Trust Unit by the Trust since the completion of the
Arrangement. Distribution per Trust Unit(US$)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
    
    $
    0.16
 
 Note:(1)
    
    This distribution was the first cash distribution of the Trust following the completion of
the Arrangement. Our growth will come mainly from future acquisition of properties to replenish our reserves.
These acquisitions will be financed in part with additional debt and with the issuance of trust
units. 25




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Business Strategy Our business strategy is to grow our oil and gas reserves and distributions by acquiring properties
that provide additional oil and gas production and potential for development upside. We are
focused on per unit growth. We will finance acquisitions with debt and equity, the optimal mix
being one that minimizes Unitholders dilution while maintaining a strong balance sheet. Our
ability to replace and grow our reserves over time is the key success factor in our business
strategy. Revenues Our revenue is obtained from the sale of oil and natural gas. The revenues for the last three
years were: For the year ended December 31,($000s)
    
    2004
    
    
    2003
    
    
    2002Revenue
    
    $
    108,293
    
    
    $
    72,097
    
    
    $
    25,746
 The business is not seasonal in nature. We produce the oil and gas and then sell the oil and
gas to marketing companies and integrated oil and gas companies that then arrange for the oil and
gas to be further refined and processed and they sell the refined products to the ultimate end
users. Employees At December 31, 2004, we and JED had collectively, 76 employees and consultants working in the
Calgary head office and in field operations. Under the Technical Services Agreements with JED, effective January 1, 2004, JED provides certain
staff to Enterra while Enterra provides offices and other administrative services to JED. As
consultants to Enterra, JEDs employees will be eligible to participate in benefit plans of
Enterra, if any. Office Facilities We currently lease 20,927 square feet of office space at Suite 2600, 500  4th Avenue S.W. in
Calgary, Alberta in a lease that commenced November 1, 2001. The lease has a term expiring on
December 31, 2009 and the annual rental is currently C$29.64 per square foot (including operating
costs and property taxes). We originally leased space in a different Calgary office building but
all of this space is subleased to third parties and the lease expires on August 31, 2006. Competition The petroleum industry is highly competitive. We compete with numerous other participants in the
acquisition of oil and gas leases and properties, and the recruitment of employees. Any company
can make acquisitions and bid on provincial leases in Alberta. Competitors include oil companies
and other income trusts, many of whom have greater financial resources, staff and facilities than
we have. Our ability to increase reserves in the future will depend not only on our ability to
develop existing properties, but also on our ability to select and acquire suitable additional
producing properties or prospects for drilling. We also compete with numerous other companies in
the marketing of oil. Competitive factors in the distribution and marketing of oil include price
and methods and reliability of delivery. Government Regulation in Canada The oil and natural gas industry is subject to extensive controls and regulations governing its
operations, including land tenure, exploration, development, production, refining, transportation
and marketing, imposed by legislation enacted by various levels of government and with respect to
pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta
and British Columbia, all of which should be carefully considered by investors in the Canadian oil
and gas industry. It is not expected that any of these controls or regulations will affect our
operations in a manner materially different from how they would affect other oil and gas companies
of similar size operating in Western Canada. All current legislation is a matter of public record
and we are unable to predict what additional legislation or amendments may be enacted. Outlined
below are some of the 26




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principal aspects of legislation, regulations and agreements governing the oil and gas industry. Pricing and Marketing  Oil and Natural Gas The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with
the result that the market determines the price of oil. Such price depends in part on oil quality,
prices of competing oils, distance to market, the value of refined products and the supply/demand
balance. Oil exporters are also entitled to enter into export contracts with terms not exceeding
one year in the case of light crude oil and two years in the case of heavy crude oil, provided that
an order approving such export has been obtained from the National Energy Board of Canada, or NEB.
Any oil export to be made pursuant to a contract of longer duration, to a maximum of 25 years,
requires an exporter to obtain an export license from the NEB and the issuance of such license
requires the approval of the Governor in Council. In addition, the prorationing of capacity on the
interprovincial pipeline systems continues to limit oil exports. The price of natural gas is determined by negotiation between buyers and sellers. Natural gas
exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters
are free to negotiate prices with purchasers, provided that the export contracts meet certain other
criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less
than two years or for a term of two to twenty years, in quantities of not more than 30,000
m3/day, must be made pursuant to an NEB order. Any natural gas export to be made
pursuant to a contract of longer duration, up to a maximum of 25 years, or a larger quantity,
requires an exporter to obtain an export license from the NEB and the issuance of such license
requires the approval of the Governor in Council. The governments of British Columbia and Alberta also regulate the volume of natural gas which may
be removed from those provinces for consumption elsewhere based on such factors as reserve ability,
transportation arrangements and market considerations. Provincial Royalties and Incentives In addition to federal regulation, each province has legislation and regulations, which govern land
tenure, royalties, production rates, environmental protection and other matters. The royalty
regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and
natural gas production. Royalties payable on production from lands other than Crown lands are
determined by negotiations between the mineral owner and the lessee, although production from such
lands is subject to certain provincial taxes and royalties. Crown royalties are determined by
governmental regulation and are generally calculated as a percentage of the value of the gross
production. The rate of royalties payable generally depends in part on prescribed reference
prices, well productivity, geographical location, field discovery date and the type or quality of
the petroleum product produced. From time to time the governments of the western Canadian provinces create incentive programs for
exploration and development. Such programs often provide for royalty rate reductions, royalty
holidays and tax credits, and are generally introduced when commodity prices are low. The programs
are designed to encourage exploration and development activity by improving earnings and cash flow
within the industry. In the Province of Alberta, a producer of oil or natural gas is entitled to a credit against the
royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit or, ARTC program. The
ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at
and below $100 per thousand cubic meters and 25% at prices at and above $210 per thousand cubic
meters. The ARTC rate is applied to a maximum of $2,000,000 of Alberta Crown royalties payable for
each producer or associated group of producers. Crown royalties on production from producing
properties acquired from a corporation claiming maximum entitlement to ARTC will generally not be
eligible for ARTC. The rate will be established quarterly based on the average par price, as
determined by the Alberta Department of Energy for the previous quarterly period. On December 22, 1997, the Alberta government announced that it was conducting a review of the ARTC
program with the objective of setting out better-targeted objectives for a smaller program and to
deal with administrative difficulties. On August 30, 1999, the Alberta government announced that
it would not be reducing the size of the program but that it would introduce new rules to reduce
the number of persons who qualify for the program. The new rules will preclude companies that pay
less than $10,000 in royalties per year and non-corporate entities from 27




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qualifying for the program. Such rules will not presently preclude Enterra from being eligible for the ARTC program. Crude oil and natural gas royalty holidays for specific wells and royalty reductions reduce the
amount of Crown royalties paid by Enterra to the provincial governments. In general, the ARTC
program provides a rebate on Alberta Crown royalties paid in respect of eligible producing
properties. Land Tenure Crude oil and natural gas located in the western provinces is owned predominantly by the respective
provincial governments. Provincial governments grant rights to explore for and produce oil and
natural gas pursuant to leases, licenses and permits for varying terms from two years and on
conditions set forth in provincial legislation including requirements to perform specific work or
make payments. Oil and natural gas located in such provinces can also be privately owned and
rights to explore for and produce such oil and natural gas are granted by lease on such terms and
conditions as may be negotiated. Environmental Regulation The oil and natural gas industry is currently subject to environmental regulations pursuant to a
variety of provincial and federal legislation. Such legislation provides for restrictions and
prohibitions on the release or emission of various substances produced in association with certain
oil and gas industry operations. In addition, such legislation requires that well and facility
sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with
such legislation can require significant expenditures and a breach of such requirements may result
in suspension or revocation of necessary licenses and authorizations, civil liability for pollution
damage and the imposition of material fines and penalties. Environmental legislation in the Province of Alberta has been consolidated into the Environmental
Protection and Enhancement Act, or EPEA, which came into force on September 1, 1993. The EPEA
imposes stricter environmental standards, requires more stringent compliance, reporting and
monitoring obligations and significantly increases penalties for violations. We are committed to
meeting our responsibilities to protect the environment wherever it operates and anticipates making
increased expenditures of both a capital and expense nature as a result of the increasingly
stringent laws relating to the protection of the environment and will be taking such steps as
required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which
it operates. We believe that we are in material compliance with applicable environmental laws and
regulations. We also believe that it is reasonably likely that the trend towards stricter
standards in environmental legislation and regulation will continue. 28




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Additional Information Relating to the Trust Income Streams and Distribution Policy A portion of the cash flows generated by the assets held, directly or indirectly, by the Trust is
distributed to holders of trust units. The Trustee may, in respect of any period, declare payable
to the Unitholders all or any part of the net income of the Trust. The Enterra Board currently intends to provide all Unitholders with monthly cash distributions of
approximately USD 80% of available cash flow from operations. However, the availability of cash
flows for the payment of distributions will at all times be dependant upon a number of factors,
including resource prices, production rates and reserve growth and the Enterra Board cannot assure
that cash flows will be available for distribution to Unitholders in the amounts anticipated or at
all. See Risk Factors. We make monthly cash distributions to Unitholders from our net cash flow. Our primary sources of
cash flow are interest payments from Enterra, and Rocky Mountain Acquisition Corp (RMAC) of
interest on the Notes and payments from EEC Trust of principal and interest on the CT Notes. The Notes Pursuant to the Arrangement, Enterra issued the Series A notes to the Trust (the Series A Notes).
The principal amount of the Series A Notes issued is $125,000,000. The Series A Notes are
unsecured and bear interest from the date of issue at 14% per annum. Interest is payable for each
month during the term on the 15th day of the month following such month. Enterra also issued other
notes to the Trust in 2004 in the amount of $36,679,530, bearing interest at 11%. RMAC issued
Series A notes, as well as other notes, to the Trust in 2004 in the aggregate amount of
$40,113,607, bearing interest at 11%. CT Note The CT Note is a subordinated, demand participating promissory note. The CT Note may bear interest
at a rate that can be re-set from time to time so as to approximate the taxable income of the EEC
Trust. Trust Units An unlimited number of trust units may be created and issued pursuant to the Trust Indenture. Each
trust unit entitles the holder thereof to one vote at any meeting of the holders of trust units and
represents an equal fractional undivided beneficial interest in any distribution from the Trust
(whether of net income, net realized capital gains or other amounts) and in any net assets of the
Trust in the event of termination or winding up of the Trust. All trust units rank among
themselves equally and rateably without discrimination, preference or priority. Each trust unit is
transferable, is not subject to any conversion or pre-emptive rights and entitles the holder
thereof to require the Trust to redeem any or all of the trust units held by such holder (see
"Redemption Right) and to one vote at all meetings of Unitholders for each trust unit held. In
addition, in certain circumstances Unitholders will have the right to instruct the trustees of EEC
Trust with respect to the voting of shares of Enterra held by EEC Trust at meetings of holders of
shares of Enterra. See Meetings of Unitholders and Exercise of Voting Rights. The trust units do not represent a traditional investment and should not be viewed by investors as
shares in either Enterra, or the Trust. As holders of trust units in the Trust, Unitholders will
not have the statutory rights normally associated with ownership of shares of a corporation
including, for example, the right to bring oppression or derivative actions. The price per trust unit is a function of anticipated distributable income generated by the Trust
and the ability of the Trust to effect long-term growth in the value of the Trust. The market
price of the trust units is sensitive to a variety of market conditions including, but not limited
to, interest rates, commodity prices and our ability to acquire additional assets. Changes in
market conditions may adversely affect the trading price of the trust units. The trust units are not deposits within the meaning of the Canada Deposit Insurance Corporation
Act (Canada) and 29




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are not insured under the provisions of that Act or any other legislation. Furthermore, the Trust
is not a trust company and, accordingly, is not registered under any trust and loan company
legislation, as it does not carry on or intend to carry on the business of a trust company. Special Voting Rights The Trust Indenture allows for the creation of Special Voting Rights which will enable the Trust to
provide voting rights to holders of Exchangeable Shares and, in the future, to holders of other
exchangeable shares that may be issued by Enterra or other subsidiaries of the Trust in connection
with other exchangeable share transactions. Holders of Special Voting Rights are not be entitled to any distributions of any nature whatsoever
from the Trust and each holder shall be entitled to attend at meetings of Unitholders and, subject
to the terms of the instrument creating the Special Voting Rights, is entitled to that number of
votes equal to the number of votes attached to the trust units for which the Special Voting Rights
held by such holder are exchangeable, exercisable or convertible. Holders of Special Voting Rights
are also be entitled to receive all notices, communications or other documentation required to be
given or otherwise sent to holders of trust units. Except for the right to attend and vote at
meetings of Unitholders and receive notices, communications and other documentation sent to
Unitholders, the Special Voting Rights do not confer upon the holders thereof any other rights. Under the terms of the Voting and Exchange Trust Agreement, the Trust has issued a Special Voting
Right to the Voting and Exchange Trust Agreement Trustee for the benefit of every person who
received Exchangeable Shares pursuant to the Arrangement. Some of these Exchangeable Shares still
remain outstanding. Unitholder Limited Liability The Trust Indenture provides that no unitholder, in its capacity as such, shall incur or be subject
to any liability in contract or in tort in connection with the Trust or its obligations or affairs
and, in the event that a court determines Unitholders are subject to any such liabilities, the
liabilities will be enforceable only against, and will be satisfied only out of the Trusts assets.
Pursuant to the Trust Indenture, the Trust will indemnify and hold harmless each unitholder from
any costs, damages, liabilities, expenses, charges or losses suffered by a unitholder from or
arising as a result of such unitholder not having such limited liability. The Trust Indenture
provides that all contracts signed by or on behalf of the Trust must contain a provision to the
effect that such obligation will not be binding upon Unitholders personally. Notwithstanding the
foregoing, Unitholders of the Trust may not be protected from certain liabilities of the Trust.
See Risk Factors. The activities of the Trust and its subsidiaries are conducted in such a way and in such
jurisdictions as to avoid as far as possible any material risk of liability to the Unitholders for
claims against the Trust including by obtaining appropriate insurance, where available, and having
contracts signed by or on behalf of the Trust include a provision that such obligations are not
binding upon Unitholders personally. Redemption Right Trust units are redeemable at any time on demand by the holders thereof upon delivery to the
transfer agent of the Trust of the certificate or certificates representing such trust units,
accompanied by a duly completed and properly executed notice requiring redemption. Upon receipt of
the notice to redeem trust units by the transfer agent, the holder thereof shall only be entitled
to receive a price per trust unit (the Market Redemption Price) equal to the lesser of: (i) 90%
of the market price of the trust units on the principal market on which the trust units are
quoted for trading during the 10 trading day period commencing immediately after the date on which
the trust units are tendered to the Trust for redemption; and (ii) the closing market price on the
principal market on which the trust units are quoted for trading on the date that the trust units
are so tendered for redemption. Where more than one market exists for the trust units, the
principal market shall mean the market on which the trust units experience the greatest volume of
trading activity on the date or for the period in question, as applicable. For the purposes of this calculation, market price is an amount equal to the simple average of
the closing price of the trust units for each of the trading days on which there was a closing
price; provided that, if the applicable exchange or market does not provide a closing price but
only provides the highest and lowest prices of the trust units 30




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traded on a particular day, the market price shall be an amount equal to the simple average of the
average of the highest and lowest prices for each of the trading days on which there was a trade;
and provided further that if there was trading on the applicable exchange or market for fewer than
five of the 10 trading days, the market price shall be the simple average of the following prices
established for each of the 10 trading days: the average of the last bid and last ask prices for
each day on which there was no trading; the closing price of the trust units for each day that
there was trading if the exchange or market provides a closing price; and the average of the
highest and lowest prices of the trust units for each day that there was trading, if the market
provides only the highest and lowest prices of trust units traded on a particular day. The closing
market price is: an amount equal to the closing price of the trust units if there was a trade on
the date; an amount equal to the average of the highest and lowest prices of the trust units if
there was trading and the exchange or other market provides only the highest and lowest prices of
trust units traded on a particular day; and the average of the last bid and last ask prices if
there was no trading on the date. The aggregate Market Redemption Price payable by the Trust in respect of any trust units
surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on
the last day of the following month. The entitlement of Unitholders to receive cash upon the
redemption of their trust units is subject to the limitation that the total amount payable by the
Trust in respect of such trust units and all other trust units tendered for redemption in the same
calendar month and in any preceding calendar month during the same year shall not exceed $100,000;
provided that Enterra may, in its sole discretion, waive such limitation in respect of any calendar
month. If this limitation is not so waived, the Market Redemption Price payable by the Trust in
respect of trust units tendered for redemption in such calendar month shall be paid on the last day
of the following month as follows: (i) firstly, by the Trust distributing Series A Notes having an
aggregate principal amount equal to the aggregate Market Redemption Price of the trust units
tendered for redemption, and (ii) secondly, to the extent that the Trust does not hold Series A
Notes having a sufficient principal amount outstanding to effect such payment, by the Trust issuing
its own promissory notes to the Unitholders who exercised the right of redemption having an
aggregate principal amount equal to any such shortfall (herein referred to as Redemption Notes).
Notwithstanding the foregoing, the distribution of any Series A Notes and the issuance of any
Redemption Notes shall be conditional upon the receipt of all necessary regulatory approvals and
the making of all necessary governmental registrations, declarations and filings, including,
without limitation, any required registration of the Series A Notes or Redemption Notes, as
applicable, to be distributed or issued in respect of the payment of the Market Redemption Price,
and any required qualification of the Trust Indenture relating to such Series A Notes or Redemption
Notes, under the securities laws of the United States. If at the time trust units are tendered for redemption by a unitholder, (i) the outstanding trust
units are not listed for trading on the TSX or Nasdaq and are not traded or quoted on any other
stock exchange or market which Enterra considers, in its sole discretion, provides representative
fair market value price for the trust units, or (ii) trading of the outstanding trust units is
suspended or halted on any stock exchange on which the trust units are listed for trading or, if
not so listed, on any market on which the trust units are quoted for trading, on the date such
trust units are tendered for redemption or for more than five trading days during the 10 trading
day period, commencing immediately after the date such trust units were tendered for redemption
then such unitholder shall, instead of the Market Redemption Price, be entitled to receive a price
per trust unit (the Appraised Redemption Price) equal to 90% of the fair market value thereof as
determined by Enterra as at the date on which such trust units were tendered for redemption. The
aggregate Appraised Redemption Price payable by the Trust in respect of trust units tendered for
redemption in any calendar month shall be paid on the last day of the third following month by, at
the option of the Trust: (i) a cash payment; or (ii) a distribution of Series A Notes and/or
Redemption Notes as described above. It is anticipated that this redemption right will not be the primary mechanism for holders of trust
units to dispose of their trust units. Series A Notes or Redemption Notes which may be distributed
in specie to Unitholders in connection with a redemption will not be listed on any stock exchange
and no market is expected to develop in such Series A Notes or Redemption Notes. Series A Notes or
Redemption Notes may not be qualified investments for trusts governed by registered retirement
savings plans, registered retirement income funds, deferred profit sharing plans and registered
education savings plans. Meetings of Unitholders The Trust Indenture provides that meetings of Unitholders must be called and held for, among other
matters, the election or removal of the Trustee, the appointment or removal of the auditors of the
Trust, the approval of 31




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amendments to the Trust Indenture (except as described under Amendments to the Trust Indenture),
the sale of the property of the Trust as an entirety or substantially as an entirety, and the
commencement of winding up the affairs of the Trust. A meeting of Unitholders may be convened at any time and for any purpose by the Trustee and must be
convened, except in certain circumstances, if requisitioned in writing by (i) Enterra or (ii) the
holders of trust units and Special Voting Rights holding in aggregate not less than 5% of the votes
entitled to be voted at a meeting of Unitholders. A requisition must, among other things, state in
reasonable detail the business purpose for which the meeting is to be called. Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a
proxy holder need not be a unitholder. Two persons present in person or represented by proxy and
representing in the aggregate at least 5% of the votes attaching to all outstanding trust units
shall constitute a quorum for the transaction of business at all such meetings. For the purposes
of determining such quorum, the holders of any issued Special Voting Rights who are present at the
meeting shall be regarded as representing outstanding trust units equivalent in number to the votes
attaching to such Special Voting Rights. The Trust Indenture contains provisions as to the notice required and other procedures with respect
to the calling and holding of meetings of Unitholders in accordance with the requirements of
applicable laws. Voting Of EEC trust units There will be a meeting of the holders of EEC trust units immediately following each meeting of
Unitholders for the purpose of permitting the Trustee to vote the EEC trust units held by the Trust
in the manner directed by Unitholders at the immediately preceding meeting of the Trust. Any
resolution passed by Unitholders pertaining to the manner in which EEC trust units held by the
Trust are to be voted by the Trustee in respect of a particular matter which is to be put forth to
the holders of EEC trust units for vote at a contemplated meeting (including by written resolution)
of holders of EEC trust units, shall be deemed to be a direction to the Trustee in respect of the
EEC trust units held by the Trust to, as applicable, either vote such EEC trust units in favor of
or in opposition to, or to vote or with-hold from voting in respect of such matter in equal
proportions to the votes cast by Unitholders in respect of the matter, and the Trustee is obligated
to vote, in respect of such matter if put forth to the holders of EEC trust units at a meeting of
such holders, the EEC trust units held by the Trust in accordance with such direction. Exercise of Voting Rights The Trustee is prohibited from authorizing or approving:  (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; without the prior approval of the Unitholders by Special Resolution at a meeting of Unitholders
called for that purpose. In addition, the Trustee is prohibited from authorizing the EEC trustees to approve, or vote any
shares of Enterra to approve:  (a)
    
    any sale, lease or other disposition of, or any interest in, all or substantially all of the
assets owned, directly 32




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or indirectly, by Enterra, the Trust or the Partnership, except in conjunction with an
internal reorganization of the direct or indirect assets of Enterra, EEC Trust or the
Partnership, as the case may be, as a result of which EEC 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 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; without the prior approval of the Unitholders by Special Resolution at a meeting of Unitholders
called for that purpose. The Trustee is prohibited from authorizing the EEC trustees to vote any shares of Enterra with
respect to the election of directors of Enterra, the appointment of auditors of Enterra, or the
approval of Enterras financial statements, without the prior approval of the Unitholders by
Ordinary Resolution. Finally, the Trustee is prohibited from authorizing the EEC trustees to vote
any shares of Enterra with respect to any matter which under applicable law (including policies of
Canadian securities commissions) or applicable stock exchange rules would require the approval of
the holders of shares of Enterra by ordinary resolution or special resolution, without the prior
approval of the Unitholders by Ordinary Resolution or Special Resolution, as the case may be. Trustee Olympia Trust Company is the trustee of the Trust. The Trustee is responsible for, among other
things, accepting subscriptions for trust units and issuing trust units pursuant thereto,
maintaining the books and records of the Trust and providing timely reports to holders of trust
units. The Trust Indenture provides that the Trustee shall exercise its powers and carry out its
functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and
the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and
skill that a reasonably prudent trustee would exercise in comparable circumstances. The initial term of the Trustees appointment is until the third annual meeting of Unitholders.
The Unitholders shall, at the third annual meeting of Unitholders, re-appoint, or appoint a
successor to the Trustee for an additional three year term, and thereafter, the Unitholders shall
reappoint or appoint a successor to the Trustee at the annual meeting of Unitholders three years
following the reappointment or appointment of the successor to the Trustee. The Trustee may also
be removed by Special Resolution of the Unitholders. Such resignation or removal becomes effective
upon the acceptance or appointment of a successor trustee. Delegation of Authority, Administration and Trust Governance The Enterra Board has generally been delegated the significant management decisions of the Trust.
In particular, the Trustee has delegated to Enterra responsibility for any and all matters relating
to the following: (i) an offering of securities of the Trust; (ii) ensuring compliance with all
applicable laws, including in relation to an offering of securities of the Trust; (iii) all matters
relating to the content of any offering documents, the accuracy of the 33




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disclosure contained therein and the certification thereof; (iv) all matters concerning the terms
of, and amendment from time to time of the material contracts of the Trust; (v) all matters
concerning any underwriting or agency agreement providing for the sale of trust units or rights to
trust units; (vi) all matters relating to the redemption of trust units; (vii) all matters relating
to the voting rights on any instruments held by the Trust, other than the EEC trust units; and
(viii) all matters relating to the specific powers and authorities as set forth in the Trust
Indenture. Liability of The Trustee The Trustee, its directors, officers, employees, shareholders and agents is not be liable to any
unitholder or any other person, in tort, contract or otherwise, in connection with any matter
pertaining to the Trust or the property of the Trust, arising from the exercise by the Trustee of
any powers, authorities or discretion conferred under the Trust Indenture, including, without
limitation, any action taken or not taken in good faith in reliance on any documents that are,
prima facie, properly executed, any depreciation of, or loss to, the property of the Trust incurred
by reason of the sale of any asset, any inaccuracy in any evaluation provided by any other
appropriately qualified person, any reliance on any such evaluation, any action or failure to act
of Enterra, or any other person to whom the Trustee has, with the consent of Enterra, delegated any
of its duties hereunder, or any other action or failure to act (including failure to compel in any
way any former trustee to redress any breach of trust or any failure by Enterra to perform its
duties under or delegated to it under the Trust Indenture or any other contract), unless such
liabilities arise out of the gross negligence, wilful default or fraud of the Trustee or any of its
directors, officers, employees or shareholders. If the Trustee has retained an appropriate expert,
adviser or legal counsel with respect to any matter connected with its duties under the Trust
Indenture, the Trustee may act or refuse to act based on the advice of such expert, adviser or
legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss
or liability occasioned by any action or refusal to act based on the advice of any such expert,
adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon
the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting
as Trustee of the assets of the Trust and shall not be subject to any personal liability for any
debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or
with respect to the Trust or the property of the Trust. In addition, the Trust Indenture contains
other customary provisions limiting the liability of the Trustee. Amendments to The Trust Indenture The Trust Indenture may be amended or altered from time to time by special resolution of the
Unitholders. The Trustee may, without the approval of any of the Unitholders, amend the Trust
Indenture for, among others, the following purposes:  (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 34




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omissions, provided that in the opinion of the Trustee the rights of the Trustee and of the
Unitholders are not prejudiced thereby; and  (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 Unitholders may vote to terminate the Trust at any meeting of Unitholders duly called for that
purpose, subject to the following: (a) a vote may only be held if requested in writing by the
holders of not less than 20% of the outstanding trust units and special voting rights; (b) a quorum
of 50% of the issued and outstanding trust units and special voting rights is present in person or
by proxy; and (c) the termination must be approved by special resolution. Unless the Trust is earlier terminated or extended by vote of the Unitholders, the Trust shall
continue in full force and effect for a period which shall end twenty-one years after the date of
death of the last surviving issue of Her Majesty, Queen Elizabeth II. In the event that the Trust
is wound up, the Trustee will sell and convert into money the property of the Trust in one
transaction or in a series of transactions at public or private sale and do all other acts
appropriate to liquidate the property of the Trust in accordance with any applicable laws or
requirements of any governmental agency or authority, and shall in all respects act in accordance
with the directions, if any, of the Unitholders in respect of termination authorized pursuant to
the special resolution of the Unitholders authorizing the termination of the Trust. After paying,
retiring or discharging or making provision for the payment, retirement or discharge of all known
liabilities and obligations of the Trust and providing for indemnity against any other outstanding
liabilities and obligations, the Trustee shall distribute the remaining part of the proceeds of the
sale of the assets together with any cash forming part of the property of the Trust among the
Unitholders in accordance with their pro rata interests. Reporting to Unitholders The financial statements of the Trust are audited annually by an independent recognized firm of
chartered accountants. The audited financial statements of the Trust, together with the report of
such chartered accountants, will be mailed by the Trustee to Unitholders and the unaudited interim
financial statements of the Trust will be mailed to Unitholders within the periods prescribed by
securities legislation. The year-end of the Trust shall be December 31. The Trust is subject to
the continuous disclosure obligations under all applicable securities legislation. The Trust is subject to the reporting requirements of the 1934 Act applicable to foreign private
issuers, and in connection therewith will file or submit reports, including annual reports and
other information with the U.S. Securities and Exchange Commission (the SEC). Such reports and
other information can be inspected and copied at the public reference facilities maintained by the
SEC at 450 Fifth Street, N.W., Room 1024, Judiciary Plaza, Washington, D.C. The Trusts SEC
filings and submissions will also be available to the public on the SECs web site at
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C. Organizational Structure The following diagram depicts the intercorporate relationships among the Trust and its
subsidiaries. Reference should be made to Item 4.A of this report for a complete description of
our structure. (FLOW CHART) 36




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D. Property, plants and equipment The Trusts core areas include the Peace River Arch area of Alberta and Central Alberta in Canada.
The Trust also has a large inventory of prospects, the development of which could significantly
increase the size of our existing production and reserve base. (MAP) Peace River Arch of Alberta, Canada Clair
The Clair property is located 7 miles north of the city of Grande Prairie, Alberta. Enterras
assets include a 100% working interest in 3,840 acres of land, 23 producing oil wells and an oil
treating facility. Gas is conserved and processed at the Encana Sexsmith gas plant. Production is primarily from the Doe Creek (Dunvegan) formation with a small amount of gas
production from the Charlie Lake and Halfway formations. Production is light, 44-degree API
gravity crude oil and solution gas from the Doe Creek oil pool. At December 31, 2004 there were 23
oil wells producing a combined 2,860 bbl/d of oil and 910 mcf/d of solution gas on a working
interest basis before royalties. One dually completed Charlie Lake and Halfway gas well also
produces combined daily gas of 400 mcf/d on a working interest basis before royalties. Enterra has
a 100% working interest in this well. To date, Enterra has drilled or re-completed 29 wells for
oil and seven wells for water injection. There are no further drilling plans for the pool.
Enterra is currently maintaining 37




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100% voidage replacement with minor water flood modifications made
in early 2004. The oil production has been maintained since 2003 due to successful modifications
to the water flood. Total proved remaining net proved reserves assigned to the Doe Creek A (Dunvegan) pool are 1,426
mbbl of oil, 912 mmcf of gas and 54 mbbl of natural gas liquids. McDaniel and Associates have
stated that the additional reserves associated with the water flood would be moved into the proven
category in a staged approach as they have for the last two years. Included
in the total net proved reserves of Clair are reserves assigned to the 13-07-073-5W6 Charlie Lake /
Halfway gas well of 265 mmcf of gas and 16 mbbl of natural gas liquids. Enterra also owns and operates a central oil treating facility at Clair, which is connected into
the Pembina Peace Pipeline system in September 2003. Hines Creek
The Hines Creek property is located 94 miles north of the city of Grande Prairie, Alberta.
Enterras assets include a 15% working interest in 5,750 gross acres of land and one producing gas
well. Two wells were drilled in the first quarter of 2005 and, as this is a winter only drilling
area, the remaining two wells will be drilled in 2006. Total net proved reserves assigned to the Hines Creek property are 368 mmcf of gas. The gas is transported three miles north through a non-operated pipeline to a main feeder line to a
central non-operated facility. Central Alberta, Canada Provost
The Provost property is located southwest of the town of Provost, Alberta. Major areas within the
package are Alliance, Sounding Lake, Monitor, Provost Cummings Y Unit and Wainwright. Enterras
assets include an average working interest of 70% in 52,000 gross acres of land as well as 245
producing oil wells and 19 producing gas wells. Production is obtained primarily from the Dina,
Cummings and Belly River formations. Enterras share of current production for the entire area is
1,500 bbl/d of oil and 3,050 mcf/d of gas on a working interest basis before royalties. In order
to optimize production and lower operating costs, Enterra has and continues to upgrade pump sizes
to maximize oil production and upgrade or consolidate oil batteries to handle higher volumes of
total fluid and injection water. Solution gas is currently conserved at most of the oil batteries. Enterra drilled four oil wells in the Cummings Y Unit in 2004 to bring the total number of oil
producers to 21. Due to the success of this drilling program, Enterra has decided to drill another
nine wells in the Unit for oil production. In order to lower operating costs and optimize reserve
recovery from the Cummings Y pool, Enterra is also in the process of constructing a central
facility to ship clean oil and re-inject produced water into the pool. Makeup water from several
source wells will be used to maintain voidage replacement at 100%. Enterra was assigned net proved reserves at Provost of 1,569 mbbl of oil, 1,208 mmcf of natural gas
and 32 mbbl of natural gas liquids. Princess/ Tide Lake
The Princess/ Tide Lake property was acquired from Rocky Mountain Energy Corp., and is now being
operated under RMAC, a wholly owned subsidiary of the Trust. RMAC has an average working interest
of 50% in 25,000 acres in the Princess area. Production is primarily from the Sunburst and Pekisko
formations. Sunburst production consists of gas and 23 degree API crude oil. In December 2004, 8
wells were producing 304 bbl/d net (330 bbl/d gross) of crude oil and 540 mcf/d net (750 mcf/d)
gross of natural gas from the Sunburst formation on a working interest basis before royalties. The
Pekisko production consists of gas and 27 degree API crude oil. As of December 2004, 17 Pekisko
oil wells were producing 343 bbl/d of crude oil and 670 mcf/d of natural gas from the Pekisko
formation on a working interest basis before royalties. Two wells have been drilled and completed
in the Sunburst formation with seven more planned upon the approval of a pending down-spacing
application. Six wells have been drilled and completed in the Pekisko formation, with two more
planned. 38




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Enterra has an average working interest of 50% of 3,040 acres in the Tide Lake area. Production,
consisting of 27 degree API oil, is from the Pekisko formation. In December 2004, there were 3
wells producing 51 bbl/day of crude and 50 mcf/d of natural gas from the Pekisko formation on a
working interest basis before royalties. Two development wells have been drilled and completed in
the Pekisko in 2004 and two more are planned for 2005. McDaniel has assigned total net proved remaining reserves of 676 mbbl of oil, 1,278 mmcf of natural
gas and 22 mbbl of natural gas liquids. Sylvan Lake
The Sylvan Lake property is located 24 miles west of the town of Red Deer, Alberta. Enterras
assets include an average working interest of 72% in 4,320 gross acres of land as well as 27
producing oil wells and 1 producing gas well. Enterra
completed the development of 40-acre spacing wells in the Pekisko G pool, and also drilled four
subsequent oil wells on 20 acre spacing. At December 31, 2004, the field was producing 680 bbl/day
of 14 degree API oil from 27 wells with 815 mcf/d of associated gas plus an additional 60 mcf/d of
non-associated gas on a working interest basis before royalties. Production is flow lined into an
Enterra operated central treating facility. Non-associated gas is conserved and flow lined to the
Husky Sylvan Lake gas plant. Clean oil is trucked from the facility to sales. McDaniel and Associates has assigned total proved remaining reserves of 1,055 mbbl of oil, 692 mmcf
of solution gas, 25 mmcf of non-associated gas and 61 mbbl of natural gas liquids. Based on the
success of the 4-well 2004 drilling program, Enterra may drill three wells with further down
spacing in other areas of the pool. The reservoir has net pays up to 40 m (130 ft). Enterra owns
a 3-D seismic program that covers the Sylvan Lake Pekisko G pool. 39




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Reserves Summary
Enterra Energy Trust is required to comply with the National Instrument 51-101, issued by the
Canadian Securities Administrators, in all its reserves related disclosures. NI 51-101 came into
effect on September 30, 2003 and is applicable for financial years ended on or after December 31,
2003. NI 51-101 brought about significant changes in which reporting issuers manage and publicly
disclose information relating to their oil and gas reserves, mandates annual disclosure
requirements and prescribes new reserve definitions as follows: Proved reserves (P90)- this is a conservative estimate of remaining reserves. For reported
reserves this means there must be at least a 90 percent probability that the quantities actually
recovered will equal or exceed the estimated proved reserves. Proved plus Probable (P50)- this is a reasonable estimate of remaining reserves. For reported
reserves there must be at least a 50 percent probability that the quantities actually recovered
will equal or exceed the sum of the proved plus probable reserves. The probable reserves will no
longer be risked by 50 percent as they are implicitly risked due to the nature of the new
definition of reserves. The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of
oil and gas activities by reporting issuers and elevate reserves reporting to a higher level of
accountability. In the United States, registrants are required to disclose reserves using the standards contained
in U.S. Regulation S-X, and the standardized measure of discounted future net cash flows relating
to proved oil and gas reserves determined in accordance with United States Statement of Financial
Accounting Standards No.69 Disclosures About Oil and Gas Producing Activities (FAS 69). Such
information is contained in Supplemental disclosure about Oil and Gas activities. Unless otherwise indicated, all of the reserves and production
information disclosure in this Form 20-F is in compliance with Industry Guide 2. The primary differences between the U.S. requirements and the NI 51-101 requirements are that (i)
the U.S. standards require disclosure only of proved reserves, whereas NI 51-101 requires
disclosure of proved and probable reserves, and (ii) the U.S. standards require that the reserves
and related future net revenue be estimated under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made, whereas NI 51-101 requires disclosure of
proved reserves and the related future net revenue estimated using constant prices and costs as at
the last day of the financial year, and of proved and probable reserves and related future net
revenue using forecast prices and costs. The definitions of proved reserves also differ, but
according to the Canadian Oil and Gas Evaluation Handbook (the reference source for the definition
of proved reserves under NI 51-101), differences in the estimated proved reserve quantities based
on constant prices should not be material. Enterra concurs with this assessment. In this Form 20-F, certain natural gas volumes have been converted to barrels of oil equivalent
(BOEs) on the basis of six thousand cubic feet (Mcf) to one barrel (bbl). BOEs may be
misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one bbl is
based on an energy equivalency conversion method primarily applicable at the burner tip and does
not represent equivalency at the wellhead. Net proved reserve volumes at December 31, 2004 are based on Enterras interest in its total proved
reserves after royalties as defined in FAS 69. Gross proved reserve volumes at December 31, 2004
are based on Enterras interest in its total proved reserves before royalties. The Trust has its reserves evaluated by independent engineers every year. McDaniel and Associates
Consultants Ltd. (McDaniel) independently evaluated the Enterras reserves at December 31, 2004.
These recovery and reserve estimates in the described properties are estimates only; the actual
reserves in the properties in which we have an interest may be more or less than those calculated.
The extent and character of the material information supplied by Enterra including, but not limited
to, ownership, well data, production, price, revenues, operating costs and contracts were relied
upon by McDaniel in preparing the report. In the absence of such information, McDaniel relied upon
their opinion of reasonable practice in the industry. Additional information can be found in our
Renewal Annual Information Form filed on the internet at www.sedar.com. 40




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##### Table of Contents



Reserve Quantity Information Estimated 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 (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
 Proved developed reserves are defined as reserves that can be expected to be recovered through
existing wells with existing facilities and operating methods.
Proved undeveloped reserves are defined as reserves that can be expected to be recovered through
the drilling of additional wells and building of additional facilities. 41




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##### Table of Contents



Production The following table summarizes the Trusts working interest production, before royalties, during
the periods indicated: 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
 Definitions: BOEPD means barrels of oil equivalent produced per day.
MBOE means thousands of barrels of oil equivalent,
meaning one barrel of oil or one barrel of natural gas liquids or ten mcf of natural gas.
MBbls means thousands of barrels, with respect to production of crude oil or natural gas liquids.
MMcf means millions of cubic feet, with respect to production of natural gas.
NGLs means natural gas liquids, being those hydrocarbon components recovered from raw natural
gas as liquids by processing through extraction plants or recovered from field separators,
scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane,
propane, butanes and pentanes plus, or a combination thereof. Oil and Gas Wells The following table summarizes the Trusts interest in producing and non-producing oil and gas
wells as at December 31, 2004: 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
 42




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##### Table of Contents



Land Holdings At December 31, 2004 the Trust had the following 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
 The number of net acres for which the Trusts rights to explore, develop or exploit will, absent
further action, expire within one year are 889 acres in Canada and 9,851 acres in the US for a
total of 10,740 acres. Drilling Activity The Trusts drilling history is as follows: 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)
 Notes:
(1) Gross wells mean the number of whole wells.
(2) Net wells means Enterras aggregate working interests in the gross wells.
(3) All wells were development wells, except for 3 (net 3.0)
exploration wells drilled in 2003, all of which were abandoned Present Activities During the three month period ended March 31, 2005, the Trust drilled the following development
wells: 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 The Trust has not entered into obligations to provide a fixed and determinable quantity of oil or
gas in the near future under existing contracts or agreements. Enterra has never been unable to
meet any significant delivery commitments. 43




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##### Table of Contents



ITEM 5. Operating and Financial Review and Prospects Overview The following should be read in conjunction with other financial information included in this
annual report on 20-F and with the consolidated financial statements of Enterra Energy Trust (the
Trust) contained in the 2004 Annual Report. All amounts are stated in Canadian dollars and in
accordance with Canadian Generally Accepted Accounting Principles (GAAP) except where otherwise
indicated. Natural gas volumes have been converted to a crude oil equivalent using a ratio of 6
mcf to 1 bbl of oil. Discussion with regard to the Trusts 2005 outlook is based on currently
available information. 5.A Operating Results Comparison of the Year Ended December 31, 2004 to the Year Ended December 31, 2003 Critical Accounting Policies The Trust follows the full cost method of accounting for oil and natural gas properties and
equipment whereby we capitalize all costs relating to its acquisition of, exploration for and
development of oil and natural gas reserves. The Trusts consolidated financial condition and
results of operations are sensitive to, and may be adversely affected by, a number of subjective or
complex judgments relating to methods, assumptions or estimates required under the full cost method
of accounting concerning the effect of matters that are inherently uncertain. For example:  (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 In 2004 production revenue increased by 50% from 2003 to $108.3 million (2003  $72.1 million).
During the year we experienced a 10% increase in commodity pricing from the previous year and
production increased by 38% to 6,957 boe per day (2003  5,024 boe/day). The Trusts production in 2004 averaged 6,957 boe/day, consisting of 5,821 bbls/day of oil and
6,817 mcf/day of natural gas, on a mix of 84% oil and 16% natural gas. Enterras production in
2003 averaged 5,024 boe/day, consisting of 3,862 bbls/day of oil and 6,972 mcf/day of natural gas,
on a mix of 77% oil and 23% natural gas. 44




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##### 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
    
    
    ChangeExit 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 flow from operations (1)
    
    $
    14,103
    
    
    $
    1,704
    
    
    
    727
    %
    
    $
    50,242
    
    
    $
    30,693
    
    
    
    64
    %Cash flow per unit (1)
    
    $
    0.54
    
    
    $
    0.08
    
    
    
    544
    %
    
    $
    2.15
    
    
    $
    1.62
    
    
    
    33
    %Net earnings (loss)
    
    $
    3,417
    
    
    $
    (5,086
    )
    
    
    167
    %
    
    $
    14,764
    
    
    $
    5,098
    
    
    
    190
    %Net earnings (loss) per unit
    
    $
    0.13
    
    
    $
    (0.25
    )
    
    
    149
    %
    
    $
    0.63
    
    
    $
    0.27
    
    
    
    135
    %Average number of units outstanding
    
    
    25,974
    
    
    
    20,205
    
    
    
    37
    %
    
    
    23,328
    
    
    
    18,954
    
    
    
    23
    %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)
    
    Cash flow from operations is a non-GAAP measure. Cash flow from operations is
reconciled to GAAP earnings in the cash flow section below. The Trusts production in Q4 of 2004 averaged 7,925 boe/day, consisting of
6,766 bbls/day of oil and 6,954 mcf/day of natural gas, for a mix of 84% oil and 16% natural gas.
The Trusts production in Q4 of 2003 averaged 5,206 boe/day, consisting of 4,110 bbls/day of oil
and 6,572 mcf/day of natural gas, for a mix of 79% oil and 21% natural gas. The Trust exited 2004 at a rate of 7,258 boe/day, consisting of 5,905 bbls/day of oil and 8,118
mcf/day of natural gas, for a mix of 81% oil and 19% natural gas. This represents a 12% increase
over the 2003 exit rate of 6,460 boe/day. 45




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##### Table of Contents



3 YEAR SUMMARY SUMMARIZED FINANCIAL AND OPERATIONAL DATA(in
    
    Year
    
    
    Year
    
    
    YearThousands except for volumes and per unit amounts)
    
    2004
    
    
    2003
    
    
    2002Revenue
    
    $
    108,293
    
    
    $
    72,097
    
    
    $
    25,746Cash flow from operations (1)
    
    $
    50,242
    
    
    $
    30,693
    
    
    $
    11,901Cash flow from operations per unit  basic (1)
    
    $
    2.15
    
    
    $
    1.62
    
    
    $
    0.65Cash flow from operations per unit  diluted (1)
    
    $
    2.13
    
    
    $
    1.62
    
    
    $
    0.63Net earnings
    
    $
    14,764
    
    
    $
    5,098
    
    
    $
    4,881Net earnings per unit  basic
    
    $
    0.63
    
    
    $
    0.27
    
    
    $
    0.27Net earnings per unit  diluted
    
    $
    0.63
    
    
    $
    0.27
    
    
    $
    0.26Average number of units outstanding
    
    
    23,328
    
    
    
    18,954
    
    
    
    18,309Total assets
    
    $
    200,301
    
    
    $
    116,661
    
    
    $
    104,505Total bank debt and obligations under capital leases
    
    $
    47,316
    
    
    $
    38,129
    
    
    $
    29,358Distribution per unit
    
    US$
    1.42
    
    
    US$
    0.10
    
    
    
    N/A
 
 (1)
    
    Cash flow from operations is a non-GAAP measure. Cash flow from operations is
reconciled to GAAP earnings in the cash flow section below. 46




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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 increased by 84% in 2004 and by 170% in Q4 compared to their respective periods
in 2003. These increases are a result of higher production rates, the acquisition of higher
operating cost properties during the year and overall increased industry operating costs. 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
    
    
    $
    12,762
    
    
    
    84
    %As a percentage of production revenue
    
    
    24
    %
    
    
    19
    %
    
    
    25
    %
    
    
    22
    %
    
    
    18
    %
    
    
    23
    %Production expenses per boe
    
    $
    10.98
    
    
    $
    6.19
    
    
    
    77
    %
    
    $
    9.23
    
    
    $
    6.96
    
    
    
    33
    %
 47




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##### Table of Contents



Royalties Royalties (including Crown, freehold and overriding royalties) increased by 39% in 2004 and by 103%
in Q4 compared to their respective periods in 2003. These increases are the result of both the
increased production in 2004 and the higher commodity prices in effect during the year. Most
royalties are calculated on a sliding scale based on commodity prices. As commodity prices
increase, so do the royalty rates. 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
    %
    
    
    -6
    %
    
    
    23
    %
    
    
    24
    %
    
    
    -8
    %Royalties per boe
    
    $
    10.91
    
    
    $
    8.18
    
    
    
    33
    %
    
    $
    9.63
    
    
    $
    9.63
    
    
    
    0
    %
 General and Administrative Expenses General and administrative cash expenses increased by 41% in 2004 and 83% in Q4 compared to their
respective periods in 2003. Approximately 80% of the increase in 2003 is the result of additional
staffing requirements. Other areas that incurred higher expenses were marketing and travel costs,
insurance premiums, and higher regulatory compliance costs both for the Canadian and U.S.
exchanges. The non-cash portion of general and administrative expenses relates to the fair market
value assigned to warrants and options issued. 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 increased by 27% in 2004 and increased by 20% in Q4 compared to their respective
periods in 2003. The 2004 increase is due to the higher average outstanding loan balances during
the year. The increase in Q4 is due to the fact that, on average, the Q4 loan balances were higher
in 2004 because of acquisitions and drilling activity in 2004 compared to 2003. 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
    %
    
    $
    47,316
    
    
    $
    38,128
    
    
    
    24
    %Interest expense
    
    $
    491
    
    
    $
    410
    
    
    
    20
    %
    
    $
    2,222
    
    
    $
    1,749
    
    
    
    27
    %As a percentage of production revenue
    
    
    2
    %
    
    
    3
    %
    
    
    44
    %
    
    
    2
    %
    
    
    2
    %
    
    
    -15
    %Interest expense per boe
    
    $
    0.67
    
    
    $
    0.86
    
    
    
    -21
    %
    
    $
    0.87
    
    
    $
    0.95
    
    
    
    -8
    %
 48




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##### Table of Contents



Depletion and Depreciation Depletion and depreciation expense increased by 52% in 2004 and by 88% in Q4 compared to their
respective periods in 2003. The increase is due to a higher production rate in the year and Q4
2004. DEPLETION AND DEPRECIATION EXPENSE(in Thousands except for percentages and per boe amounts) Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeDepletion and depreciation expense
    
    $
    11,650
    
    
    $
    6,210
    
    
    
    88
    %
    
    $
    35,438
    
    
    $
    23,306
    
    
    
    52
    %As a percentage of production revenue
    
    
    35
    %
    
    
    40
    %
    
    
    -13
    %
    
    
    33
    %
    
    
    33
    %
    
    
    0
    %Depletion and depreciation expense per boe
    
    $
    15.98
    
    
    $
    12.97
    
    
    
    23
    %
    
    $
    13.92
    
    
    $
    12.71
    
    
    
    10
    %
 Income and Capital Taxes The Trust, pursuant to the Trust Indenture, is not subject to income tax as all of the taxable
income of the Trust is distributed to Unitholders in the form of taxable distributions. The fully
owned subsidiaries of the Trust are subject to tax if the discretionary deductions available within
the provisions of the Canadian Income Tax Act are inadequate to reduce taxable income to zero.
These discretionary deductions are often referred to as tax pools. Total tax expense reflected in the Income Statement is a combination of the Current and Future
Income Tax provisions. The current tax expense relates to Large Corporation Tax. Future Income
tax expense reflects the temporary differences between the accounting value and the tax value of
the pools, valued at the anticipated future tax rate when the temporary differences are anticipated
to reverse. The Trust has neither directly nor indirectly incurred current income tax liabilities since the
formation of the Trust in 2003. A $0.8 million tax liability was acquired in conjunction with the
purchase of Rocky Mountain Energy Corp. related to periods prior to acquisition. Management
regularly reviews the potential for cash income taxes liabilities, and undertakes strategies to
minimize this potential for taxes in future years. The Large Corporation Tax will continue in
future years as a cash tax on the Trust. The size of available tax pools is one indicator of the Trusts ability to minimize cash income
taxes in the future. Should tax pools become inadequate to reduce taxable income of the subsidiary
corporations then cash income taxes will become due indirectly by the Trust. These cash taxes will
reduce the funds available for distribution to Unitholders. 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
 49




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##### Table of Contents



Earnings In 2003, earnings were reduced by the re-organization costs related to the conversion to a trust in
the fourth quarter of 2003. EARNINGS(in Thousands except for per unit amounts) Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeEarnings (loss) before income taxes
    
    $
    3,247
    
    
    $
    (4,710
    )
    
    
    169
    %
    
    $
    14,953
    
    
    $
    7,220
    
    
    
    107
    %Deduct income taxes
    
    $
    (170
    )
    
    $
    (377
    )
    
    
    145
    %
    
    $
    (189
    )
    
    $
    (2,122
    )
    
    
    -91
    %Net earnings (loss)
    
    $
    3,417
    
    
    $
    (5,087
    )
    
    
    167
    %
    
    $
    14,764
    
    
    $
    5,098
    
    
    
    190
    %Net Earnings (loss) as a percentage of revenue
    
    
    10
    %
    
    
    33
    %
    
    
    130
    %
    
    
    14
    %
    
    
    7
    %
    
    
    93
    %Net Earnings (loss) on a per boe basis
    
    $
    4.69
    
    
    $
    (10.62
    )
    
    
    144
    %
    
    $
    5.30
    
    
    $
    2.77
    
    
    
    109
    %Per unit informationNet earnings (loss) per unit
    
    $
    0.13
    
    
    $
    (0.25
    )
    
    
    152
    %
    
    $
    0.63
    
    
    $
    0.27
    
    
    
    135
    %Average number of units outstanding
    
    
    25,974
    
    
    
    20,205
    
    
    
    29
    %
    
    
    23,328
    
    
    
    18,954
    
    
    
    23
    %
 Cash Flow From Operations Cash flow grew by 64% in 2004 and by 728% in Q4 compared to their respective periods in 2003. s a
percentage of revenue, cash flow decreased by 8% to 46% in 2004 compared to 2003 and increased by
284% in Q4 2004 to 42% compared to Q4 2003. Cash flow from operations increased by 38% in 2004 and by 88% in Q4 compared to their respective
periods in 2003. As a percentage of revenue, cash flow from operations decreased by 8% to 46% in
2004 compared to 2003 and decreased by 13% in Q4 2004 to 42% compared to Q4 2003. The difference
between cash flow and cash flow from operations is the $5.8 million re-organization cost incurred
in 2003 to convert Enterra Energy Corp. to a trust. Higher operating cost properties acquired in 2004 contributed to the decrease in cash flow as a
percentage of revenue. As mentioned earlier, it is managements view that cash flow from operations is a very useful
measure of performance, especially in light of Enterras conversion to an oil and gas income trust.
Cash flow from operations is the key factor in setting the monthly distribution rate. As
discussed in the earnings section above, cash flow from operations is also a good benchmark when
comparing results from year to year or quarter to quarter because it excludes one-time
non-recurring events that may otherwise distort the financial results. Cash flow from operations
is a non-GAAP measure, reconciled with GAAP net earnings in the table below: 50




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##### Table of Contents



CASH FLOW FROM OPERATIONS(in Thousands except for per unite amounts) Q4
    
    
    Q4
    
    
    
    
    
    
    Year
    
    
    Year2004
    
    
    2003
    
    
    Change
    
    
    2004
    
    
    2003
    
    
    ChangeNet earnings (loss)
    
    $
    3,417
    
    
    $
    (5,087
    )
    
    
    167
    %
    
    $
    14,764
    
    
    $
    5,098
    
    
    
    190
    %Add back depletion and depreciation
    
    
    11,650
    
    
    
    6,210
    
    
    
    88
    %
    
    
    35,438
    
    
    
    23,306
    
    
    
    52
    %Add back (deduct) amortization of deferred
financing charges
    
    
    (18
    )
    
    
    (27
    )
    
    
    33
    %
    
    
    33
    
    
    
    262
    
    
    
    - 87
    %Add back (deduct) future income taxes
    
    
    (340
    )
    
    
    331
    
    
    
    203
    %
    
    
    (71
    )
    
    
    1,988
    
    
    
    - 104
    %Deduct amortization of deferred gain
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (237
    )
    
    
    - 100
    %Asset Retirement Expenditures
    
    
    
    
    
    
    (5
    )
    
    
    -100
    %
    
    
    
    
    
    
    (6
    )
    
    
    - 100
    %Add back (deduct) non-cash expense related to
warrants/ options
    
    
    (606
    )
    
    
    282
    
    
    
    315
    %
    
    
    78
    
    
    
    282
    
    
    
    - 72
    %Cash flow from operations
    
    $
    14,103
    
    
    $
    1,704
    
    
    
    728
    %
    
    $
    50,242
    
    
    $
    30,693
    
    
    
    64
    %Cash flow from operations as a percentage of revenue
    
    
    42
    %
    
    
    11
    %
    
    
    284
    %
    
    
    46
    %
    
    
    51
    %
    
    
    - 8
    %Cash flow from operations on a per boe basis
    
    $
    19.34
    
    
    $
    3.56
    
    
    
    444
    %
    
    $
    19.73
    
    
    $
    16.74
    
    
    
    18
    %Per unit informationCash flow from operations per unit
    
    $
    0.54
    
    
    $
    0.08
    
    
    
    544
    %
    
    $
    2.15
    
    
    $
    1.62
    
    
    
    33
    %Average number of units outstanding
    
    
    25,974
    
    
    
    20,205
    
    
    
    29
    %
    
    
    23,328
    
    
    
    18,954
    
    
    
    23
    %
 Capital Expenditures Capital expenditures, net of disposals, for the year ended December 31, 2004 were $65.2 million
(2003  $33.3 million) including $36.0 million of assets obtained through the acquisition of Rocky
Mountain Energy Corp. and $20.0 for the acquisition of Eastern Central Alberta (see notes 4 and 5
to the Financial Statements). Proceeds on disposal of oil and gas properties were $1.1 million in
2004 (2003  $18.3 million). These proceeds were used to reduce debt and replenish working
capital. In addition to cash capital expenditures, $11.8 million of net Asset Retirement
Obligations (ARO) were charged to Property Plant and Equipment. CAPITAL EXPENDITURES (In Thousands except for percentages)
    
    Year
    
    
    Year2004
    
    
    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
    %
 51




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##### Table of Contents



Cash Distributions The Trust paid distributions of US$0.10 per unit for the first two months of 2004. The
distribution was raised to US$0.11 per unit for the months of March, April and May, raised to
US$0.12 per unit for the months of June, July and August, raised to US$0.13 per unit for the months
of September, October and November and raised to US$0.14 per unit for the month of December 2004.
Cash distributions are paid on the 15th of the following month (e.g. the March distribution would
be paid on April 15). For Canadian tax purposes 47.84% of the 2004 distributions are taxable income to Unitholders for
the 2004 tax year. The remaining 52.16% is a tax-deferred return of capital that will reduce the
Unitholders cost base of the unit for purposes of calculating a capital gain or loss upon ultimate
disposition of the trust units. The Trusts distributions are typically qualifying dividend income for U.S. Unitholders, without
any portion deemed a return of capital. 52




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##### Table of Contents



NEW ACCOUNTING PRONOUNCEMENTS Canadian Pronouncements In December 2001, The Canadian Institute of Chartered Accountants (CICA) issued Accounting
Guideline 13, Hedging Relationships (AcG-13). AcG-13 establishes certain conditions for when
hedge accounting may be applied. The guideline is effective for years beginning on or after July
1, 2003. Where hedge accounting does not apply, any changes in the mark to market values of the
option contracts relating to a financial period can either reduce or increase net income and net
income per trust unit for that period. Enterra enters into financial instruments to manage its
commodity price risk that do not qualify as hedges under the new accounting guideline. We have
elected to not apply hedge accounting to any of our financial instruments. Effective January 1,
2004, we recorded the fair value of financial instruments as a liability of $1.0 million on the
balance sheet. Future changes in fair value of the financial instruments were recorded as a gain
or loss in oil and gas sales in the income statement. Full Cost Accounting Effective January 1, 2004, the Trust adopted Accounting Guideline 16, Oil and Gas Accounting 
Full Cost which replaces AcG-5  Full Cost Accounting in the Oil and Gas industry. AcG-16
modifies how the ceiling test is performed and is consistent with CICA Section 3063, Impairment of
Long-lived Assets. The new guideline 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. Asset Retirement Obligations 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. Unit-based Compensation Effective January 1, 2004, the Trust adopted the fair value method of accounting for options on a
retroactive basis, without prior period restatement. 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 as the grant date, no compensation cost was
recognized on any option issuance. In 2003, the Trust disclosed pro forma net earnings and earning
per unit as if compensation cost for the Trusts unit-base compensation plan had been determined
based on the fair value at the grant date for awards made under the plan subsequent to January 1,
2002. The estimated fair value of the options issued is determined using a Black-Scholes
option-pricing model. Variable Interest Entities (VIEs) In June 2003, the CICA issued Accounting Guideline 15 Consolidation of Variable Interest Entities
(AcG-15). AcG-15 defines VIEs as entities in which either: the equity at risk is not sufficient to
permit that entity to finance its activities without additional financial support from other
parties; or equity investors lack voting control, an obligation to absorb expected losses or the
right to receive expected residual returns. AcG-15 harmonizes Canadian and U.S. GAAP and provides
guidance for companies consolidating VIEs in which it is the primary beneficiary. The guideline is
effective for all annual and interim periods beginning on or after November 1, 2004. We have
performed a review of entities in which the Trust has an interest and have determined that we do not
have any variable interest entities at this time. Exchangeable Shares 53




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##### Table of Contents



On January 19, 2005, the CICA issued EIC-151 Exchangeable Securities Issued by Subsidiaries of
Income Trusts that states that, effective June 30, 2005, 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 exchangeable shares issued by the
Trust are transferable and, in accordance with EIC-151, will be reclassified to non-controlling
interest on the consolidated balance sheet. In addition, a portion of consolidated income or loss
before non-controlling interest will be reflected as a reduction to such income or loss in the
Trusts consolidated statement of income. Prior periods will be retroactively restated. U.S. Pronouncements The 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 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 Juen 15, 2005.
Management does not expect the adoption of this statement to have any material impact on
our results of operations or financial position. The Trust will continue to assess the applicability of these standards in the future. 54




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##### Table of Contents



Comparison of the Year Ended December 31, 2003 to the Year Ended December 31, 2002 Overview Enterra managed to achieve record revenue, cash flow and earnings in 2003 while converting itself
to an oil and gas income trust during the fourth quarter. Cash flow from operations, excluding the
one-time re-organization costs of $5.8 million, was in excess of $36 million for the year or $1.92
on a per unit basis. As a trust, we established an initial monthly distribution level at US$0.10
per unit. The first distribution was paid on January 15, 2004 for the month of December 2003.
Enterra drilled 47 wells in 2003, including 20 wells at Clair and 19 wells at Sylvan Lake. The two
projects represented almost 60% of Enterras 2003 capital expenditures. The 2003 drilling program
resulted in 31 oil wells (31.0 net) and 3 gas wells (1.1 net) for an 86% success rate. 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 flow from operations (1)
    
    $
    30,693
    
    
    $
    11,901
    
    
    
    + 158
    %Cash flow from operations per unit (1)
    
    $
    1.61
    
    
    $
    0.65
    
    
    
    + 148
    %Average number of units outstanding (after giving effect
to trust conversion)
    
    
    18,954
    
    
    
    18,309
    
    
    
    + 4
    %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
    %
 
 (1)Cash flow from operations is a non-GAAP measure. Cash flow from operations is reconciled to GAAP earnings in the cash flow section below. 55




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##### Table of Contents



2 YEAR SUMMARY Summarized financial and operational data(in Thousands except for per unit amounts)} 2003
    
    
    2002Revenue
    
    $
    72,097
    
    
    $
    25,746Net earnings
    
    $
    5,098
    
    
    $
    4,881Net earnings per unit  basic
    
    $
    0.27
    
    
    $
    0.27Net earnings per unit  diluted
    
    $
    0.27
    
    
    $
    0.26Average number of units outstanding (after giving effect to trust conversion)
    
    
    18,954
    
    
    
    18,309Total assets
    
    $
    116,661
    
    
    $
    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. 56




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##### Table of Contents



PRODUCTION REVENUE Production revenue has increased by 180% in 2003 or to $72.1 million ($25.7 million in 2002).
Approximately 30% of this increase was as a result of higher commodity prices during 2003 and 70%
was due to the higher production volumes in 2003. Enterra drilled 47 wells in 2003, including 20 wells at Clair and 19 wells at Sylvan Lake. The two
projects represented almost 60% of Enterras 2003 capital expenditures. The 2003 drilling program
resulted in 31 oil wells (31.0 net) and 3 gas wells (1.1 net) for an 86% success rate. Enterras
production in 2003 averaged 5,024 boe/day, consisting of 3,862 bbls/day of oil and 6,972 mcf/day of
natural gas, for a mix of 77% oil and 23% natural gas. Enterra exited 2003 at a rate of 6,460 boe/day, consisting of 4,890 bbls/day of oil and 9,420
mcf/day of natural gas, for a mix of 76% oil and 24% natural gas. This represents a 21% increase
over the 2002 exit rate of 5,335 boe/day. 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 increased by 112% in 2003 compared to 2002. This increase is consistent with
the higher production levels in 2003. Both as a percentage of revenue and on a per boe basis,
Enterra reduced its operating costs in 2003, mainly due to operating efficiencies gained at Clair
in the fourth quarter of 2003 by implementing a sales line which eliminated trucking and terminal
fees for that area. Production expenses(in Thousands except for percentages and per boe amounts) 2003
    
    
    2002
    
    
    ChangeProduction expenses
    
    $
    12,762
    
    
    $
    6,018
    
    
    
    + 112
    %As a percentage of production revenue
    
    
    18
    %
    
    
    23
    %
    
    
    - 22
    %Production expenses per boe
    
    $
    6.96
    
    
    $
    7.11
    
    
    
    - 2
    %
 57




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##### Table of Contents



ROYALTIES
Royalties (which include Crown, freehold and overriding royalties) increased by 320% in 2003
compared to 2002. This increase is the result of both the increased production in 2003 and the
higher commodity prices in effect during the year. Most royalties are calculated on a sliding
scale based on commodity prices. As commodity prices increase, so do the royalty rates.
Conversely, the Alberta Royalty Tax Credit is reduced as commodity prices increase. Since
royalties are not calculated by reference to any hedging position entered into by Enterra, any
hedging loss will result in a higher royalty expense as a percentage of production revenue. These
factors were the reason for the increase (50% for the year) in royalty expense both as a percentage
of production revenue and on a per boe basis. 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 increased by 84% in 2003 compared to 2002. Approximately 80%
of the increase in 2003 is the result of additional staffing requirements. Other areas that
incurred higher expenses were marketing and travel costs, insurance premiums, and higher regulatory
compliance costs both for the Canadian and U.S. exchanges. Capitalized general and administrative
costs were consistent in both years, $1,787,000 (or 32% of total general and administrative
expenses) in 2003 and $1,450,900 (or 39% of total general and administrative expenses) in 2002.
The non-cash portion of general and administrative expenses in 2003 relate to the value assigned to
200,000 warrants (see Note 9(h) of the Financial Statements for details). 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 increased by 42% in 2003 compared to 2002. The 2003 increase is due to the higher
average outstanding loan balances during the year. 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
    %
 58




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##### Table of Contents



DEPLETION AND DEPRECIATION
Depletion and depreciation expense increased by 152% in 2003 compared to 2002. The increase is due
to a higher production rate in 2003. The depletion base was consistent in both years as the
capital expenditures, net of proceeds on disposal of properties, were $33 million in 2003 and $ 30
million in 2002. 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
The combined federal and provincial income taxes decreased in 2003 to 40.75% from 42.12% in 2002.
The actual tax provision recorded on the financial statements is at much lower rates in both 2003
and 2002 (29.25% in 2003 and 16.96% in 2002). The rate was very low in 2002 mainly because of the
$3.1 million gain on redemption of preferred shares that was not a taxable gain for tax purposes,
resulting in a lower tax provision in that year. The rate was also lower in 2003 mainly due to
changes in the timing differences related to the Crown royalties and the resource allowance
calculation, and to differences related to the Trust distributions, which are deductible in part
for tax purposes but are not deducted to arrive at net earnings. 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 net earnings
    
    
    29.25
    %
    
    
    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
    %
 59




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##### Table of Contents



EARNINGS
Earnings were higher in 2002 because of the impact of a $3.1 million gain on redemption of
preferred shares. The opposite occurred in 2003 as earnings were reduced by the re-organization
costs related to the conversion to a trust structure in the fourth quarter of 2003. Earnings(in Thousands except for per unit amounts) 2003
    
    
    2002
    
    
    ChangeEarnings (loss) before income taxes
    
    $
    7,220
    
    
    $
    5,878
    
    
    
    + 23
    %Deduct income taxes
    
    
    (2,122
    )
    
    
    (997
    )Net earnings (loss)
    
    $
    5,098
    
    
    $
    4,881
    
    
    
    + 4
    %Per unit informationNet earnings (loss) per unit
    
    $
    0.27
    
    
    $
    0.27
    
    
    
    0
    %Average number of units outstanding
    
    
    18,954
    
    
    
    18,309
    
    
    
    + 4
    %
 60




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##### Table of Contents



CASH FLOW FROM OPERATIONS
Cash flow from operations grew by 205% in 2003 compared to 2002. As a percentage of revenue, cash
flow from operations was consistent in both years, at 51% of revenue in 2003 compared to 46% in
2002. Higher production volumes and higher commodity prices in 2003 are the main factors behind the
increase. The changes on a per unit basis showed similar results: an increase of 195% in 2003 compared to
2002. As mentioned earlier, it is managements view that cash flow from operations is a very useful
measure of performance, especially in light of Enterras conversion to an oil and gas income trust.
Cash flow from operations is the key factor in setting the monthly distribution rate. As
discussed in the earnings section above, cash flow from operations is also a good benchmark when
comparing results from year to year or quarter to quarter because it excludes one-time
non-recurring events that may otherwise distort the financial results. Cash flow from operations
is a non-GAAP measure, reconciled with GAAP net earnings in the table below: Cash flow from operations(in Thousands except for per unit amounts) 2003
    
    
    2002
    
    
    ChangeNet earnings (loss)
    
    $
    5,098
    
    
    $
    4,881
    
    
    
    + 4
    %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
    )Cash flow from operations (1)
    
    $
    30,693
    
    
    $
    11,901
    
    
    
    + 158
    %Cash flow from operations as a percentage of revenue (1)
    
    
    42
    %
    
    
    46
    %
    
    
    - 10
    %Cash flow from operations on a per boe basis (1)
    
    $
    19.73
    
    
    $
    14.11
    
    
    
    + 40
    %Per unit informationCash flow from operations per unit
    
    $
    1.61
    
    
    $
    0.65
    
    
    
    + 148
    %Average number of units/shares outstanding
    
    
    18,954
    
    
    
    18,309
    
    
    
    + 4
    %
 (1)Cash flow from operations is a non-GAAP measure. Cash flow from operations is
reconciled to GAAP earnings in the cash flow section below. CAPITAL EXPENDITURES
Capital expenditures, net of disposals, for the year ended December 31, 2003 were $33.3 million
(2002  $30.1 million). Enterra drilled 47 wells in 2003, resulting in 31 oil wells (31.0 net) and
3 gas wells (1.1 net) for an 86% success rate. Enterra drilled 62 wells (57.7 net) in 2002,
resulting in 25 oil wells (23.7 net) and 37 gas wells (34.0 net). Proceeds on disposal of oil and
gas properties were $18.3 million in 2003 (2002  $5.8 million). These proceeds were used to
reduce debt and replenish working capital and relate almost exclusively to the sale of the Grand
Forks properties, which occurred in the second quarter of 2002 and which accounted for $5.3 million
of the total proceeds. 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
    %
 61




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##### Table of Contents



CASH DISTRIBUTIONS The Trust paid distributions of US$0.10 per unit for the month of December 2003 and for the first
two months of 2004. The distribution for the month of March 2004 was raised to US$0.11 per unit.
Cash distributions are paid on the 15th of the following month (e.g. the March
distribution would be paid on April 15). The Trusts distributions are highly dependent on commodity prices, primarily the price of crude
oil. The Trust mitigates this risk by hedging some of its oil production. A detailed schedule of
our hedging history and current position is included in the next section dealing with liquidity and
capital resources. For Canadian tax purposes 72.37% of the December distribution is taxable income to Unitholders for
the 2003 tax year. The remaining 27.63% is a tax deferred return of capital that will reduce the
unitholders cost base of the unit for purposes of calculating a capital gain or loss upon ultimate
disposition of the trust units. For U.S. tax purposes, the December distribution is a 2004 taxable event. The Trusts
distributions are typically dividend income for U.S. Unitholders, without any portion deemed a
return of capital. 5 B. Liquidity and Capital Resources Enterras bank debt at December 31, 2004 was $43.9 million (2003  $34.0 million). In both periods
the funds were used to acquire capital assets and support ongoing operations. At December 31, 2004
The Trusts bank facility consisted of a line of credit of $45.0 million (2003  $34.7 million).
The line of credit was reduced by $1 million per month until April 30, 2005 when the line was set
at $41 million. Interest on amounts drawn is based on the banks prime rate plus 1.6% to 2.0%. In 2002 the Trust closed a sale-leaseback arrangement on some of its production and processing
equipment for $5 million. The funds were used for the Trusts 2002 drilling program. The lease
agreement calls for 60 monthly payments of $88,802, with an option to purchase of $1 million on the
last day of the 60th month. This arrangement is accounted for as a capital lease. At December 31,
2004 the balance outstanding on this capital lease was $3.4 million (2003  $4.2 million). On January 30, 2004 the Trust closed an acquisition of properties in East Central Alberta for $19.6
million. The effective date of the sale was October 1, 2003. On February 20, 2004 the Trust completed a private placement of 1,049,400 Trust Units at a price of
US$11.25 per unit for gross proceeds of US$11,805,750 (US$10,265,463 net of financing costs).
These funds were used for drilling projects that Enterra began prior to its conversion to a Trust. On June 30, 2004 the Trust completed a private placement of 1,650,000 Trust Units at a price of
US$10.00 per unit for proceeds of US$16,500,000. These funds were used for property acquisitions. The Trust has approximately $127 million in tax pools available at December 31, 2004 (2003  $100
million). The Trust had several costless collars and forward contracts in place during the year in order to
reduce the volatility in crude oil pricing. Below is a summary of the financial instruments in
place in 2004. 62




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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
 The Trust reflected a $3.2 million loss on these contracts in 2004. These financial derivative
losses occurred, as the posted commodity price at the time of contract settlement was higher than
the contracted pricing as a result of the escalating oil and gas commodity pricing throughout the
year. These losses were offset by higher revenue on production. There were no contracts entered into subsequent to December 31, 2004. The Trust has sufficient working capital for its present requirements. The working capital
deficiency is caused by the requirement of GAAP that $43.9 million bank indebtedness is classified
as a current liability even though there is no expectation that the revolving lines of credit will
be called by the bank. Our cash flow from operations for 2004 was $50.2 million, so the bank
indebtedness represents less than 1 years cash flow. Our long term business strategy is to grow
its oil and gas reserves and distributions by acquiring properties that provide additional oil and
gas production and potential for development upside. We are focused on per unit growth. We will
finance acquisitions with debt and equity, the optimal mix being one that minimizes Unitholders
dilution while maintaining a strong balance sheet. At December 31, 2004 the Trust was not in compliance with certain non-financial covenants of its
credit facility. The Trusts lenders have not declared the Trust to be in default, and the Trust
is working to bring itself back into full compliance. The amounts available under our existing credit facility may not be sufficient for future
operations, or we may not be able to obtain additional financing on economic terms attractive to
us, if at all. Our current credit facility consists of a revolving operating demand loan, and a
demand subordinated debt facility. Repayment of all outstanding amounts may be demanded at any
time. If this occurs, we may need to obtain alternate financing. Any failure to obtain suitable
replacement financing may have a material adverse effect on our business, and distributions to
Unitholders may be materially reduced. The credit facilities are in Canadian dollars. On April 22, 2005, the Trust entered into a committed equity financing facility with Kingsbridge
Capital Limited, pursuant to which Kingsbridge committed, subject to certain significant
limitations and conditions precedent, to purchase up to US$100 million of Trust Units. The Trust signed an arrangement agreement dated May 31, 2005 with High Point Resources Inc. (High
Point) to acquire all of the issued and outstanding common shares of High Point to be completed by
plan of arrangement (the High Point Plan). High Point shareholders will receive 0.105 of a Trust
Unit or Exchangeable Share for each High Point common share held. The value of this transaction is
approximately US$250 million and the Trust will issue approximately 8.9 million Trust Units in
association with the High Point Plan, which equals approximately 35% of the current issued and
outstanding Trust Units. This transaction remains subject to approval by the High Point
shareholders at a special meeting which is expected to occur in August 2005. We do not have material commitments for capital expenditures. Our business strategy is to have
other companies spend the capital to develop our properties in exchange for us receiving a 30%
working interest in the developed properties at no additional cost to us. We also retain the right
to purchase the remaining 70% working interest on favorable terms. Any such purchases will be
financed by the Trust issuing new trust units and or debt. 63




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##### Table of Contents



The principal undertaking of the Trust is to issue trust units and to acquire and hold debt
instruments, royalties and other interests. The direct and indirect wholly owned subsidiaries of
the Trust carry on the business of acquiring and holding interests in petroleum and natural gas
properties and assets related thereto. 5.C Research and development, patents and licenses, etc. The Trust has no material research and development programs, patents and licenses etc. 5.D Trend information Our financial results have been principally affected by increased derived crude oil prices and a
gradual strengthening in the Canadian to US dollar. In recent months, the derived crude oil price has risen from the year-end level of 32.52 US
dollar/bbl to 42.45 US dollar/bbl on 20 August 2004, falling to 37.52 US dollar/bbl on 31 August
2004, before approaching 50.00 US dollar/bbl during most of the month of September 2004. Given the
current uncertain political environment, the oil price has been volatile and this volatility is
expected to continue in the foreseeable future. A high oil price generally results in increased
profitability for Enterra. Oil is priced in US dollars, and the US dollar has been falling against the Canadian dollar for the
last few years. This has the effect of reducing the Canadian dollar revenue that would otherwise
be received for each barrel of oil sold in US dollars. 5.E Off balance sheet arrangements There were no off balance sheet arrangements in 2004 or 2003. 5.F Tabular disclosure of contractual obligations The Trust has two ongoing commitments over the next five years, one related to the capital lease
and the other related to the rental payments for our office space. The rental expense was $81,339
in 2004 (2003  $299,132). These commitments are outlined below: 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
 64




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##### Table of Contents



ITEM 6. Directors, Senior Management and Employees A. Directors and senior management Enterras officers, directors and executive officers as of June 15, 2005 were: 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.Mr. Greenslade was President, CEO and Director of Old Enterra from
the fall of 2001 until November 2003 and continued as Chairman of Enterra Energy Trust after the
arrangement. Following the resignation of the CEO and president on January 15, 2005, Mr.
Greenslade was appointed President and CEO in addition to his duties as Chairman of the Board until
the appointment of Mr. Conrad as President and CEO on June 1, 2005. He is also the Chairman, Chief
Executive Officer and director of JED Oil Inc., a publicly traded oil and gas company listed on the
American Stock Exchange. He was a director of PASW Inc., a software development company, from
February 2001 to July 2001. From 1995 until the formation of Enterra, Mr. Greenslade was the
President, CEO and Director of Big Horn Resources Ltd. Prior to his position with Big Horn, Mr.
Greenslade was with CS Resources Limited in the areas of exploitation engineering and project
management from 1993 to 1995. Prior to 1993, Mr. Greenslade was employed by Saskatchewan Oil and
Gas Corporation in the capacities of project management, production, and reservoir engineering. He
has extensive experience with secondary recovery schemes and is recognized for his work in the
specialized field of horizontal well technology. All the above companies were publicly traded in
either the U.S., Canada, or both, during the periods indicated. E. Keith Conrad.Mr. Conrad is a lawyer with over 40 years of business experience, the last 20
years directly involved with executive management in the oil and gas industry. Mr. Conrad has been
Chairman of Macon Resources Ltd., a private company involved in the management of and investment in
private and public companies in the oil and gas industry, since 1997. Mr. Conrad holds Bachelors
of Arts and Law Degrees from the University of Alberta. H.S. (Scobey) Hartley.Mr. Hartley has a Bachelor of Science degree in Geology from Texas Tech
University. Mr. Hartley has been a director of Enterra since May 2000. Mr. Hartley was the
President of Prism Petroleum Ltd. and a predecessor company from December 1990 through December
1996. Mr. Hartley has been the Chairman of Prism Petroleum Ltd. since January 1997. Mr. Hartley
has served as the President of Faster Oilfield Services since June 1995, and was the President of
Cayenne Energy Corp. from 1990 to 1996. Mr. Hartley was the President and a Director of Scaffold
Connection Corporation from February 2000 to November, 2001. Mr. Hartley has been a Director of
Cathedral Energy Services Ltd. since June 2001. Norman W. Wallace.Mr. Wallace has been a director of Enterra since May 2000. Mr. Wallace
resigned as a director of Enterra in August 2001 and was reappointed in June 2002. He has been the
owner of Wallace Construction Specialties Ltd. since 1972. Mr. Wallace received a Bachelor of
Commerce degree from the University of Saskatchewan in 1968. William E. Sliney.Mr. Sliney became a director on March 19, 2004. He has been the president of
PASW, Inc. since August 2001 and was chairman from October 2000 to August 2001. Previously Mr.
Sliney was the chief financial officer for Legacy Software Inc. from 1995 to 1998. From 1993 to
1994, Mr. Sliney was chief executive officer for Gumps. Mr. Sliney received his masters in
business administration from the University of California at Los Angeles. John Kalman.Mr. Kalman is a Chartered Accountant with over 23 years of business experience, the
last 17 years involved in senior financial positions within the oil and gas industry. Mr. Kalman
has been the Vice President, Finance & CFO of Macon Resources Ltd. since November 2004. From
January 2004 to October 2004 Mr. Kalman 65




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was an independent consultant providing various accounting services to the oil and gas industry.
Prior thereto, from October 1999 to December 2003 he was Vice President, Finance and CFO of
Gauntlet Energy Corporation a junior oil and gas exploration and development company. Prior
thereto, he was Vice President, Finance and CFO of First Calgary Petroleums Ltd. a junior
international oil and gas exploration company. Mr. Kalman holds a Bachelor of Commerce Degree from
the University of Calgary. 66




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##### Table of Contents



B. Compensation The following table provides a summary of compensation earned during the last fiscal year ended
December 31, 2004 by our directors and executive officers during 2004. All monetary amounts are in
Canadian dollars. 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 CEO
    
    
    2003
    
    
    
    200,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    274,0002002
    
    
    
    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 On January 14, 2004, the directors of Enterra approved an Annual Bonus Plan, which provides for a
bonus pool equal to seven/tenths of a percent (0.7%) of the increase in capitalization of the Trust
Units each year. There are a number of ways to calculate a bonus pool and each has advantages and
disadvantages. The directors of Enterra elected to use a small percentage of the increase in
capitalization of the Trust Units because they believe that the best measure of the success of the
employees is the increase in value for the Unitholders. Directors, officers and employees of the
Trust on December 31st of each year are eligible for a bonus. Allocations of the bonus pool to
eligible persons is also at the sole discretion of Enterras Compensation Committee, although
compensation received during the year is the starting point for the allocations. The Annual Bonus
Plan requires that it receive the approval of disinterested Unitholders. Management Contracts
Effective June 1, 2005, we entered into a Management Agreement with Macon Resources Ltd. (Macon)
for Macon to provide the services of E. Keith Conrad as President and CEO, and John Kalman as CFO,
to Enterra and provide other Management services. Enterra pays Macon fees of $600,000 per year and
Macon has also been granted 400,000 options. The agreement has a term of 3 years, which can be
amended by mutual consent, and can be terminated with six months notice by either party. Trust Units Options
We grant trust unit options from time to time to directors, officers, key employees, and
consultants. The terms and conditions of the options, in accordance with resolutions of our board
of directors and the policies of the Toronto Stock Exchange, will not exceed a term of five years.
The option price may be at a discount to market price, which discount will not, in any event,
exceed that permitted by any stock exchange on which our shares are listed for 67




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##### Table of Contents



trading. Ten percent of our of issued and outstanding trust units from time to time are reserved for
issuance pursuant to trust unit options. The aggregate number of trust units reserved for issuance
under option grants, together with any other employee trust unit option plans, options for services
and employee trust unit purchase plans, will not exceed ten percent of our issued and outstanding
trust units. In addition, the aggregate number of trust units so reserved for issuance to any one
person shall not exceed five percent of the issued and outstanding trust units. If an optionee ceases to be eligible due to the loss of corporate office or employment for any
reason other than death, the option terminates not later than 30 days after the loss of such
corporate office; provided that in the event of termination of employment for cause, the board of
directors may resolve that the option shall terminate on the date of such termination. Option
agreements also provide that estates of deceased participants can exercise their options for a
period not exceeding one year following death. Trust Unit Options Granted During the Most Recently Completed Financial Year There were 950,000 trust unit options granted at a weighted average price of C$14.22 during the
fiscal year ended December 31, 2004. Option Grants During Fiscal Year Ended December 31, 2004 Individual GrantsPercentage of TotalOptionsGranted to
    
    
    
    
    
    
    
    
    
    
    Potential Realizable Value atEmployees in
    
    
    
    
    
    
    
    
    
    
    Assumed Annual Rate of Stock PriceNumber of Shares of
    
    
    Year Ending
    
    
    Exercise
    
    
    Expiration
    
    
    Appreciation for Option Term (1)Common 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 The following table sets forth the aggregate of options exercised by our executive officers
during the year ended December 31, 2004 and the December 31, 2004 year-end values for options
granted to the executive officers. All monetary amounts are in Canadian dollars. 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. 68




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C. Board Practices Board of Directors The Trust does not have a Board of Directors or officers. The Board of Directors and officers of
Enterra act as the Trusts directors and officers. Enterra is authorized to have a board of at
least three directors and no more than ten. Enterra currently has five directors. Directors are
elected for a term of about one year, from annual meeting to annual meeting, or until an earlier
resignation, death or removal. Each officer serves at the discretion of the board or until an
earlier resignation or death. There are no family relationships among any of Enterras directors
or officers. Alberta securities laws requires that Enterra have at least two independent outside
directors who are not officers or employees of Enterra. Currently, two directors are members of
management and three directors are independent. Currently, the independent directors of Enterra receive an annual retainer of US$5,000 for the
Chairman of the Audit Committee and C$5,000 for the other two. Directors are also compensated for
their out-of-pocket costs, including travel and accommodation, relating to their attendance at any
directors meeting. Finally, the directors of Enterra are entitled to participate in our trust
unit option plan and annual bonus plan. During the year ended December 31, 2004, there were
360,000 options granted to the independent directors (not including options granted to a director
who is also a named executive officer), and the independent directors received an aggregate of
$136,820 under the annual bonus plan. Except as described herein, no compensation by way of annual
retainer or meeting fees was paid to directors for acting in such capacity in the year ended
December 31, 2004. Committees of the Board of Directors Enterras Board of Directors currently has an audit committee, a compensation committee, a
corporate governance committee and a reserves committee. Audit Committee.Enterras audit committee consists of Mr. Sliney (Chairman), Mr. Hartley and Mr.
Wallace, all three being independent directors. The audit committee reviews in detail and
recommends approval of the full board of our annual and quarterly financial statements; recommends
approval of the remuneration of our auditors to the full board; reviews the scope of the audit
procedures and the final audit report with the auditors, and reviews our overall accounting
practices and procedures and internal controls with the auditors. Compensation Committee.Enterras compensation committee consists of Mr. Hartley (Chairman), Mr.
Wallace and Mr. Greenslade. The compensation committee recommends approval to the full board of
the compensation of the Chief Executive Officer, the annual compensation budget for all other
employees, bonuses, grants of stock options and any changes to our benefit plans. Corporate Governance Committee.Enterras corporate governance committee consists of Mr. Wallace
(Chairman), Mr. Greenslade and Mr. Hartley. The corporate governance committee determines the
scope and frequency of periodic reports to the board concerning issues relating to overall
financial reporting, disclosure and other communications with all stakeholders. Reserves Committee. Enterras reserves committee consists of Mr. Wallace (Chairman) and Mr.
Hartley. The reserves committee reviews and recommends approval to the full board of Enterras
annual reserve report as prepared by independent reservoir engineers. D. Employees At December 31, 2004, we had 3 employees working in the Calgary head office. Under the Technical Services Agreements with JED Oil Inc. (JED), effective January 1, 2004, JED
provides staff while Enterra provides offices and other administrative services to JED. As
consultants to Enterra, JEDs employees will be eligible to participate in benefit plans of
Enterra, if any. At December 31, 2004, JED had approximately 73 employees and consultants working
both in the Calgary head office and in field operations. The number of employees has grown each
year as the company has grown. 69




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##### Table of Contents



E. Share ownership The following table sets forth information regarding beneficial ownership of our trust units as of
June 30, 2005, by: · each of our executive officers and directors; and · all executive officers and directors as a group. Trust units not outstanding but deemed beneficially owned because an individual has the right to
acquire the trust units within 60 days are treated as outstanding when determining the amount and
percentage of trust units owned by that individual and by all directors and executive officers 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.   70




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##### Table of Contents



ITEM 7. Major Shareholders and Related Party Transactions A. Major Shareholders To the extent that it known to Enterra or can be ascertained from public filings, no shareholder
has more beneficial ownership of 5% or more of Enterras Trust Units. To the best of our
knowledge, Enterra is not directly or indirectly controlled by another corporation or the
government of Canada or any other government. Our management believes that no single person or
entity holds a controlling interest in our share capital. B. Related Party Transactions There were no related party transactions in 2004, 2003 or 2002 C. Interests of Experts and Counsel Not applicable 
 ITEM 8. Financial Information A. Consolidated Statements and Other Financial Information See ITEM 18. B. Significant Changes Subsequent to the year ended December 31, 2004, the Trust entered into two material agreements. On
April 22, 2005, the Trust entered into a committed equity financing facility with Kingsbridge
Capital Limited, pursuant to which Kingsbridge committed, subject to certain significant
limitations and conditions precedent, to purchase up to US$100 million of Trust Units. Until April
22, 2007 the Trust may, from time to time, at its sole discretion and subject to various
limitations and conditions precedent that the Trust must satisfy, require Kingsbridge to purchase
newly-issued Trust Units at a price that is 92% of the volume weighted average of the price of our
Trust Units for each of the fifteen trading days following its election to sell, or draw down,
Trust Units. As part of this arrangement, the Trust issued a warrant to Kingsbridge, which entitles Kingsbridge
to purchase 301,000 Trust Units at a price of US$25.77 per Trust Unit. The warrant is exercisable
beginning April 22, 2005 and until April 22, 2008. The exercise price of the warrant is adjusted
downward by the amount of distributions on the Trust Units while the Warrant is exercisable but
unexercised to a minimum of US$21.55 per Trust Unit. The warrant also has a cashless exercise
feature. The Trust is under no obligation to access any of the capital available under this commitment. It
has the option to draw on the commitment based on 92% of the fifteen day volume weighted average
trading price which must exceed $12 per Trust Unit. Under the terms of the commitment, the first
draw is to be up to US$10 million and each subsequent draw can be up to 4% of the Trusts market
capitalization but not to exceed $25 million per draw. There is to be 20 consecutive trading days
between each drawdown. The term of this commitment is 24 months or until the total commitment of
$100 million is drawn. In conjunction with the commitment, Kingsbridge will receive warrants to
purchase 301,000 Trust Units at an exercise price of $25.77/Trust Unit. The warrants will have a
three year term and the exercise price of the warrants will be adjusted downward by the amount of
unpaid distributions to a minimum price of US$21.55/Trust Unit. The Trust intends to register the
Trust Units for resale as per the agreement. The arrangement is subject to regulatory approval. On May 30, 2005, the Trust and High Point Resources Inc. entered into an agreement for the
acquisition by the Trust of all of the issued and outstanding common shares of High Point. The
acquisition is to be completed by way of a plan of arrangement pursuant to which shareholders of
High Point will receive for each share of High Point held 0.105 of a Trust Unit. The closing price
of the Trust Units on Friday, May 27th was C$25.41, valuing the common shares of High Point at
C$2.67 per share. High Point has approximately 85 million shares outstanding. The 71




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##### Table of Contents



transaction, including assumption of High Points debt of approximately US$67 million, has been
valued at approximately US$250 million. The Trust will be issuing approximately 8.9 million units
or approximately 34% of the total number of Trust Units currently outstanding. 72




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##### Table of Contents



ITEM 9. The Offer and Listing A. Offer and Listing details Not applicable, except for Item 9A (4) Price Range of Common Stock and Trading Markets On November 28, 2003 the business of Old Enterra was reorganized as an income trust. In
conjunction with this reorganization holders of Enterra Energy Corp. common stock received two
trust units for each share of common stock held or non-registered exchangeable shares convertible
into an equal number of trust units. All historical information before November 28, 2003 in the
following tables has been restated to reflect this exchange. Old Enterras shares commenced trading on the TSX Venture Exchange (TSXV) under the symbol WLX
during the quarter ended September 30, 1998. Our shares traded on the National Quotation Bureaus
pink sheets (Pink Sheets) under the symbol WLKSF from April 26, 2000 to January 10, 2001 when
the shares commenced trading on the Nasdaq Small Cap Market under the symbol EENC and under the
symbol ENT on the TSX Venture Exchange (TSX). On May 21, 2003 the shares commenced trading on
the Nasdaq National Market under the symbol EENC. On June 20, 2003 the shares commenced trading
on the Toronto Stock Exchange under the symbol ENT. Following our reorganization as an income
trust in November 2003 our trust units commenced trading on the Nasdaq National Market and Toronto
Stock Exchange under the same symbols as the common stock which was retired as a result of the
reorganization. 73




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##### Table of Contents



The following table sets forth the bid prices, in Canadian or U.S. dollars, as reported by the
TSXV, TSX and NASDAQ National and Small Cap Markets/pink sheets, for the periods shown, as restated
for periods prior to November 28, 2003 to reflect the 2:1 conversion from common shares to trust
units. Toronto Stock Exchange/TSX
    
    
    Nasdaq
    
    
    NasdaqVenture Exchange
    
    
    Small Cap 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:December 2004
    
    
    24.00
    
    
    
    19.36
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    19.03
    
    
    
    16.47January 2005
    
    
    23.65
    
    
    
    21.77
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    19.10
    
    
    
    17.83February 2005
    
    
    26.80
    
    
    
    22.03
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    20.95
    
    
    
    18.19March 2005
    
    
    25.14
    
    
    
    21.80
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    20.41
    
    
    
    18.19April 2005
    
    
    28.84
    
    
    
    24.45
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    24.40
    
    
    
    20.00May 2005
    
    
    27.73
    
    
    
    23.01
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    22.49
    
    
    
    18.50June 2005 (through June 15)
    
    
    29.24
    
    
    
    23.85
    
    
    
    n/a
    
    
    
    n/a
    
    
    
    22.21
    
    
    
    19.00
 74




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B. Plan of Distribution Not applicable C. Markets See Item 9.A D. Selling Shareholders Not applicable E. Dilution Not applicable F. Expenses of the issue Not applicable 75




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ITEM 10.
    
    Additional information
  A.
    
    Share Capital Not applicable  B.
    
    Trust Indenture / Memorandum and Articles of Association The Trust Enterra Energy Trust is an open-ended unincorporated investment trust governed by the laws of the
Province of Alberta and created pursuant to the Trust Indenture. The principal undertaking of the Trust is to issue trust units and to acquire and hold debt
instruments, royalties and other interests. The direct and indirect wholly owned subsidiaries of
the Trust carry on the business of acquiring and holding interests in petroleum and natural gas
properties and assets related thereto. The Trustee is prohibited from acquiring any investment or engaging in any activity which (a) would
result in the Trust Units becoming foreign property (as defined in the Income Tax Act(Canada))
or which would cause the Trust to become liable for tax under Part XI under the Income Tax Act
(Canada), (b) would result in the Trust not being considered either a unit trust or a mutual
fund trust for purposes of the Income Tax Act(Canada), or (c) would cause the Trust to be subject
to regulation as an investment company under the U.S. Investment Company Act of 1940. The Trust is authorized to issue an unlimited number of trust units. The Unitholders have no
liability for further capital calls and are not subject to any discrimination due to number of
trust units owned. The rights of trust Unitholders can be changed at any time in a Unitholders meeting where the
modifications are approved by 66 2/3% of the Unitholders represented by proxy or in person at the
meeting. All Unitholders are entitled to vote at annual or special meetings of Unitholders, provided that
they were Unitholders as of the record date. The record date for Unitholders meetings may precede
the meeting date by no more than 50 days and not less than 21 days. Notice of the time and place
of meetings of Unitholders may not be less than 21 or greater than 50 days prior to the date of the
meeting. See Additional Information Relating to the Trust. Enterra Enterra is amalgamated under the laws of the Province of Alberta, Canada (corporation number
207913385). The Articles of Amalgamation and by-laws provide no restrictions as to the nature of
the business operations of Enterra. The governing legislation requires a director to inform Enterra, at a meeting of the Board of
Directors, of any interest he or she has in a material contract or proposed material contract with
Enterra. No director may vote in respect of any such contract made by them with Enterra or in any
such contract in which they are interested. However, these provisions do not apply to (i) an
arrangement by way of security for money lent to or obligations undertaken by them: (ii) a contract
relating primarily to their remuneration as a director, officer, employee or agent of Enterra or an
affiliate: (iii) a contract for indemnity or insurance of the director as allowed under the
governing legislation: or (iv) a contract or transaction with an affiliate. The Board of Directors, subject to the direction of the Trustee, may exercise all powers of the
Trust to borrow or raise money, and to give guarantees, and to mortgage or charge its properties
and assets, and to issue debentures, debenture stock and other securities, outright or as security
for any debt, liability or obligation of the Trust or its subsidiaries. 76




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There are no age limit requirements regarding retirement of directors and there is no minimum share
ownership required for a directors election to the board. All directors of Enterra are elected at each annual meeting of Unitholders of the Trust and
cumulative voting is not permitted. C. Material Contracts The Trust has entered into material contracts that are other than in the ordinary course of
business during the previous two years, other than as described elsewhere in this Form 20-F, as
follows: Governing Trust Documents (a)Trust Indenture  The Trust is governed by an amended and restated trust indenture
dated November 25, 2003 which is fully described in this Form 20-F under Item 4. Information on the
Trust. (b)Administration Agreement  The Trust entered into an administration agreement with
Enterra dated November 25, 2003 in connection with the Arrangement (the Administration
Agreement). Under the Administration Agreement, Enterra is appointed the administrator of the
Trust (the Administrator) and is responsible for the administration and management of all general
and administrative affairs of the Trust. The Administrator is not entitled to the payment of a fee
for the services provided to the Trust. The Administrator is, however, entitled to be indemnified
and saved harmless by the Trust against all losses (other than loss of profit), claims, damages,
liabilities, obligations, costs and expenses in any way arising from and related in any manner to
the provision of services and the performance of obligations by the Administrator unless found
liable for or guilty of fraud, wilful default or negligence. (c)Enterra Note Indenture Enterra entered into an agreement with Olympia Trust Company
dated November 25, 2003 (the Note Indenture) providing for the issuance of unsecured subordinated
notes. An unlimited number of notes may be issued under the Note Indenture. The initial series of
notes issued were Series A Notes which rank equally in right of payment. The initial principal
amount of the Series A Notes issued was $125,000,000 bearing interest at a rate of 14% per annum.
Additional Series A Notes may be issued from time to time. Pursuant to the terms of the Note
Indenture, and subject to certain restrictions set forth therein, Enterra is entitled to defer the
payment of interest on the principal amount of the Series A Notes for periods not exceeding 27
consecutive months. In certain circumstances, Enterra has the ability to make payments in respect
of interest and/or principal on the Series A Notes by the issuance of common shares of Enterra.
The Note Indenture provides for various events of default with respect to the Series A Notes
including, but not limited to, failure to pay interest or principal, acceleration of senior
indebtedness of Enterra, failure to perform any other covenant, certain events of bankruptcy or
ceasing to carry on in the ordinary course of business. (d)Support Agreement In connection with the Arrangement, the Trust entered into a
support agreement with Enterra dated November 25, 2003 (the Support Agreement) to establish a
procedure whereby the Trust would take certain actions and make certain payments and deliveries
necessary to ensure that Enterra can make certain payments and deliver Trust Units in satisfaction
of its obligations in connection with the Exchangeable Shares issued pursuant to the Arrangement. Under the Support Agreement, the Trust has agreed that: (a) it will take all actions and do all
things necessary to ensure that Enterra is able to pay to the holders of the Exchangeable Shares
the Liquidation Amount in the event of a liquidation, dissolution or winding up of Enterra, the
Retraction Price in the event of the giving of a Retraction Request by a holder of Exchangeable
Shares, or the Redemption Price in the event of a redemption of Exchangeable Shares by Enterra (as
such capitalized terms are defined in the Support Agreement); and (b) it will not vote or otherwise
take any action or omit to take any action causing the liquidation, dissolution or winding up of
Enterra. The Support Agreement also provides that the Trust will not issue or distribute to the holders of
all or substantially all of the outstanding Trust Units:  (a)
    
    additional Trust Units or securities convertible into Trust Units; 77




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(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; unless the same or an equivalent distribution is made to holders of Exchangeable Shares, an
equivalent change is made to the Exchangeable Shares, such issuance or distribution is made in
connection with a distribution reinvestment plan instituted for holders of Trust Units or a
unitholder rights protection plan approved for holders of Trust Units by the Enterra board of
directors or the approval of holders of Exchangeable Shares has been obtained. The Trust may not subdivide, reduce, consolidate, reclassify or otherwise change the terms of the
Trust Units unless an equivalent change is made to the Exchangeable Shares or the approval of the
holders of Exchangeable Shares has been obtained. In the event of any proposed take-over bid, issuer bid or similar transaction affecting the Trust
Units, the Trust will use reasonable efforts to take all actions necessary or desirable to enable
holders of Exchangeable Shares to participate in such transaction to the same extent and on an
economically equivalent basis as the Unitholders. With the exception of certain administrative changes, the Support Agreement may not be amended
without the approval of the holders of the Exchangeable Shares. The Trust also agreed not to
exercise any voting rights attached to the Exchangeable Shares owned by it or any of its respective
subsidiaries and other affiliates on any matter considered at meetings of holders of Exchangeable
Shares. (e)Voting and Exchange Trust Agreement The Trust entered into an agreement dated
November 25, 2003 with Enterra, Enterra Exchangeco Ltd. (Exchangeco) and Olympia Trust Company,
as the initial Trustee (the Voting and Exchange Trust Agreement), pursuant to which the Trust
issued a special voting right to the Trustee for the benefit of the holders of the Exchangeable
Shares (the Special Voting Right). The Special Voting Right carries a number of votes,
exercisable at any meeting at which Unitholders are entitled to vote, equal to the number of Trust
Units into which the outstanding Exchangeable Shares are then exchangeable multiplied by the number
of votes to which the holder of one Trust Unit is then entitled. Upon the occurrence and during the continuance of: (a) an Insolvency Event (as defined in the
Voting and Exchange Trust Agreement); or (b) circumstances in which the Trust or Exchangeco may
exercise certain call rights held by them, but elect not to exercise such call rights; a holder of Exchangeable Shares will be entitled to instruct the Trustee to exercise the Optional
Exchange Right (as defined in the Voting and Exchange Trust Agreement) with respect to any or all
of the Exchangeable Shares held by such holder, thereby requiring the Trust or Exchangeco to
purchase such Exchangeable Shares from the holder. The purchase price payable by the Trust or Exchangeco for each Exchangeable Share to be purchased
under the Optional Exchange Right will be satisfied by the issuance of that number of Trust Units
equal to the Exchange Ratio (as defined in the Voting and Exchange Trust Agreement) as at the day
of closing of the purchase and sale of such Exchangeable Share under the Optional Exchange Right. If, as a result of solvency provisions of applicable law, Enterra is unable to redeem all of a
holders Exchangeable Shares such holder is entitled to have redeemed in accordance with the
Exchangeable Share Provisions, the holder will be deemed to have exercised the Optional Exchange
Right with respect to the unredeemed Exchangeable Shares and the Trust or Exchangeco will be
required to purchase such shares from the holder in the manner set forth above. Other Material Contracts (f)Amended and Restated Agreement of Business Principles  The Trust, JED Oil Inc.
(JED) and JMG Exploration, Inc. (JMG) are parties to an Amended and Restated Agreement of
Business Principles pursuant to which each oil and gas property which is owned by the Trust is as a
general matter to be developed or explored under arrangements pursuant to which JED and JMG,
respectively, bear the cost thereof in exchange for a percentage (usually 70 percent) of such
property and the Trust retains the balance of such property. The Trust has a first right to
purchase oil and gas properties owned by JED prior to the sale thereof to others, and the Trust has
the 78




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right to purchase 80 percent of any oil and gas property that is owned by JMG when drilling has
established the existence of commercially viable quantities of oil or gas at a value that is based
upon an independent engineering report. (g)Technical Services Agreement  The Trust and JED are parties to a Technical Services
Agreement pursuant to which employees of JED may provide administrative, management and technical
services to the Trust at the cost of the Trust and the Trust is to provide office space and
administrative supplies to JED at the cost of JED. (h)RMAC Arrangement Agreement  The Trust entered into an Arrangement Agreement dated
August 20, 2004 for the acquisition of all of the issued and outstanding common shares of Rocky
Mountain Energy Corp. (Rocky) completed on September 29, 2004 by plan of arrangement. The
acquisition was paid for by the issuance of 1,946,576 Trust Units, 341,882 Exchangeable Shares and
cash of C$7,223,746. Each Rocky common share was exchanged for 0.35078 Trust Units, Exchangeable
Shares or cash. The acquisition was valued at approximately C$55 million. (i)RMAC Note Indenture  Rocky Mountain Acquisition Corp. entered into an agreement with
Olympia Trust Company dated September 28, 2004 (the RMAC Note Indenture) providing for the
issuance of unsecured subordinated notes. An unlimited number of notes may be issued under the RMAC
Note Indenture. The initial series of notes issued were Series A Notes which rank equally in right
of payment. The initial principal amount of the Series A Note issued was $29,153,223 bearing
interest at the rate of 11% per annum. Additional Series A Notes may be issued from time to time.
Pursuant to the terms of the RMAC Note Indenture, and subject to certain restrictions set forth
therein, RMAC is entitled to defer the payment of interest on the principal amount of the Series A
Notes for periods not exceeding 27 consecutive months. In certain circumstances, RMAC has the
ability to make payments in respect of interest and/or principal on the Series A Notes by the
issuance of common shares of RMAC. The RMAC Note Indenture provides for various events of default
with respect to the Series A Notes including, but not limited to, failure to pay interest or
principal, acceleration of senior indebtedness of RMAC, failure to perform any other covenant,
certain events of bankruptcy or ceasing to carry on in the ordinary course of business. (j)Trust Unit Sale Agreement  The Trust entered into an agreement with Kingsbridge
Capital Limited (Kingsbridge) on April 22, 2005 for a drawdown equity financing arrangement.
Pursuant to this agreement, Kingsbridge agreed to purchase up to $100 million Trust Units over a
two year period. The Trust has no obligation to access any of the available capital, but may do so
at its option. The subscription price of the Trust Units on each drawdown will be 92% of the
fifteen day volume weighted average trading price of the Trust Units on the Nasdaq provided that
the price must be at least US$12.00 and not less than the minimum price permitted by the rules of
the Toronto Stock Exchange. The first draw may be up to US$10 million, and each subsequent draw
can be up to the lesser of 4% of the Trusts market capitalization or US$25 million. The Trust
also granted a warrant to Kingsbridge to purchase 301,000 Trust Units which cannot be exercised for
three months and thereafter has a three year term. The exercise price of the warrant will
initially be US$25.77 per Trust Unit which will be reduced each month by the amount of the Trusts
distribution for such month on the Trust Units, provided that the price shall not decrease below
US$21.55 per Trust Unit as provided by the Toronto Stock Exchange convertible securities pricing
rules. (k)High Point Arrangement Agreement  The Trust signed an arrangement agreement dated May
31, 2005 with High Point Resources Inc. (High Point) to acquire all of the issued and outstanding
common shares of High Point 79




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to be completed by plan of arrangement (the High Point Plan). High Point shareholders will
receive 0.105 of a Trust Unit or Exchangeable Share for each High Point common share held. The
value of this transaction is approximately US$250 million and the Trust will issue approximately
8.9 million Trust Units in association with the High Point Plan, which equals approximately 35% of
the current issued and outstanding Trust Units. This transaction remains subject to approval by
the High Point shareholders at a special meeting which is expected to occur in August 2005.  D.
    
    Exchange Controls There is no law or government decree or regulation in Canada that restricts the export or import of
capital, or affects the remittance of dividends, interest or other payments to non-resident holders
of trust units, other than withholding tax requirements. There is no limitation imposed by Canadian law or by our charter or other charter documents on the
right of a non-resident to hold or vote our trust units, other than as provided by the Investment
Canada Act, the North American Free Trade Agreement Implementation Act(Canada) and the World Trade
Organization Agreement Implementation Act. The Investment Canada Actrequires notification and, in
certain cases, advance review and approval by the Government of Canada of the acquisition by a
non-Canadian of control of a Canadian business, each as defined in the Investment Canada Act.
In general, the threshold for review will be higher in monetary terms for a member of the World
Trade Organization or North American Free Trade Agreement. 80




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E.
    
    Taxation Canadian Federal Income Tax Considerations
The following is a summary of the material Canadian federal income tax considerations under the
Income Tax Act(Canada) (the Tax Act) in respect of the acquisition of trust units pursuant this
offering generally applicable to purchasers who (i) hold trust units as capital property for
purposes of the Tax Act, and (ii) at all material times deal at arms length, and are not
affiliated, with Enterra and the Trust for purposes of the Tax Act. Generally, trust units will be
considered to be capital property to a holder who does not hold such securities in the course of
carrying on a business and has not acquired them in one or more transactions considered to be an
adventure in the nature of trade. Certain Canadian resident Unitholders who might not otherwise be
considered to hold their trust units as capital property may, in certain circumstances, be entitled
to make an irrevocable election in accordance with subsection 39(4) of the Tax Act to have such
trust units treated as capital property. This summary is not applicable to either a unitholder that is a financial institution or a
specified financial institution, as defined for purposes of the Tax Act, or a unitholder, an
interest in which would be a tax shelter investment under the Tax Act. This summary is based upon the provisions of the Tax Act and the regulations thereunder (Tax
Regulations) in force as of the date hereof, all specific proposals to amend the Tax Act and the
Tax Regulations that have been publicly announced by or on behalf of the Minister of Finance
(Canada) prior to the date hereof (the Proposed Amendments) and the Trusts understanding of the
current published administrative and assessing policies of the Canada Revenue Agency (the CRA). This summary is not exhaustive of all possible Canadian federal income tax considerations
applicable to the acquisition of trust units and, except for the Proposed Amendments, does not take
into account or anticipate any changes in the law, whether by legislative, governmental or judicial
action or changes in the administrative and assessing practices of the CRA. This summary does not
take into account any provincial, territorial or foreign tax considerations, which may differ
significantly from those discussed herein. 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 This portion of the summary is applicable to a unitholder who, for the purposes of the Tax Act and
at all relevant times, is resident, or deemed to be resident, in Canada. Status of the Trust The Trust qualifies as a mutual fund trust under the provisions of the Tax Act and the balance of
the summary assumes that the Trust will continue to so qualify. The Trust is also a registered
investment under the Tax Act, and this summary further assumes that the Trust will be so
registered.] The requirements to qualify as a mutual fund trust for purposes of the Tax Act include:  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 81




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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. The Trust has certain restrictions on its activities and its powers and certain restrictions on the
holding of taxable Canadian property, such that Enterra believes it is reasonable to expect that
the requirements will be satisfied. However, Enterra and the Trust can provide no assurances that
the requirements will continue to be met. 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 The Trust is subject to tax in each taxation year on its income or loss for the year, computed as
though it were a separate individual resident in Canada. The taxation year of the Trust will end
on December 31 of each year. The Trust will be required to include in its income for each taxation year (i) all interest on the
Notes that accrues to, becomes receivable or is received by it before the end of the year, except
to the extent that such interest was included in computing its income for a preceding year (ii) all
interest on the CT Note that accrues to, becomes receivable or is received by it before the end of
the year, except to the extent that such interest was included in computing its income for a
preceding year (iii) the net income of Commercial Trust paid or payable to the Trust in the year
and (iv) all amounts in respect of any oil and gas royalties, if any, held by the Trust including
any amounts required to be reimbursed to the grantor of the royalty in respect of Crown charges. In computing its income, the Trust will generally be entitled to deduct reasonable administrative
expenses incurred to earn income. The Trust will be entitled to deduct the costs incurred by it in
connection with the issuance of trust units on a five-year, straight-line basis (subject to
pro-ration for short taxation years). The Trust may also deduct amounts which become payable by it
to Unitholders in the year, to the extent that the Trust has net income for the year after the
inclusions and deductions outlined above and to the extent permitted under the Tax Act. An amount
will be considered to have become payable to a unitholder in a taxation year only if it is paid in
that year by the Trust or the unitholder is entitled in that year to enforce payment of the amount.
Under the Trust Indenture, net income of the Trust for each year will be paid or made payable by
way of cash distributions to the Unitholders. The Trust Indenture also contemplates other
situations in which the Trust may not have sufficient cash to distribute all of its net income by
way of such cash distributions. In such circumstances, such net income will be payable to
Unitholders in the form of the issuance by the Trust of additional trust units (Reinvested trust
units). Accordingly, it is anticipated that the Trust will generally not have any taxable income
for the purposes of the Tax Act. Under the Trust Indenture, income received by the Trust may be used to finance cash redemptions of
trust units. A redemption of trust units that is effected by a distribution by the Trust to a
unitholder of Series A Notes will be treated as a disposition by the Trust of such Series A Notes
for proceeds of disposition equal to the fair market value thereof and may give rise to a taxable
capital gain to the Trust. The Trust will be entitled for each taxation year to reduce (or receive a refund in respect of) its
liability, if any, for tax on its net taxable capital gains by an amount determined under the Tax
Act based on the redemption or retraction of trust units during the year (the Capital Gains
Refund). In certain circumstances, the Capital Gains Refund for a particular taxation year may
not completely offset the Trusts tax liability on net realized capital gains for such taxation
year. For purposes of the Tax Act, the Trust generally intends to deduct, in computing its income and
taxable income, the full amount available for deduction in each year. As a result of such
deductions and the Trusts entitlement to a Capital Gains Refund, it is expected that the Trust
will not be liable for any material amount of tax under the Tax Act. However, no assurance can be
given in this regard. The Trust is a registered investment under the Tax Act. It may have its registration revoked by
the CRA if it ceases to be a mutual fund trust and did not otherwise qualify for registered
investment status. 82




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If the Trust ceases to qualify as a mutual fund trust, the Trust may be required to pay tax under
Part XII.2 of the Tax Act. The payment of Part XII.2 tax by the Trust may have material adverse
tax consequences for certain Unitholders. Taxation of Unitholders Income from trust units The income of a unitholder from the trust units will be considered to be income from property for
the purposes of the Tax Act. Any deduction or loss of the Trust for the purposes of the Tax Act
cannot be allocated to and treated as a deduction or loss of a unitholder. A unitholder will generally be required to include in computing income for a particular taxation
year of the unitholder the portion of the net income of the Trust for a taxation year, including
taxable dividends and net taxable capital gains, that is paid or becomes payable to the unitholder
in that particular taxation year, whether such amount is payable in cash or in Reinvested trust
units. Provided that appropriate designations are made by Commercial Trust and the Trust, such
portion of the Trusts net taxable capital gains and taxable dividends, if any, as are paid or
payable to a unitholder will effectively retain their character as taxable capital gains and
taxable dividends, respectively, and will be treated as such in the hands of the unitholder for
purposes of the Tax Act. The amount of any net taxable capital gains designated by the Trust to a unitholder will be
included in the unitholders income under the Tax Act for the year of disposition as a taxable
capital gain. See Taxation of Capital Gains and Capital Losses above. The non-taxable portion
of net realized capital gains of the Trust that is paid or becomes payable to a unitholder in a
year will not be included in computing the unitholders income for the year. Any other amount in
excess of the net income of the Trust that is paid or becomes payable by the Trust to a unitholder
in a year will generally not be included in the unitholders income for the year. However, a
unitholder is required to reduce the adjusted cost base of the trust units held by such unitholder
by each amount payable to the unitholder otherwise than as proceeds of disposition of trust units
(except to the extent that the amount either was included in the income of the unitholder or was
the unitholders share of the non-taxable portion of the net capital gains of the Trust, the
taxable portion of which was designated by the Trust in respect of the unitholder). To the extent
that the adjusted cost base of a trust unit is less than zero, the negative amount will be deemed
to be a capital gain of a unitholder from the disposition of the trust unit in the year in which
the negative amount arises. See Taxation of Capital Gains and Capital Losses below. The amount of dividends designated by the Trust to a unitholder will be subject to, among other
things, the gross-up and dividend tax credit provisions for Unitholders who are individuals, the
refundable tax under Part IV of the Tax Act applicable to private corporations and subject
corporations (as defined under the Tax Act), and the deduction in computing taxable income in
respect of dividends received by taxable Canadian corporations. In general, net income of the
Trust that is designated as taxable dividends from taxable Canadian corporations or as net taxable
capital gains may increase an individual unitholders liability for alternative minimum tax. Cost of trust units The cost to a unitholder of a trust unit will generally include all amounts paid by the unit holder
for the trust unit. Reinvested trust units issued to a unitholder, as a non-cash distribution of
income will have a cost equal to the amount of income distributed by the issuance of such
Reinvested trust units. This cost will be averaged with the adjusted cost base of all other trust
units held by the unitholder as capital property in order to determine the respective adjusted cost
base of each trust unit. Disposition of trust units Upon the disposition or deemed disposition by a unitholder of a trust unit, whether on a redemption
or otherwise, the unitholder will generally realize a capital gain (or a capital loss) equal to the
amount by which the proceeds of disposition exceed (or are less than) the aggregate of (i) such
unitholders adjusted cost base of the trust units disposed of, determined immediately before the
disposition and (ii) any reasonable costs of disposition. A redemption of trust units in
consideration for cash distributed to the unitholder in satisfaction of the Market Redemption
Price, or the issuance of a Redemption Note by the Trust in satisfaction of the Market Redemption 83




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Price, will be a disposition of such trust units for proceeds of disposition equal to the cash or
the principal amount of the Redemption Note, as the case may be. Where trust units are redeemed by
the distribution of Series A Notes to the unitholder, the proceeds of disposition to the unitholder
of such trust units will generally be equal to the fair market value of the Series A Notes so
distributed less any capital gain or income realized by the Trust in connection with such
redemption which has been designated by the Trust to the redeeming unitholder. Where a unitholder that is a corporation or a trust (other than a mutual fund trust) disposes of a
trust unit, the unitholders capital loss from the disposition will generally be reduced by the
amount of dividends from taxable Canadian corporations previously designated by the Trust to the
unitholder, except to the extent that a loss on a previous disposition of a trust unit has been
reduced by such dividends. Similar rules apply where a corporation or trust (other than a mutual
fund trust) is a member of a partnership that disposes of trust units. See Taxation of Capital
Gains and Capital Losses below. The cost to a unitholder of any Series A Notes distributed to the unitholder by the Trust on a
redemption of trust units will be equal to the fair market value of such Series A Notes at the time
of distribution, excluding any accrued interest thereon. Such a unitholder will be required to
include in income interest on such Series A Notes (including interest that had accrued to the date
of distribution of the Series A Notes to the unitholder) in accordance with the provisions of the
Tax Act. To the extent that the unitholder is required to include in income any interest that had
accrued to the date of distribution of the Series A Notes, an offsetting deduction will be
available in computing the unitholders income from the Trust. A unitholder will be required to include in income interest on the Redemption Notes in accordance
with the provisions of the Tax Act. A unitholder that is corporation that is throughout a relevant taxation year a Canadian-controlled
private corporation, as defined in the Tax Act, may be liable to pay an additional refundable tax
of 6 2/3% on certain investment income, including taxable capital gains and interest. Tax-Exempt Unitholders Provided that the Trust qualifies as a mutual fund trust or is a registered investment for
purposes of the Tax Act at a particular time, the trust units will be qualified investments for
Exempt Plans. If the Trust ceases to qualify as a mutual fund trust and the Trusts registration
as a registered investment under the Tax Act is revoked, the trust units will cease to be qualified
investments under the Tax Act for Exempt Plans. Where, at the end of a month, an Exempt Plan holds
trust units or other properties that are not qualified investments, the Exempt Plan may, in respect
of that month, be required to pay a tax under Part XI.1 of the Tax Act. Exempt Plans will generally not be liable for tax in respect of any distributions received from the
Trust or any capital gain arising on the disposition of trust units. However, where an Exempt Plan
receives trust property as a result of a redemption of trust units, some or all of such property
may not be qualified investments under the Tax Act for the Exempt Plans and could, as discussed
above, give rise to adverse consequences to the Exempt Plans (and, in the case of registered
retirement savings plans or registered retirement income funds, to the annuitants thereunder).
Accordingly, Exempt Plans that own trust units should consult their own tax advisors before
deciding to exercise their redemption rights thereunder. Taxation of Capital Gains and Capital Losses Generally, one half of any capital gain (a taxable capital gain) realized by a unitholder or a
unitholder on the disposition of capital property in a taxation year must be included in the income
of the holder for the year, and one half of any capital loss (an allowable capital loss) realized
in a taxation year may be deducted from taxable capital gains realized by the holder in that year.
Allowable capital losses for a taxation year in excess of taxable capital gains for that year
generally may be carried back and deducted in any of the three preceding taxation years or carried
forward and deducted in any subsequent taxation year against net capital gains realized in such
years, to the extent and under the circumstances described in the Tax Act. 84




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A corporation that is throughout a relevant taxation year a Canadian-controlled private
corporation, as defined in the Tax Act, may be liable to pay an additional refundable tax of 6
2/3% on certain investment income, including taxable capital gains realized in the particular
taxation year. Capital gains realized by an individual may give rise to a liability for alternative minimum tax. Non-Residents of Canada This portion of the summary is applicable to a unitholder who, for the purposes of the Tax Act, and
at all relevant times is not resident in Canada and is not deemed to be resident in Canada, does
not use or hold, and is not deemed to use or hold, trust units in, or in the course of, carrying on
business in Canada, and is not an insurer who carries on an insurance business in Canada and
elsewhere (a Non-Resident Holder). Taxation of the Trust The tax treatment of the Trust under the Tax Act is as generally described above under Residents
of Canada  Taxation of the Trust. If the Trust ceases to qualify as a mutual fund trust for
purposes of the Tax Act, the Trust may be required to pay tax under Part XII.2 of the Tax Act. The
payment of Part XII.2 tax by the Trust may have adverse tax consequences to certain Unitholders. Taxation of Income from Trust Units All income of the Trust determined in accordance with the Tax Act (except taxable capital gains)
paid or credited by the Trust in a taxation year to a Non-Resident Holder will generally be subject
to Canadian withholding tax at a rate of 25%, subject to a reduction of such rate under an
applicable income tax treaty or convention, whether such income is paid or credited in cash or in
Reinvested trust units. See Residents of Canada  Taxation of the Trust above. Provided that
certain conditions are satisfied, the rate of Canadian withholding tax may be reduced to 15% in
respect of amounts that are paid or credited by the Trust to a Non-Resident Holder that is a United
States resident for the purposes of the Canadian-United States Income Tax Convention. The Trust is required to maintain a special TCP gains balance account to which it will add its
capital gains from dispositions after March 22, 2004 of taxable Canadian property (as defined in
the Tax Act) and from which it will deduct its capital losses from dispositions of such property
and the amount of all TCP gains distributions (as defined in the Tax Act) made by it in previous
taxation years. If the Trust pays an amount to a Non-Resident Holder, makes a designation to treat
that amount as a taxable capital gain of the Holder and the total of all such amounts designated by
the Trust in a taxation year to Non-Resident Holders exceeds 5% of all such designated amounts,
such portion of that amount as does not exceed the Non-Resident Holders pro rata portion of the
Trusts TCP gains balance account (as defined in the Tax Act) for the taxation year effectively
will be subject to the same Canadian withholding tax as described above for distributions of income
(other than net realized capital gains). All other amounts distributed by the Trust to a
Non-Resident Holder other than amounts described above, where more than 50% of the fair market
value of a Trust Unit is attributable to, inter alia, real property situated in Canada or a
Canadian resource property (as defined in the Tax Act) will be subject to a special Canadian tax
of 15% of the amounts of such distributions as an income tax on the deemed capital gain. This tax
will be withheld from such distributions by the Trust. A Non-Resident Holder will not be required
to report such distribution in a Canadian tax return and such distribution will not reduce the
adjusted cost base of the Non-Resident Holders Trust Units. If a Non-Resident Holder realizes a
capital loss on the disposition of a Trust Unit in a particular taxation year and files a special
tax return on or before such Non-Resident Holders filing due date for such taxation year, the
Non-Resident Holder will have a Canadian property mutual fund loss (as defined in the Tax Act)
equal to the lesser of such loss and sum of all distributions previously received on such Trust
Unit that were subject to 15% tax. The Non-Resident Holders tax liability for such taxation year
shall be computed by reducing any deemed capital gain for the taxation year by the aggregate of
such loss and any unused Canadian property mutual fund losses (as defined in the Tax Act) from
previous taxation years arising from the disposition of a Trust Unit or a share of the capital
stock of a mutual fund corporation or a unit of another mutual fund trust. In certain
circumstances, the Non-Resident Holder may be entitled to receive a refund of all or a portion of
such tax. A Canadian property mutual fund loss and unused Canadian mutual fund losses generally may
be carried back up to three years and forward indefinitely and deducted against similar
distributions received in such years. 85




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Disposition of trust units A Non-Resident Holder will be subject to taxation in Canada in respect of a capital gain or capital
loss realized on the disposition of trust units only to the extent such units constitute taxable
Canadian property, as defined in the Tax Act, and the Non-Resident Holder is not afforded relief
under an applicable income tax treaty or convention. Trust units will normally not be taxable Canadian property at a particular time provided that (i)
the Non-Resident Holder, persons with whom the Non-Resident Holder does not deal at arms length
(within the meaning of the Tax Act), or the Non-Resident Holder together with such persons, did not
own or have an interest in or option in respect of 25% or more of the issued trust units at any
time during the 60-month period preceding the particular time (ii) the Trust is a mutual fund trust
at the time of the disposition, and (iii) the trust units are not otherwise deemed to be taxable
Canadian property. A Non-Resident Holder of trust units that are not taxable Canadian property will not be subject to
tax on gains realized under the Tax Act on the disposition of such units. A Non-Resident Holder whose trust units constitute taxable Canadian property generally will realize
a capital gain (or capital loss) on the redemption or disposition of such units equal to the amount
by which the proceeds of disposition exceeds (or is less than) the aggregate of (i) such
unitholders adjusted cost base of its trust units so disposed, determined immediately before the
disposition and (ii) any reasonable costs of disposition. Taxation of Capital Gains and Capital Losses on Dispositions of Taxable Canadian Property Generally, one half of any capital gain (a taxable capital gain) realized by a Non-Resident
Holder on a disposition of taxable Canadian property in a taxation year must be included in the
income of the Non-Resident Holder for the year, and one half of any capital loss (an allowable
capital loss) realized by a Non-Resident Holder on a disposition of taxable Canadian property in a
taxation year may be deducted from taxable capital gains realized by the Non-Resident Holder in
that year. Allowable capital losses for a taxation year in excess of taxable capital gains for
that year generally may be carried back and deducted in any of the three preceding taxation years
or carried forward and deducted in any subsequent taxation year against net capital gains realized
in such years, to the extent and under the circumstances described in the Tax Act. In certain cases where a Non-Resident Holder realizes a capital gain from a disposition of property
that constitute taxable Canadian property to such Non-Resident Holder, it is possible that any such
capital gain may be exempt from tax for the purposes of the Tax Act by virtue of the provisions of
an income tax treaty or convention between Canada and the country of residence of the Non-Resident
Holder. Conversely, the amount of any capital loss resulting from the disposition of such property
may not be deductible against capital gains of the Non-Resident Holder for the purposes of the Tax
Act by virtue of the provisions of such income tax treaty or convention. Unitholders who are
Non-Resident Holders are advised to consult with their tax advisors regarding the application of
any applicable income tax treaty or convention. If a Non-Resident Holder disposes of taxable Canadian property, the Non-Resident Holder is required
to file a Canadian income tax return for the taxation year in which such disposition occurs. United States Federal Income Tax Considerations The following summary discusses the material United States federal income tax considerations that
are generally applicable to a holder of Enterra common shares and trust units who is a citizen or
resident of the United States, who is a corporation, partnership or other entity that is created or
organized in or under the laws of the United States, who is subject to United States federal income
tax on a net income basis with respect to Enterra common shares or who will be subject to United
States federal income tax on a net income basis with respect to trust units that are acquired (a
U.S. Holder). This summary does not purport to be a complete description of all of the United States federal
income tax considerations that may be relevant to a U.S. Holder. In particular, this summary deals
only with U.S. Holders who hold Enterra common shares as a capital asset. This summary does not
address the tax treatment of U.S. Holders 86




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who are subject to special tax rules. Nor does this summary discuss the United States federal
income tax considerations for a partner in a partnership which holds Enterra common shares or trust
units. Flow-through of Items of Income, Gain, Loss, Deduction and Credit A U.S. holder will include in each of its taxable years its share of our items of income, gain,
loss, deduction and credit and certain deductions in respect of depletion for each of our taxable
years that ends within or with such U.S. holders taxable year on its own United States federal
income tax return in order to determine its liability for United States federal income tax whether
or not we make any distribution to it. Such items of income, gain, loss, deduction and credit will
be determined on United States federal income tax principles and will as a general matter retain
their character and source as they flow through us to the holders of trust units. The use by a
holder of trust units of certain of our items of deduction, loss and credit will be limited as is
discussed below. As a result, a U.S. holder whose taxable year is not the same as our taxable year and who disposes
of all of its trust units after the close of its taxable year but before the end of our taxable
year will be required to include in income for its then taxable year its share of more than one
year of our items of income, gain, loss, deduction and credit. A U.S. Holders share of our items
of income, gain, loss, deduction and credit will, as a general matter, be its percentage interest
in us of such items. Tax Rates and Creditability of Certain Canadian Income Taxes. As general matter, the character and source of a U.S. holders share of the items of the income,
gain, loss, deduction and credit is determined at our level and flows through us to each such U.S.
holder in determining its liability for United States federal income tax including any effect of
the alternative minimum tax. Each U.S. holder should consult with its tax advisors as to the
impact of holding trust units on its liability for the United States federal income tax and the
alternative minimum tax. The rules as to the use of foreign income taxes as credits are complex,
the following discussion is only a summary of a portion thereof, and a U.S. holder should discuss
these matters with its own tax advisors. United States Federal Income Tax Rates A U.S. holders share of our oil and gas production is treated as ordinary income subject to cost
depletion. Such ordinary income is generally subject to the income tax at a maximum rate of 35
percent. Dividends that are received from a foreign corporation are currently subject to the
United States federal income tax at a maximum rate of 15 percent under certain conditions. If a
U.S. holder who is an individual, then any dividends received would be subject to the United States
federal income tax at a maximum rate of 15 percent so long as (i) the shares in respect of which
the dividends are paid have been held (subject to certain tolling rules) for more than 60 days
during the 120 day period which begins 60 days before the those shares go ex-dividend, (ii) such
U.S. holder is not under an obligation to make certain related payments with respect to
substantially similar or related property, (iii) we are not either a foreign personal holding
company, a foreign investment company or a passive foreign investment company, and (iv) we are
eligible for the benefits of the income tax treaty between Canada and the United States. It is
likely that the Internal Revenue Service will take the position that such holding period
requirement is applied when an individual holds shares indirectly through us to the individuals
holding period in trust units. For a U.S. holder who is an individual, any long-term capital gain that is realized on the sale or
other disposition of trust units (including any part of a distribution that is treated as gain on
such shares that is a long-term capital gain) would be subject to tax at a maximum rate of 15
percent until the end of 2008 under current law. Each U.S. holder should discuss with its own
advisor whether a person whose holding period in us is less than one year can claim such 15 percent
tax rate. Credits for Canadian Income Taxes As a general matter, any Canadian income taxes that are withheld from distributions are foreign
income taxes that, subject to generally applicable limitations under United States law, may be used
by a U.S. holder as a credit against its United States federal income tax liability or as a
deduction (but only for a taxable year for which such U.S. holder elects to do so with respect to
all foreign income taxes). So long as we are a partnership for United States federal 87




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income tax purposes, the provisions of Section 901(k) of the Internal Revenue Code should not
apply. If we were a corporation for such purposes, then a U.S. Holder would not be able to claim
the foreign tax credit with respect to any such Canadian tax that is withheld on a distribution
that we made unless such U.S. holder had held the trust units for a minimum period (subject to
certain tolling rules) of at least 16 days during the 30 day period beginning on the date which is
15 days before the date on which the trust units went ex-dividend with respect to such dividend or
to the extent such U.S. holder is under an obligation to make related payments with respect to
substantially similar or related property. It is likely that the Internal Revenue Service will
take the position that the holding period requirement that is summarized in the preceding sentence
is measured as to an individual partner of us in respect of any Canadian taxes paid by us in
respect of dividends that we receive by the holding period in the trust units. The limitation under United States law on foreign taxes that may be used as credits is calculated
separately with respect to specific classes of income or baskets. That is, the use of foreign
taxes that are paid with respect to income in any such basket as a credit is limited to a
percentage of the foreign source income in that basket. For such purposes, a U.S. holders share
of our income, gain, loss and deductions is generally in the passive basket if it holds less than
10 percent of the trust units. Its share of the dividends and the income will be from foreign
sources, but the amount of foreign source income of an individual is only a fraction of the
dividend income that is subject to the 15 percent maximum rate. Under rules of general
application, a portion of a U.S. holders interest expense and other expenses can be allocated to,
and thereby reduce, the foreign source income in any basket. Any gain that is recognized by a U.S. Holder on the sale of a trust unit that is recognized because
a distribution thereon is in excess of basis in that security will generally constitute income from
sources within the United States for U.S. foreign tax credit purposes and will therefore not
increase the ability to use foreign taxes as credits. Tax Consequences if We are Determined to be a Passive Foreign Investment Company Although we do not expect to be a passive foreign investment company, or PFIC, it will be a PFIC if
either (a) 75 percent or more of its gross income in a taxable year, including the pro rata share
of the gross income of any company, U.S. or foreign, in which it is considered to own 25 percent or
more of the shares by value, is passive income (as defined in the pertinent provisions of the
Internal Revenue Code or (b) 50 percent or more of its assets (including the pro rata share of the
assets of any company in which it is considered to own 25 percent or more of the shares by value),
are held for the production of, or produce, passive income. Although we believe that we are not
currently a PFIC and do not expect that we will become a PFIC, there is no assurance in that
regard. If we were a PFIC, and a U.S. holder did not make an election to treat it as a qualified electing
fund (there is no assurance that it will be able to make such an election) or elect to make a
mark-to-market election (again, there is no assurance that it will be able to make such an
election) then distributions on our stock that exceed 125 percent of the average distributions
received by the U.S. holder in the shorter of the three previous taxable years or the U.S. holders
holding period for the trust units before the taxable year of distribution and the entire amount of
gain that is realized by a U.S. holder upon the sale of the trust units would be subject to an
additional United States income tax that approximates (and in some cases exceeds) the value of
presumed benefit of a deferral of United States income taxation that was available because we are a
foreign corporation. Tax-Exempt Organizations and Other Investors Ownership of trust units by employee benefit plans, other tax-exempt organizations, non-resident
aliens, foreign corporations, other foreign persons and regulated investment companies or mutual
funds raises issues unique to those investors and, as described below, may have substantially
adverse tax consequences to them. Employee benefit plans and most other organizations exempt from federal income tax, including
individual retirement accounts and other retirement plans, are subject to federal income tax on
unrelated business taxable income. We are unable to provide any assurance that the income that we
recognize in respect of the royalty or in respect of any of our other assets will not be unrelated
business taxable income. A regulated investment company or mutual fund (as such terms are used in the Internal Revenue
Code) is required in order to maintain its special status under the Internal Revenue Code to derive
90 percent or more of its gross 88




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income from interest, dividends and gains from the sale of stocks or securities or foreign currency
or specified related sources. A significant amount of our gross income may not be any such type of
income. Administrative Matters Information Returns and Audit Procedures We expect to furnish to each unitholder, within 90 days after the close of each calendar year,
specific tax information, including a Schedule K-1, which describes the unitholders share of our
income, gain, loss, deduction and credits for the preceding taxable year. In preparing this
information, which will not be reviewed by tax counsel, we will take various accounting and
reporting positions, some of which have been mentioned earlier, to determine the share of income,
gain, loss and deduction. We cannot assure you that those positions will yield a result that
conforms to the requirements of the Internal Revenue Code Treasury regulations or administrative
interpretations of the Internal Revenue Service. Any challenge by the Internal Revenue Service
could negatively affect the value of the trust units. The Internal Revenue Service may audit our federal income tax information returns. Adjustments
resulting from an Internal Revenue Service audit may require each unitholder to adjust a prior
years tax liability, and possibly may result in an audit of its return. Any audit of a
unitholders return could result in adjustments not related to our returns. Partnerships generally
are treated as separate entities for purposes of federal tax audits, judicial review of
administrative adjustments by the Internal Revenue Service and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a
partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue
Code requires that one partner be designated as the Tax Matters Partner for these purposes. The
Tax Matters Partner will make some elections on our behalf and on behalf of Unitholders. In
addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax
deficiencies against Unitholders for items in our returns. The Tax Matters Partner may bind a
unitholder with less than a one percent profits interest in us to a settlement with the Internal
Revenue Service unless that unitholder elects, by filing a statement with the Internal Revenue
Service, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek
judicial review, by which all the Unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be
sought by any unitholder having at least one percent interest in profits or by any group of
Unitholders having in the aggregate at least a five percent interest in profits. However, only one
action for judicial review will go forward, and each unitholder with an interest in the outcome may
participate. A unitholder must file a statement with the Internal Revenue Service identifying the treatment of
any item on its federal income tax return that is not consistent with the treatment of the item on
our return. Intentional or negligent disregard of this consistency requirement may subject a
unitholder to substantial penalties. Nominee Reporting Persons who hold an interest trust units as a nominee for another person are required to furnish to us:  
    
    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. Brokers and financial institutions are required to furnish additional information, including
whether they are United States persons and specific information on the trust units they acquire,
hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000
per calendar year, is imposed by the Internal Revenue 89




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Code for failure to report that information to us. The nominee is required to supply the
beneficial owner of the trust units with the information furnished to us. Registration as a Tax Shelter The Internal Revenue Code requires that tax shelters be registered with the Secretary of the
Treasury. Although we may not be a tax shelter for such purposes, we have applied to register as
a tax shelter with the Secretary of the Treasury in light of the substantial penalties that might
be imposed if registration is required and not undertaken. 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. We will supply our tax shelter registration number to you when one has been assigned to us. A
unitholder who sells or otherwise transfers a trust unit in a later transaction must furnish the
registration number to the transferee. The penalty for failure of the transferor of a unit to
furnish the registration number to the transferee is $100 for each failure. A unitholder must
disclose our tax shelter registration number on its tax return on which any deduction, loss or
other benefit we generates is claimed or on which any of our income is included. A unitholder who
fails to disclose the tax shelter registration number on its return, without reasonable cause for
that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not
deductible for federal income tax purposes. Reportable Transactions Certain Treasury regulations require taxpayers to report specific information on Internal Revenue
Service Form 8886 if they participate in a reportable transaction. A transaction may be a
reportable transaction based upon any of several factors, including the existence of book-tax
differences common to financial transactions, one or more of which may be present with respect to
your investment in the trust units. Investors should consult their own tax advisor concerning the
application of any of these factors to an investment in the trust units. Congress is considering
legislative proposals that, if enacted, would impose significant penalties for failure to comply
with these disclosure requirements. Other Tax Considerations Each U.S. holder is urged to investigate the legal and tax consequences, under the laws of
pertinent jurisdictions, of acquiring and holding the trust units. Accordingly, each prospective
unitholder is urged to consult its tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all state, local and foreign, as well
as United States federal tax returns that may be required. 90




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F.
    
    Dividends and Paying Agents Not applicable  G.
    
    Statement by Experts Not applicable  H.
    
    Documents on Display Any statement in this annual report about any of our contracts or other documents is not
necessarily complete. If the contract or document is filed as an exhibit, the contract or document
is deemed to modify the description contained in this registration statement. You must review the
exhibits themselves for a complete description of the contract or document. We intend to provide our Unitholders with annual reports containing consolidated financial
statements audited by an independent chartered accounting firm and will make available to
Unitholders quarterly reports containing unaudited consolidated financial data for the first three
quarters of each year. We are subject to the information and reporting requirements of the
Securities and Exchange Act of 1934 and file periodic reports, proxy statements and other
information with the SEC. However, we are exempt from the rules under the Exchange Act prescribing
the furnishing and content of proxy statements, and our officers, directors and principal
stockholders are exempt from the reporting and short-swing profit recovery provisions contained in
Section 16 of the Exchange Act. Under the Exchange Act, we are not required to publish financial
statements as frequently or as promptly as U.S. companies. Such reports, proxy statements and
other information filed with the SEC may be inspected at the public reference facilities maintained
by the Commission at Judiciary Plaza, 450 5th Street N.W., Washington, D.C. 20549. Copies of these
materials may be obtained at prescribed rates from the Commission at that address. The reports,
proxy statements and other information can also be inspected on the Commissions Web site at
www.sec.gov If you are a unitholder, you may request a copy of these filings at no cost by contacting us at: Enterra Energy Trust
Suite 2600, 500  4th Avenue S.W.
Calgary, Alberta, Canada
T2P 2V6
(403) 213-2502  I.
    
    Subsidiary Information Not applicable 91




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ITEM 11.
    
    Qualitative and Quantitative Disclosures about Market Risk
 We are exposed to all of the normal risks inherent within the oil and gas sector, including
commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We manage
our operations in a manner intended to minimize our exposure, as described in notes 12 and 13 to
the consolidated financial statements. Credit Risk
Credit risk is the risk of loss resulting from non-performance of contractual obligations by a
customer or joint venture partner. A substantial portion of our accounts receivable are with
customers in the energy industry and are subject to normal industry credit risk. We assess the
financial strength of our customers and joint venture partners through regular credit reviews in
order to minimize the risk of non-payment. Foreign Exchange Risk
We are exposed to market risk from changes in the exchange rate between U.S. and Canadian dollars.
The price we receive for oil and natural gas production is based on a benchmark expressed in U.S.
dollars, which is the standard for the oil and natural gas industry worldwide. Our monthly
distributions are also based on a value expressed in U.S. dollars. However, we pay our operating
expenses, drilling expenses and general overhead expenses in Canadian dollars. Changes to the
exchange rate between U.S. and Canadian dollars can adversely affect us. When the value of the
U.S. dollar increases, we receive higher revenue and when the value of the U.S. dollar declines, we
receive lower revenue on the same amount of production sold at the same prices. A change of $0.01
in the U.S. to CDN dollar would impact Enterras earnings by approximately $500,000 and our cash
flow by $400,000. Commodity Price Risk
Our financial condition, results of operations and capital resources are highly dependent upon the
prevailing market prices of oil and natural gas. These commodity prices are subject to wide
fluctuations and market uncertainties due to a variety of factors that are beyond our control.
Factors influencing oil and natural gas prices include the level of global demand for crude oil,
the foreign supply of oil and natural gas, the establishment of and compliance with production
quotas by oil exporting countries, weather conditions which determine the demand for natural gas,
the price and availability of alternative fuels and overall economic conditions. It is impossible
to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in
oil and natural gas prices may adversely affect our financial condition and results of operations,
and may also reduce the amount of oil and natural gas reserves that we can produce economically.
Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations,
can have an adverse affect on our ability to obtain capital for our development activities.
Similarly, any improvements in oil and natural gas prices can have a favorable impact on our
financial condition, results of operations and capital resources. If the WTI oil price were to
change by US$1.00 per bbl, the impact on our earnings would be approximately $1,300,000 and the
impact on our cash flow would be approximately $2,000,000. If natural gas prices were to change by
US$0.50 per mcf, the impact on our earnings would be approximately $800,000 and the impact on our
cash flow would be approximately $1,200,000. We periodically use hedges with respect to a portion of our oil and natural gas production to
mitigate our exposure to price changes. While the use of these derivative arrangements limits the
downside risk of price declines, such use may also limit any benefits which may be derived from
price increases. Interest Rate Risk
Interest rate risk exists principally with respect to our indebtedness that bears interest at
floating rates. At December 31, 2004, we had $43.9 million of indebtedness bearing interest at
floating rates. If interest rate were to change by one full percentage point, the net impact on
our earnings would be approximately $300,000 and the net impact on our cash flow would be
approximately $400,000. Summarized below are our sensitivities to various risks, based on its 2004 operations: Sensitivities
    
    Estimated 2005 impact on:Net Earnings
    
    
    Cash FlowCrude oil  US$1.00/bbl change in WTI
    
    $
    1,300,000
    
    
    $
    2,000,000
 92




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Sensitivities
    
    Estimated 2005 impact on:Net Earnings
    
    
    Cash FlowNatural 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
 Not applicable 93




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Part II 
 ITEM 13.
    
    Defaults, Dividends Arrearages and Delinquencies
 None 
 ITEM 14.
    
    Material Modifications to the Rights of Security Holders and Use of Proceeds
 Not applicable 
 ITEM 15.
    
    Controls and Procedures
 (a) Disclosure controls and procedures. Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our
disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of
the end of the period covered by this report (the Evaluation Date), have concluded that, as of
the Evaluation Date, our disclosure controls and procedures were adequate and effective to ensure
that material information relating us and our consolidated subsidiaries would be made known to them
by others within those entities. (b) Managements annual report on internal control over financial reporting. Not applicable (c) Attestation report of the registered public accounting firm. Not applicable (d) Changes in internal controls. There were no significant changes in our internal controls or in other factors that could
significantly affect our disclosure controls and procedures subsequent to the Evaluation Date, nor
were there any significant deficiencies or material weaknesses in such disclosure controls and
procedures requiring corrective actions. As a result, no corrective actions were taken. With the
addition of new executive officers and senior staff, and with the ongoing growth of the Trusts
business, the internal control systems will continue to evolve. 94




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ITEM 16.
    
    [Reserved]ITEM 16A.
    
    Audit Committee Financial Expert
 The chairman of our audit committee, William E. Sliney, is independent in accordance with
applicable Nasdaq listing standards and the rules and regulations of the SEC and possesses the
attributes required of an audit committee financial expert as defined by ITEM 16A(b) of Form 20-F. ITEM 16B.
    
    Code of Ethics
 We have adopted a Code of Ethics which applies to all directors, officers, employees and
consultants. Our code of ethics is posted on our website at www.enterraenergy.com. ITEM 16C.
    
    Principal Accountant Fees and Services
 Audit Fees Our principal accountants, KPMG LLP, audited our annual financial statements for the 2004 fiscal
year. Deloitte & Touche LLP audited our annual financial statements for 2003 fiscal year. The
audit fees for 2004 were $292,986 (2003  $248,050). Audit fees are fees billed for the audit of
our annual consolidated financial statements and statutory and regulatory filings. Audit-Related Fees Our principal accountants billed audit-related fees for 2004 of $21,130 (2003  nil). These fees
were for the reviews of our interim financial statements. Tax Fees Our principal accountants billed tax fees for 2004 of $12,500 (2003  $22,000). These fees were
for the reviews of our tax statements regarding our distributions. All Other Fees Our principal accountants billed other fees for 2004 of $nil (2003  nil). These fees were for the
reviews of our financing and acquisition related filings. Pre-Approval Policies and Procedures The audit committee pre-approves all audit, audit-related services, tax services and other services
provided by our principal accountants. Any services provided by our principal accountants that are
not specifically included within the scope of the audit must be pre-approved by the audit committee
in advance of any engagement. Under the Sarbanes-Oxley Act of 2002, audit committees are permitted
to approve certain fees for audit-related services, tax services and other services pursuant to a
de minimus exception prior to the completion of an audit engagement. ITEM 16D.
    
    Exemptions from the Listing Standards for Audit Committees
 Not applicable. ITEM 16E.
    
    Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 Not applicable. 95




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PART III 
 ITEM 17.
    
    Financial Statements
 We have responded to Item 18 in lieu of responding to this item. 
 ITEM 18.
    
    Financial Statements
 The Consolidated Financial Statements of Enterra Energy Trust are attached as follows: Audited Annual Financial Statements: 
 96




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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 3779041Canada 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.
 
 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). 97




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Auditors Report to the Unitholders REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Unitholders of Enterra Energy Trust We have audited the accompanying consolidated balance sheet of Enterra Energy Trust as of
December 31, 2004 and the consolidated statements of earnings and accumulated earnings and cash
flows for the year then ended. These consolidated financial statements are the responsibility of
the Trusts management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted accounting standards and the
standards of the Public Company Accounting Oversight Board (United States). These standards
require that we plan and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that our audit
provides a reasonable basis for our audit opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of the Trust as of December 31, 2004 and the results of
its operations and its cash flows for year then ended in accordance with Canadian generally
accepted accounting principles. The consolidated financial statements as at December 31, 2003 and for each of the two years ended
December 31, 2003, prior to the adjustments for the change in the Trusts accounting policy for
asset retirement obligations as described in note 3(c) to the consolidated financial statements,
were audited by another firm of chartered accountants who expressed an opinion without reservation
on those statements in their audit report dated March 5, 2004. We have audited the adjustments to
the financial statements as at December 31, 2003 and for each of the two years ended December 31,
2003 as described in note 3(c) to the consolidated financial statements and in our opinion, such
adjustments, in all material aspects, are appropriate and have been properly applied. Canadian generally accepted accounting principles vary in certain significant respects from
accounting principles generally accepted in the United States of America. Information relating to
the nature and effect of such differences is presented in notes 17 and 18 to the consolidated
financial statements. (Signed) KPMG LLP
Chartered Accountants
Calgary Canada
March 31, 2005, except for notes 16(d), 16(e), 16(f), 17
and 18 which are as of June 30, 2005 Comments by Auditor for US Readers on Canada-US Reporting Differences In the United States, reporting standards for auditors require the addition of an explanatory
paragraph (following the opinion paragraph) when there is a change in accounting principle that has
a material effect on the comparability of the Trusts financial statements, such as the changes
described in note 3 to the Trusts consolidated financial statements as at and for the year ended
December 31, 2004. Our report to the unitholders dated
March 31, 2005, except for notes 16(d), 16(e), 16(f), 17
and 18 which are as of June 30, 2005, is expressed in accordance with Canadian reporting standards
which do not require a reference to such changes in accounting principles in the auditors report
when the changes are properly accounted for and adequately disclosed in the financial statements. (Signed) KPMG LLP
Chartered Accountants
Calgary Canada
June 30, 2005




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REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS To the Board of Trustees and the Unitholders of Enterra Energy Trust: We have audited the consolidated balance sheet of Enterra Energy Trust (formerly Enterra Energy
Corp.) as at December 31, 2003 and the consolidated statements of earnings and accumulated earnings
and cash flows for each of the years in the two year period ended December 31, 2003 prior to the
adjustments for the change in the Trusts accounting policy for asset retirement obligations as
described in Note 3(c). These financial statements are the responsibility of the Trusts
management. Our responsibility is to express an opinion on these financial statements based on our
audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the
standards of the Public Company Accounting Oversight Board (United States). These standards
require that we plan and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion. In our opinion, these consolidated financial statements, prior to the adjustments for the change in
the Trusts accounting policy for asset retirement obligations as described in Note 3(c), present
fairly, in all material respects, the financial position of Enterra Energy Trust as at December 31,
2003 and the results of its operations and its cash flows for each of the years in the two year
period ended December 31, 2003 in accordance with Canadian generally accepted accounting
principles. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control
over financial reporting. Our audit included consideration of internal control over financial
reporting as basis for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the Trusts internal control
over financial reporting. Accordingly we express no such opinion. (signed) Deloitte & Touche LLP Deloitte & Touche LLP
Independent Registered Chartered Accountants
Calgary, Alberta, Canada
March 5, 2004 (except for Note 17(g) which is as of June 17, 2005) Comments by Independent Registered Chartered Accountants on Canada-United States of America
Reporting Differences The standards of the Public Company Accounting Oversight Board (United States) require the addition
of a explanatory paragraph (following the opinion paragraph) when there has been a restatement of
the financial statements as described in Note 17(g) to the consolidated financial statements. Our
report to the Board of Trustees and the Unitholders, dated March 5, 2004 (except for Note 17(g)
which is as of June 17, 2005), is expressed in accordance with Canadian reporting standards which
do not require a reference to such conditions and events in the auditors report when these are
adequately disclosed in the financial statements. (signed) Deloitte & Touche LLP Deloitte & Touche LLP
Independent Registered Chartered Accountants
Calgary, Alberta, Canada
March 5, 2004 (except for Note 17(g) which is as of June 17, 2005)




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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 note 3(c))AssetsCurrent assetsCash
    
    $
    4,779
    
    
    $
    66Accounts receivable
    
    
    15,613
    
    
    
    8,742Prepaid expenses and deposits
    
    
    518
    
    
    
    46220,910
    
    
    
    9,270Deposit on land purchase (notes 4 and 16)
    
    
    2,400
    
    
    
    2,015Property and equipment (note 6)
    
    
    146,910
    
    
    
    105,253Deferred financing charges
    
    
    90
    
    
    
    123Goodwill (note 5)
    
    
    29,991
    
    
    
    $
    200,301
    
    
    $
    116,661LiabilitiesCurrent 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 11)
    
    
    21,526
    
    
    
    13,936Capital lease (note 9)
    
    
    2,580
    
    
    
    3,386102,206
    
    
    
    69,032Unitholders EquityUnitholders capital (note 10)
    
    
    111,653
    
    
    
    32,838Exchangeable units (note 10)
    
    
    3,273
    
    
    
    3,457Contributed surplus (note 10)
    
    
    78
    
    
    
    Accumulated earnings
    
    
    27,903
    
    
    
    13,785Accumulated distributions
    
    
    (44,812
    )
    
    
    (2,451
    )98,095
    
    
    
    47,629Commitments, contingencies and guarantees (notes 13, 14 and 15)Subsequent events (note 16)$
    200,301
    
    
    $
    116,661
 Approved on behalf of the BoardReg Greenslade
    
    Bill SlineyDirector
    
    Director
 See accompanying notes to consolidated financial statements




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Enterra Energy Trust
Consolidated Statements of Earnings and Accumulated Earnings
Years Ended December 31,(Expressed in thousand Canadian Dollars) 2004
    
    
    2003
    
    
    2002restated see
    
    
    restated seenote 3(c)
    
    
    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
    
    
    35,438
    
    
    
    23,306
    
    
    
    9,449Financial derivative loss
    
    
    3,188
    
    
    
    
    
    
    
    Gain on redemption of preferred shares
    
    
    
    
    
    
    
    
    
    
    (3,111
    )Restructuring charges (note 1)
    
    
    
    
    
    
    5,756
    
    
    
    93,340
    
    
    
    64,877
    
    
    
    19,868Earnings before income taxes
    
    
    14,953
    
    
    
    7,220
    
    
    
    5,878Income taxes (reduction) (note 11)Current
    
    
    260
    
    
    
    134
    
    
    
    132Future
    
    
    (71
    )
    
    
    1,988
    
    
    
    865189
    
    
    
    2,122
    
    
    
    997Net earnings
    
    
    14,764
    
    
    
    5,098
    
    
    
    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
    )
    
    
    
    
    
    
    Accumulated earnings, end of year
    
    $
    27,903
    
    
    $
    13,785
    
    
    $
    8,933Earnings per unit (note 10)Basic
    
    $
    0.63
    
    
    $
    0.27
    
    
    $
    0.27Diluted
    
    $
    0.63
    
    
    $
    0.27
    
    
    $
    0.26
 See accompanying notes to consolidated financial statements




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Enterra Energy Trust
Consolidated Statements of Cash Flows
Years Ended December 31(Expressed in thousand Canadian Dollars) 2004
    
    
    2003
    
    
    2002(restated see
    
    
    (restated seenote 3(c))
    
    
    note 3(c))Cash provided by (used in):OperationsNet earnings
    
    $
    14,764
    
    
    $
    5,098
    
    
    $
    4,881Add non-cash items:Depletion, depreciation and accretion
    
    
    35,438
    
    
    
    23,306
    
    
    
    9,449Future income taxes
    
    
    (71
    )
    
    
    1,988
    
    
    
    865Amortization of deferred gain
    
    
    
    
    
    
    (238
    )
    
    
    (524
    )Amortization of deferred financing charges
    
    
    33
    
    
    
    262
    
    
    
    390Unit based compensation
    
    
    78
    
    
    
    
    
    
    
    Gain on redemption of preferred shares
    
    
    
    
    
    
    
    
    
    
    (3,111
    )Valuation of warrants
    
    
    
    
    
    
    282
    
    
    
    Expenditures on asset retirement obligations
    
    
    
    
    
    
    (5
    )
    
    
    (49
    )50,242
    
    
    
    30,693
    
    
    
    11,901Change 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
 During 2004, the Trust paid
$2,222,000 (2003 -  $1,749,000; 2002 - $1,236,000) of interest on long-term debt and bank
indebtedness and nil of capital taxes (2003 - $134,000; 2002 - $132,000). See accompanying notes to consolidated financial statements




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Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  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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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  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.




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  (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 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.




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Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  (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.(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.




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Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  (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.  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
    
    $
    




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  (c)
    
    Asset Retirement ObligationsEffective 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 asBalance Sheet as at
December 31, 2003
    
    previously 
reported
    
    
    Adjustments
    
    
    Balance as 
restatedProperty 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
 Balance asStatement of Earning for the year
ended
December 31, 2003
    
    previously 
reported
    
    
    Adjustments
    
    
    Balance as 
restatedDepletion, 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 asStatement of Earning for the year
ended December 31, 2002
    
    previously 
reported
    
    
    Adjustments
    
    
    Balance as 
restatedDepletion, 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)
    
    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.




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  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 $2,015,000.5.
    
    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 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
 The purchase price allocation is preliminary and subject to change. Results from operations of Rocky Mountain Energy Corp. subsequent to September 29, 2004 are
included in the Trusts consolidated financial statements. The value assigned to each Enterra Trust Unit of Cdn $17.98 was based on the weighted average
trading price on the NASDAQ National Market System immediately prior to and after the
measurement date.




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  6.
    
    Property and Equipment 2004Accumulateddepletion andCost
    
    
    depreciation
    
    
    NetPetroleum and natural gas
properties
    
    $
    221,551
    
    
    $
    75,967
    
    
    $
    145,584Office furniture and equipment
    
    
    2,158
    
    
    
    832
    
    
    
    1,326$
    223,709
    
    
    $
    76,799
    
    
    $
    146,910
 2003Accumulateddepletion andCost
    
    
    depreciation
    
    
    NetPetroleum and natural gas
properties
    
    $
    145,878
    
    
    $
    41,601
    
    
    $
    104,277Office furniture and equipment
    
    
    1,603
    
    
    
    627
    
    
    
    976$
    147,481
    
    
    $
    42,228
    
    
    $
    105,253
 During 2004, $869,000 of general and administrative expenses were capitalized and included in
the cost of the petroleum and natural gas properties (2003 -
$1,787,000, 2002 - $1,451,000). Included in petroleum and natural gas properties are assets acquired and pledged under capital
lease agreements with a cost base of $5,218,000 and net book value of $3,107,000 (2003 -
$5,218,000 and $4,268,000). At
December 31, 2004 costs of undeveloped land of $3,430,000 (2003 - $5,037,000) were excluded
from the calculation of depletion expense. The Trust completed a ceiling test calculation at December 31, 2004 to assess the recoverable
value of the petroleum and natural gas properties. The petroleum and natural gas prices are
based on the January 1, 2005 commodity price forecast of our independent reserve engineers.
These prices have been adjusted for commodity price differentials specific to the Trust. The
following table summarizes the benchmark prices used in the ceiling test calculation. 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
 A ceiling test write down as at December 31, 2004 was not required.




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Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  7.
    
    Asset Retirement ObligationsThe asset retirement obligations were estimated by management based on the Trusts working
interest in its wells and facilities, estimated costs to remediate, reclaim and abandon the
wells and facilities and the estimated timing of the costs to be incurred. At December 31, 2004,
the Trust estimated the asset retirement obligation to be $14,836,000 (2003  $2,188,000), based
on a total future liability of $25,354,000 (2003 - $4,220,000). These obligations will be
settled at the end of the useful lives of the underlying assets, which currently extend up to 20
years into the future. This amount has been calculated using an inflation rate of 2% and
discounted using a credit-adjusted risk-free interest rate of 8%.The following table reconciles the 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 TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  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.
    
    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
    
    
    
    8Balance at December 31, 2003
    
    
    18,955,960
    
    
    $
    32,838Adopt 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
    
    
    
    6,331Unit share issue costs
    
    
    
    
    
    
    (837
    )Balance at December 31, 2004
    
    
    25,426,800
    
    
    $
    111,653




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Enterra
Energy Trust
Notes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information) Pursuant to the Plan of Arrangement, 18,951,556 Trust Units and 2,000,000 Exchangeable Shares
were issued on November 25, 2003 at a two for one exchange ratio and upon cancellation of all
outstanding common shares of Enterra. The consideration attributed to the Trust Units and the
Exchangeable Shares was the relative proportion of the carrying value of the common shares of
Enterra prior to the exchange. The prior years number of shares issued in the share tables
above have been restated to reflect the two for one exchange ratio under the Plan of
Arrangement. Issued Exchangeable Shares Enterra
    
    
    RMAC
    
    
    TotalExchangeable
    
    
    Exchangeable
    
    
    ExchangeableShares
    
    
    Shares
    
    
    Shares
    
    
    AmountIssued pursuant to
Plan of Arrangement
    
    
    2,000,000
    
    
    
    
    
    
    
    2,000,000
    
    
    $
    3,465Exchanged for trust units
    
    
    (4,404
    )
    
    
    
    
    
    
    (4,404
    )
    
    
    (8
    )Balance at December 31, 2003
    
    
    1,995,596
    
    
    
    
    
    
    
    1,995,596
    
    
    
    3,457Issued 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
    )Balance at December 31, 2004
    
    
    410,770
    
    
    
    142,444
    
    
    
    553,214
    
    
    $
    3,273
 The exchangeable shares are convertible at any time into Trust Units (at the option of the
holder) based on the exchange ratio. The exchange ratio is increased monthly based on the cash
distribution paid on the Trust Units divided by the ten day weighted average unit price
preceding the distribution payment date. Cash distributions are not paid on the exchangeable
shares. On the third anniversary of the issuance of the Exchangeable Shares, subject to
extension of such date by the Board of Directors of the Trust, or at the Trusts option when the
aggregate number of issued and outstanding Exchangeable Shares is less than 1,000,000, the
Exchangeable Shares will be redeemed for Trust Units at a redemption price per exchangeable
share equal to the value of that number of Trust Units equal to the exchange ratio as at that
Redemption Date. The exchangeable shares of the Company are not listed for trading on an
exchange. During 2004, a total of 1,784,264 exchangeable shares were converted into 1,824,864 trust units
at an exchange ratio prevailing at the time of conversion (2003  4,404 exchangeable shares were
converted into 4,404 Trust Units). At December 31, 2004, the exchange ratio for Enterra Energy Corp. exchangeable shares was
1.10534 and the exchange ratio for Rocky Mountain Acquisition Corp. was 1.02466. 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




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##### Table of Contents



Enterra
Energy Trust
Notes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information) Trust unit options Enterra 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
    
    
    
    
    
    $
    
 Estimated fair value of stock options The 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




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##### Table of Contents



Enterra Energy Trust
Notes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information) Pro forma net earnings  fair value based method of accounting for options In 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
    
    $
    14,764
    
    
    $
    5,098
    
    
    $
    4,881Deduct:Stock-based employee compensation expense
determined under fair value based method for all
awards
    
    
    
    
    
    
    (631
    )
    
    
    (47
    )Pro forma net earnings
    
    $
    14,764
    
    
    $
    4,467
    
    
    $
    4,834Pro forma net earnings per unit  basic and diluted
    
    $
    0.63
    
    
    $
    0.24
    
    
    $
    0.26
 Reconciliation of Earnings per Unit Calculations For the year ended December 31, 2004WeightedAverageUnitsNet Earnings
    
    
    Outstanding

    
    
    Per UnitBasic
    
    $
    14,764
    
    
    
    23,327,728
    
    
    $
    0.63Options assumed exercised
    
    
    
    
    
    
    950,000Units assumed purchased
    
    
    
    
    
    
    (716,943
    )Diluted
    
    $
    14,764
    
    
    
    23,560,785
    
    
    $
    0.63
 For the year ended December 31, 2003 the weighted average number of units outstanding was
18,953,968. There were no options outstanding as at December 31, 2003 and therefore no
dilution to earnings per unit for 2003 For the year ended December 31, 2002WeightedAverageNet
    
    
    UnitsEarnings
    
    
    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




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##### Table of Contents



Enterra Energy Trust
Notes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information) 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. Trust Unit Savings Plan In 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.  11.
    
    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
    
    $
    14,953
    
    
    $
    7,220
    
    
    $
    5,878Combined federal and provincial income tax rate
    
    
    38.87
    %
    
    
    40.75
    %
    
    
    42.12
    %Computed income tax provision
    
    
    5,812
    
    
    
    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$
    189
    
    
    $
    2,122
    
    
    $
    997




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##### Table of Contents



Enterra Energy Trust
Notes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information) 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
    
    
    38,820
    
    
    
    15,095Net future income tax liability
    
    $
    21,526
    
    
    $
    13,936
 Non-capital loss carry-forwards expire from time to time to 2011. 12. Financial instruments The 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. 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.




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  (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. 13. Commitments The 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
 During
2004 total rental expense was $81,339 (2003 - $ 299,000; 2002 - $241,000). 14. Contingencies On 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. 15. Guarantees The 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. 16. Subsequent events  (a)
    
    On January 26, 2005 the Trust closed an acquisition of petroleum and natural gas
properties for cash consideration of $12,303,000. At December 23, 2004, the Trust had made
a refundable deposit on the property purchased in the amount of $2,400,000.(b)
    
    The Trust has a bonus plan that is subject to unitholder approval at the 2005 annual
general meeting. If the plan is approved by the Unitholders, officers and former officers,
directors, employees and consultants of the Trust will be paid bonuses aggregating $1.6
million. As payment of this amount is subject to unitholder approval it has not been
accrued in the 2004 financial statements.(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 $9,500,000.(d)
    
    On February 22, 2005 the Trust and Enterra Energy Corp. entered into a Letter of Intent
with Rocky Mountain




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  Gas, Inc. whereby the companies would merge under Wyoming law and
Enterra would acquire all the outstanding shares of Rocky Mountain
Gas, Inc. Consideration consisted of US $14 million by the
issuance of exchangeable shares (exchangeable on a one-to-one basis
into trust units), US $5.5 million by the issuance of trust
units and US$0.5 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 will receive 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. The acquisition is anticipated to be completed by way of a plan of
arrangement pursuant to which shareholders of High Point will receive
0.105 of a trust unit for each share of High Point. The Trust anticipates issuing
8.9 million trust units in conjunction with the acquisition. The acquisition is
subject to regulatory and High Point shareholder approval.  17.
    
    Differences between Generally Accepted Accounting Principles in Canada and the United States
of America The 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




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  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 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.




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##### Table of Contents



Enterra
Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  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
    
    $
    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.(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:




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##### Table of Contents



Enterra Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)   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.(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.




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##### Table of Contents



Enterra
Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information) As at December 31, 2004, Unitholders Capital was reduced by $111.1 million and Exchangeable
units was reduced by $3.3 million (2003 - $32.8 million and $3.5 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, Exchangeable units decreased
by $3.5 million, Mezzanine Equity increased by $245.8 million and accumulated earnings
decreased by $209.4 million.  (h)
    
    Balance sheets The 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)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)
    
    
    146,910
    
    
    
    117,940
    
    
    
    105,253
    
    
    
    84,288Goodwill
    
    
    29,991
    
    
    
    29,991
    
    
    
    
    
    
    
    Deferred financing charges
    
    
    90
    
    
    
    90
    
    
    
    123
    
    
    
    123$
    200,301
    
    
    $
    171,331
    
    
    $
    116,661
    
    
    $
    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)
    
    
    21,526
    
    
    
    10,614
    
    
    
    13,936
    
    
    
    5,644Asset retirement obligation (f)
    
    
    14,836
    
    
    
    14,836
    
    
    
    2,188
    
    
    
    2,188102,206
    
    
    
    91,294
    
    
    
    69,032
    
    
    
    61,698Mezzanine equity (g)
    
    
    
    
    
    
    529,764
    
    
    
    
    
    
    
    261,810Unitholders equity:Unitholders equity (g)
    
    
    111,653
    
    
    
    
    
    
    
    32,838Exchangeable units (g)
    
    
    3,273
    
    
    
    
    
    
    
    3,457
    
    
    
    Contributed surplus
    
    
    78
    
    
    
    78
    
    
    
    
    
    
    
    Accumulated earnings (deficit)
    
    
    27,903
    
    
    
    (404,993
    )
    
    
    13,785
    
    
    
    (225,361
    )Accumulated distributions
    
    
    (44,812
    )
    
    
    (44,812
    )
    
    
    (2,451
    )
    
    
    (2,451
    )98,095
    
    
    
    80,037
    
    
    
    47,629
    
    
    
    33,998$
    200,301
    
    
    $
    171,331
    
    
    $
    116,661
    
    
    $
    95,696




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##### Table of Contents



Enterra
Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  (i)
    
    Income statements The 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)Net earnings under Canadian GAAP
    
    $
    14,764
    
    
    $
    5,098
    
    
    $
    4,881Adjustments:Hedging gain (b)
    
    
    
    
    
    
    (238
    )
    
    
    (524
    )Related income taxes
    
    
    
    
    
    
    97
    
    
    
    221Depletion and accretions (a)
    
    
    (8,005
    )
    
    
    5,676
    
    
    
    3,583Related income taxes
    
    
    3,011
    
    
    
    (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
    
    
    
    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
    
    $
    (7.62
    )
    
    $
    (11.55
    )
    
    $
    0.36




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##### Table of Contents



Enterra
Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  (j)
    
    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
  (k)
    
    Cash flowsUnder Canadian GAAP, reporting entities are permitted to present a sub-total prior to
changes in non-cash working capital within operating activities. This information is
perceived to be useful information for various users of the financial statements and is
commonly presented by Canadian public companies. Under U.S. GAAP, this sub-total is not
permitted to be shown and would be removed in the statements of cash flows for all periods
presented.(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
    
    $
    11,166
    
    
    $
    12,583
    
    
    $
    4,760
    
    
    $
    6,824Cumulative effect
of accounting
changes
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    (1,281
    )Net earnings (loss)
    
    $
    11,166
    
    
    $
    (177,387
    )
    
    $
    4,760
    
    
    $
    (247,098
    )Earnings (loss) per
trust unit  basic
    
    $
    0.45
    
    
    $
    (7.08
    )
    
    $
    0.22
    
    
    $
    (11.63
    )Earnings (loss) per
trust unit 
diluted
    
    $
    0.44
    
    
    $
    (7.02
    )
    
    $
    0.22
    
    
    $
    (11.63
    )




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##### Table of Contents



Enterra
Energy TrustNotes to 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
(Expressed in Canadian Dollars)
(Tabular amounts are stated in thousands of dollars except unit and per unit information)  18.
    
    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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##### Table of Contents



Enterra
Energy Trust Supplemental Disclosure
About Oil and Gas Producing Activities (Unaudited)
 The following oil and gas information is provided in accordance with the U.S. Financial Accounting
Standards Board Statement No. 69 Disclosure About Oil and Gas Producing Activities. The Trust
follows the full cost method of accounting.  (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 Information Estimated 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
    
    
    
    5,234Proved 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
    
    
    
    3,952Proved 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




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##### Table of Contents



Enterra
Energy Trust Supplemental Disclosure
About Oil and Gas Producing Activities (Unaudited)
  (c)
    
    Standardized Measure of Discounted Future Net Cash Flows and Changes Therein The 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.




---



##### Table of Contents



Enterra
Energy Trust Supplemental Disclosure
About Oil and Gas Producing Activities (Unaudited)
 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. 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




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##### Table of Contents



SIGNATURES The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and
that it has duly caused and authorized the undersigned to sign this annual report on its behalf. Date: July 14, 2005 Enterra Energy Trust /s/ E. Keith ConradE. Keith Conrad
President and Chief Executive Officer
(Duly Authorized Signing Officer) 98




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##### Table of Contents



EXHIBIT INDEX 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 3779041Canada 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.
 
 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).