ENTERRA ENERGY TRUST

INITIAL ANNUAL INFORMATION FORM


for the year ended December 31, 2003

May 19, 2004

TABLE OF CONTENTS

NOTE REGARDING FORWARD LOOKING STATEMENTS

Certain statements contained in this annual information form constitute forward looking statements.  The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward looking statements.  These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward looking statements.  Management believes the expectations reflected in those forward looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward looking statements included herein should not be unduly relied upon.  These statements speak only as of the date hereof.

In particular, this annual information form contains forward looking statements pertaining to the following:

·

oil and natural gas production levels;

·

capital expenditure programs;

·

the quantity of the oil and natural gas reserves;

·

projections of commodity prices and costs;

·

supply and demand for oil and natural gas;

·

expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; and

·

treatment under governmental regulatory regimes.

The actual results could differ materially from those anticipated in these forward looking statements as a result of the risk factors set forth below and elsewhere in this annual information from:

·

volatility in market prices for oil and natural gas;

·

liabilities inherent in oil and natural gas operations;

·

uncertainties associated with estimating oil and natural gas reserves;

·

competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

·

incorrect assessments of the value of acquisitions;

·

geological, technical, drilling and processing problems;

·

fluctuations in foreign exchange or interest rates and stock market volatility;

·

failure to realize the anticipated benefits of acquisitions; and

·

the other factors discussed under "Risk Factors".

These factors should not be construed as exhaustive.  We do not undertake any obligation to publicly update or revise any forward looking statements.

GLOSSARY OF TERMS

The following are defined terms used in this Annual Information Form:

"board of directors" or "Enterra board" means the board of directors of Enterra;

"CT Note" means the unsecured promissory note issued by EEC Trust to the Trust pursuant to the Arrangement;

"EEC Trust" means Enterra Energy Commercial Trust, an unincorporated trust governed by the laws of Alberta and a wholly-owned subsidiary of the Trust;

"EEC Trust Units" means trust units of EEC Trust;

"Enterra Debt" means the Series A Notes and any other indebtedness of Enterra to the Trust from time to time.  

"Exchangeco" means Enterra Exchangeco Ltd., a corporation incorporated pursuant to the laws of Alberta and a wholly-owned subsidiary of EEC Trust;

"McDaniel" means McDaniel & Associates Ltd., independent petroleum engineering consultants of Calgary, Alberta;

"McDaniel Report" means the independent engineering evaluation of certain oil, NGL and natural gas interests of the Trust prepared by McDaniel dated February 27, 2004 and effective December 31, 2003;

"Non-Resident" means (a) a Person who is not a resident of Canada for the purposes of the Tax Act; or (b) a partnership that is not a Canadian partnership for the purposes of the Tax Act;

"Note Indenture" means the indenture between Enterra and the Note Trustee governing the Series A Notes;

"Note Trustee" means Olympia Trust Company or any successor thereto, in its capacity as the trustee for the holders of Series A Notes;

"Partnerco" means Enterra Energy Partner Corp., a corporation incorporated pursuant to the ABCA and a wholly-owned subsidiary of Enterra;

"Partnership" means the Enterra Production Partnership, a partnership organized pursuant to the laws of Alberta, the partners of which are Enterra (99.99%) and Partnerco (0.01%);

"Series A Notes" means interest-bearing subordinated promissory notes issued by Enterra  pursuant to the Arrangement and currently held by the Trust;

"Special Resolution" means a resolution proposed to be passed as a special resolution at a meeting of holders of Trust Units and holders of Special Voting Rights (including an adjourned meeting) duly convened for the purpose and passed by the affirmative votes of the holders of not less than 66 2/3% of the Trust Units and Special Voting Rights represented at the meeting and voted on a poll upon such resolution;

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1. (5th Supp), as amended, including the regulations promulgated thereunder;

"Trust Unit" or "Unit" means a unit of the Trust issued by the Trust;

"Trustee" means Olympia Trust Company, the initial trustee of the Trust, or such other trustee from time to time of the Trust;

"Unitholders" means holders from time to time of the Trust Units;

"U.S. Person" means a U.S. person as defined in Rule 902(k) under Regulation S, including, but not limited to, any natural person resident in the United States;

"U.S. Unitholder" means any Unitholder who is either in the United States or a U.S. Person;

"Voting and Exchange Trust Agreement" means the voting and exchange trust agreement entered into on November 25, 2003 between the Trust, Enterra Acquisition Ltd. and the Voting and Exchange Agreement Trustee; and

"Voting and Exchange Trust Agreement Trustee" means Olympia Trust Company, the initial trustee under the Voting and Exchange Trust Agreement, or such other trustee from time to time appointed thereunder.

"1933 Act" means the United States Securities Act of 1933, as amended;

"1934 Act" means the United States Securities Exchange Act of 1934, as amended; and

Conventions

Unless otherwise indicated, references herein to "$" or "dollars" are to Canadian dollars.  All financial information herein has been presented in Canadian dollars in accordance with generally accepted accounting principles in Canada.

Abbreviations

	Oil and Natural Gas Liquids		Natural Gas
bbl	Barrel	mcf	thousand cubic feet
bbls	Barrels	mmcf	million cubic feet
mbbls	thousand barrels	bcf	billion cubic feet
bbls/d	barrels per day	mcf/d	thousand cubic feet per day
NGLs	natural gas liquids	mmcf/d	million cubic feet per day
GJ	Gigajoule	MMBTU	million British Thermal Units
GJ/d	gigajoule per day

Other

AECO-C	Intra-Alberta Nova Inventory Transfer Price (NIT net price)
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale.  Liquid petroleum with a specified gravity of 28 °API or higher is generally referred to as light crude oil
ARTC	Alberta Royalty Tax Credit
BOE	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 (unless otherwise stated) mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
BOE/D	barrel of oil equivalent per day
M3	cubic metres
MBOE	1,000 barrels of oil equivalent
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
MW/h	Megawatts per hour

Conversion

The following table sets forth certain standard conversions from Standard Imperial Units to the International System of Units (or metric units).

To Convert From	To	Multiply By
mcf	Cubic metres	28.174
Cubic metres	Cubic feet	35.494
bbls	Cubic metres	0.159
Cubic metres	Bbls oil	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.47

CURRENCY OF INFORMATION

The information set out in this renewal annual information form is stated as at December 31, 2003 unless otherwise indicated.  Capitalized terms used but not defined in the text are defined in the Glossary.

ORGANIZATIONAL STRUCTURE

Enterra Energy 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 an indenture (the "Trust Indenture") dated as of October 24, 2003, between Enterra Energy Corp. and Olympia Trust Company. Our head and principal office is located at 2600, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6.

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") on November 25, 2003 (the "Arrangement"), 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 wholly-owned subsidiary of the Trust. Old Enterra was subsequently amalgamated with Enterra Acquisition Corp., Big Horn Resources Ltd. and Enterra Sask. Ltd. to form Enterra Energy Corp. ("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.  See "Description of the Business of the Trust – General".

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.

The Partnership

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 all of our producing crude oil and natural gas properties from which the Trust ultimately derives its cash flow. The partners of the Partnership are Enterra (as to 99.99%) and Partnerco (as to 0.01%).

EEC Trust

EEC Trust is an unincorporated commercial trust governed by the laws of the Province of Alberta. The Trust holds all of the issued and outstanding trust units of EEC Trust.

Our Organizational Structure

The following diagram describes the intercorporate relationships among the Trust and its subsidiaries as well as the flow of cash from the oil and gas properties held by such subsidiaries to the Trust and, ultimately, from the Trust to the Unitholders.  Reference should be made to the appropriate sections of this Annual Information Form for a complete description of our structure.

GENERAL DEVELOPMENT OF THE BUSINESS OF THE TRUST

History

History of Old Enterra Prior to the Arrangement

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 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 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 to 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.

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 fort 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 Act on 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. 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.

On October 8, 2002, Old Enterra purchased 3,300 acres of land in one of its core areas for $2.5 million.

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".

The Arrangement

The Arrangement received the approval of 99.37% of the votes cast by shareholders at a special meeting held on November 24, 2003. The Arrangement also received the approval of the Court of Queen’s Bench of Alberta on November 24, 2003 and became effective on November 25, 2003.

Under the terms of the Arrangement, Old Enterra was reorganized into the Trust and Enterra, which resulted in all of the assets of Old Enterra being transferred to the Partnership.  Enterra manages the operations of the Partnership.

Pursuant to the Arrangement, the outstanding common shares of Old Enterra were exchanged by the holders thereof for an aggregate of 18,951,556 Trust Units.  Also, as part of the Arrangement, Enterra issued an aggregate of 2,000,000 Exchangeable Shares to former holders of Old Enterra common shares in accordance with elections made by such holders under the Arrangement.  Each Exchangeable Share is exchangeable into Trust Units at any time.  See "Additional Information Respecting Enterra – Description of Share Capital – Exchangeable Shares".  

Events Occurring Following the Completion of the Arrangement

The Trust Units of Enterra Energy Trust commenced trading on the Nasdaq under the symbol "EENC" and the Toronto Stock Exchange ("TSX") under the symbol "ENT.UN" on Friday November 28, 2003.

On January 16, 2004 the Trust entered into a financing agreement whereby it will issue 1,650,000 Trust Units at a price of US$10.00 per unit for gross proceeds of US$16,500,000. Payment will be received pending registration of the Trust Units. The funds received from this financing will applied to pay down debt and for general corporate purposes.  

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 applied to repay debt.

Significant Acquisitions

The Trust did not make any significant acquisitions or dispositions during the year ended December 31, 2003 other than the reorganization of assets occurring pursuant to the Arrangement.

DESCRIPTION OF THE BUSINESS OF THE TRUST

General

The principal undertaking of the Trust is to issue Trust Units and to acquire and hold debt instruments, securities, royalties an other interests.  The direct and indirect subsidiaries of the Trust carry on the business of acquiring and holding interests in petroleum and natural gas properties and assets related thereto.  Cash flow from the properties is flowed from Enterra to the Trust primarily through (i) payments of interest and principal in respect of the Enterra Debt, and (ii) dividends declared on the common shares of Enterra and/or redemptions of preferred shares of Enterra, which amounts are transferred from EEC Trust to the Trust as payments of interest or principal on the CT Note.  Cash flow received by the Trust is distributed to the Unitholders on a monthly basis.  See "Distributions".  

Under the terms of the Trust Indenture, the Trust was created for the purposes of:

·

acquiring the Series A Notes and CT Note pursuant to the Arrangement;

·

investing in the CT Units;

·

acquiring, holding, transferring and disposing of, investing in and otherwise dealing with assets, securities (whether debt or equity) and other interests (including royalty interests) or properties of whatever nature or kind of, or issued by, Enterra, EEC Trust or any other entity in which the Trust owns, directly or indirectly, 50% or more of the outstanding voting securities, including, without limitation, bodies corporate, partnerships or trusts;

·

borrowing funds or otherwise obtaining at any time and from time to time or otherwise incurring any indebtedness for any of the purposes set forth in the Trust Indenture;

·

disposing of any part of the property of the Trust;

·

temporarily holding cash and other short term investments in connection with and for the purposes of the Trust's activities, including paying administration and trust expenses, paying any amounts required in connection with the redemption of Trust Units and making distributions to Unitholders;

·

issuing Trust Units, instalment receipts, and other securities (whether debt or equity) of the Trust (including securities convertible into or exchangeable for Trust Units or other securities of the Trust, or warrants, options or other rights to acquire Trust Units or other securities of the Trust), for the purposes of:

(i)

obtaining funds to conduct the activities described above, including raising funds for further acquisitions;

(ii)

repaying of any indebtedness or borrowings of the Trust or any affiliate thereof, including the Series A Notes and the CT Note;

(iii)

establishing and implementing Unitholder rights plans, distribution reinvestment plans, Trust Unit purchase plans, and incentive option and other compensation plans of the Trust, if any;

(iv)

satisfying obligations to deliver securities of the Trust, including Trust Units, pursuant to the terms of securities convertible into or exchangeable for such securities of the Trust, whether or not such convertible or exchangeable securities have been issued by the Trust; and

(v)

making non-cash distributions to Unitholders as contemplated by the Trust Indenture including distributions pursuant to distribution reinvestment plans, if any, established by the Trust;

·

guaranteeing the obligations of its affiliates pursuant to any debt for borrowed money or any other obligation incurred by such entity in good faith for the purpose of carrying on its business, and pledging securities and other property owned by the Trust as security for any obligations of the Trust, including obligations under any guarantee;

·

repurchasing or redeeming Trust Units or other securities of the Trust, subject to the provisions of the Trust Indenture and applicable law; and

·

engaging in all activities incidental or ancillary to any of the foregoing.

Strategy

Our business strategy is to grow our reserves and distributions by acquiring properties which provide additional production and potential for development upside. We are focused on per Unit growth. We will finance acquisitions with both debt and equity, the optimal mix being one which 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.

We intend to distribute approximately 80% of our available cash flow to our Unitholders. See "Distributions".  Future growth will be financed with a combination of additional Trust Units and bank debt. The level of distribution to Unitholders will fluctuate depending on a number of factors, including future commodity prices and operating results. The portion of cash not distributed to Unitholders will be used for maintenance of capital or reduction of bank debt.  

Risk Management and Marketing

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 to such risks.

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 $193,000 and its cash flow by approximately $394,000.

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 Enterra’s earnings would be approximately $869,000 and the impact on Enterra’s cash flow would be approximately $1,774,000. If natural gas prices were to change by US$0.50 per mcf, the impact on Enterra’s earnings would be approximately $873,000 and the impact on Enterra’s cash flow would be approximately $1,781,000.

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.

Enterra had several costless collars and forward contracts in place during the year in order to minimize the volatility in crude oil pricing. Below is a summary of our hedging operations:

Hedging Summary
Description	Quantity	Pricing	Gain (loss) on Contract
Oil Contract Oct. 1, 2000 To Sept 30, 2003 (Sold In January 2001)	350/650 bbls of oil/day	US$24.15 to US$27.19	$1,680,000
Zero collar from November 1, 2001 to April 30, 2002	500 bbls of oil/day	Floor US$20 – Ceiling US$24	($41,878)
Zero collar from October 1, 2002 to March 31, 2003	500 bbls of oil/day	Floor US$22 – Ceiling US$28	($65,440)
Natural gas contract from Nov 1, 2002 to March 31, 2003	1,500 mcf of gas/day	C$4.60 per mcf	($486,225)
Natural gas contract from Nov 1, 2002 to March 31, 2003	1,500 mcf of gas/day	C$4.45 per mcf	($520,200)
Oil contracts from April 1, 2003 to December 31, 2003	2,000 bbls of oil/day	From US$29.50 to US$29.80	($246,937)
Contracts Entered Into Subsequent To December 31, 2003:
Oil contracts from January 1, 2004 to June 30, 2004	500 bbls of oil/day	US$26.75 per barrel
Oil contracts from January 1, 2004 to June 30, 2004	500 bbls of oil/day	US$26.68 per barrel
Oil contracts from January 1, 2004 to June 30, 2004	1,000 bbls of oil/day	C$38.50 per barrel
Oil contracts from July 1, 2004 to December 31, 2004	500 bbls of oil/day	C$40.50 per barrel

Interest Rate Risk

Interest rate risk exists principally with respect to our indebtedness that bears interest at floating rates. At December 31, 2003, we had $34 million of indebtedness bearing interest at floating rates. If interest rates were to change by one full percentage point, the net impact on Enterra’s earnings would be approximately $244,000 and the net impact on Enterra’s cash flow would be approximately $337,000.

Summary of Risk Sensitivities

Summarized below are Enterra’s sensitivities to various risks, based on its 2003 operations:

Sensitivity	Estimated 2004 Impact On:
	Net Income	Cash Flow
Crude oil – US$1.00/bbl change in WTI	$869,000	$1,774,000
Natural Gas – US$0.50/mcf change	$873,000	$1,781,000
Foreign Exchange - $0.01 change in U.S. to Cdn dollar	$193,000	$394,000
Interest rate – 1% change	$244,000	$337,000

Revenue Sources

For the year ended December 31, 2003, approximately 23% of the revenue from our properties before hedging and royalties was derived from natural gas and approximately 76% was derived from crude oil and natural gas liquids.

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 of our competitors can make acquisitions and bid on provincial leases in Alberta. Such competitors include oil companies and other income trusts, many of whom have greater financial resources, staff and facilities than ours.  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 competitors in the marketing of oil. Competitive factors in the distribution and marketing of oil include price and methods and reliability of delivery.

Seasonal Factors

The exploration for and development of oil and natural gas reserves is dependent on access to areas where production is to be conducted.  Seasonal weather variations, including freeze up and break up, affect access to our properties in certain circumstances.

Employees

At December 31, 2003, we had approximately 30 employees and consultants working both in the Calgary head office and in field operations.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Notes and Definitions

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty.  Categories of proved, probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied.  Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.

"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on (a) analysis of drilling, geological, geophysical, and engineering data;  (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate.  These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

"Undeveloped" reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production.  They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.  In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing.  This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved + probable reserves.

The following terms, used in the preparation of the McDaniel and Associates Report (as defined herein) and this document, have  the following meanings:

"associated gas" means the gas cap overlying a crude oil accumulation in a reservoir.

"constant prices and costs" means prices and costs used in an estimate that are:

(a)

the Trust's prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies;

(b)

if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Trust is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

For the purpose of paragraph (a), the reporting issuer's prices will be the posted price for oil and the spot price for gas, after historical adjustments for transportation, gravity and other factors.

"crude oil" or "oil" means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon compounds, that is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated. It does not include solution gas or natural gas liquids.

"development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a)

gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;

(b)

drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;

(c)

acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

(d)

provide improved recovery systems.

"development well" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

"exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a)

costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs");

(b)

costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

(c)

dry hole contributions and bottom hole contributions;

(d)

costs of drilling and equipping exploratory wells; and

(e)

costs of drilling exploratory type stratigraphic test wells.

"exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.

"field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest".

"future prices and costs" means future prices and costs that are:

(a)

generally accepted as being a reasonable outlook of the future;

(b)

if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Trust issuer is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

"future income tax expenses" means future income tax expenses estimated (generally, year-by-year):

(a)

making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;

(b)

without deducting estimated future costs (for example, Crown royalties) that are not deductible in computing taxable income;

(c)

taking into account estimated tax credits and allowances (for example, royalty tax credits); and

(d)

applying to the future pre-tax net cash flows relating to the reporting issuer's oil and gas activities the appropriate year-end statutory tax rates, taking into account future tax rates already legislated.

"future net revenue" means the estimated net amount to be received with respect to the development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using constant prices and costs or forecast prices and costs.

"gross" means:

(a)

in relation to the Trust's interest in production or reserves, its "company gross reserves", which are it's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Trust;

(b)

in relation to wells, the total number of wells in which the Trust has an interest; and

(c)

in relation to properties, the total area of properties in which the Trust has an interest.

"natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain natural gas liquids. Natural can exist in a reservoir either dissolved in crude oil (solution gas) or in a gaseous phase (associated gas or non-associated gas). Non-hydrocarbon substances may include hydrogen sulphide, carbon dioxide and nitrogen.

"natural gas liquids" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.

"net" means

(a)

in relation to the Trust's interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus the its royalty interests in production or reserves;

(b)

in relation to the Trust's interest in wells, the number of wells obtained by aggregating the Trust's working interest in each of its gross wells; and

(c)

in relation to the Trust's interest in a property, the total area in which the Trust has an interest multiplied by the working interest owned by the Trust.

"non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.

"operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

"production" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.

"property" includes:

(a)

fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;

(b)

royalty interests, production payments payable in oil or gas, and other non-operating interests in properties operated by others; and

(c)

an agreement with a foreign government or authority under which a reporting issuer participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).

A property does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.

"property acquisition costs" means costs incurred to acquire a property (directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the property), including:

(a)

costs of lease bonuses and options to purchase or lease a property;

(b)

the portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee;

(c)

brokers' fees, recording and registration fees, legal costs and other costs incurred in acquiring properties.

"proved property" means a property or part of a property to which reserves have been specifically attributed.

"reservoir" means a porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

"service well" means a well drilled or completed for the purpose of supporting production in an existing field.  Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion.

"solution gas" means natural gas dissolved in crude oil.

"stratigraphic test well" means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production.  They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (a) "exploratory type" if not drilled into a proved property; or (b) "development type", if drilled into a proved property.  Development type stratigraphic wells are also referred to as "evaluation wells".

"support equipment and facilities" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district or field offices.

"Trust" or "the Trust" means Enterra Energy Trust.

"unproved property" means a property or part of a property to which no reserves have been specifically attributed.

"well abandonment costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. They do not include costs of abandoning the gathering system or reclaiming the wellsite.

Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue

In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, McDaniel  prepared the McDaniel Report dated February 27, 2004.  The McDaniel Report evaluated, as at December 31, 2003, the Trust's oil, NGL and natural gas reserves.  The tables below are a summary of the oil, NGL and natural gas reserves of the Trust and the net present value of future net revenue attributable to such reserves as evaluated in the McDaniel Report based on constant and forecast price and cost assumptions.  The tables summarize the data contained in the McDaniel Report and as a result may contain slightly different numbers than such report due to rounding.  Also due to rounding, certain columns may not add exactly.  The net present value of future net revenue attributable to the Trust's reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by McDaniel. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Trust's reserves estimated by McDaniel represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Trust's oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual reserves may be greater than or less than the estimates provided herein.

The McDaniel Report is based on certain factual data supplied by the Trust and McDaniel’s opinion of reasonable practice in the industry.  The extent and character of ownership and all factual data pertaining to the Trust's petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Trust to McDaniel and accepted without any further investigation.  McDaniel accepted this data as presented and neither title searches nor field inspections were conducted.

Reserves Data – Constant Prices and Costs

Summary of Oil and Gas Reserves

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil (Bbls)	Heavy Oil (Bbls)	Natural Gas Liquids (Bbls)	Natural Gas (Mmcf/)	Light and Medium Crude Oil (Bbls)	Heavy Oil (Bbls)	Natural Gas Liquids (Bbls)	Natural Gas (Mmcf/)
Proved
Developed Producing	2,587	1,814	46	5,334	2,254	1,594	31	3,905
Developed Non-Producing	680	-	22	774	563	-	15	559
Undeveloped	-	-	-	-	-	-	-	-
Total Proved	3,267	1,814	68	6,108	2,817	1,594	46	4,464
Probable	1,360	590	22	1,926	1,130	517	15	1,397
Total Proved plus Probable	4,627	2,404	90	8,034	3,947	2,111	61	5,861

Net Present Value of Future Net Revenue of Oil and Gas Reserves

		Before Future Income Tax Expenses and Discounted at		After Future Income Tax Expenses and Discounted at
		0%	10%	0%	10%
		(M$)	(M$)	(M$)	(M$)
Proved
	Developed Producing	101,802	84,065	94,491	78,486
	Developed Non-Producing	22,614	18,547	14,752	12,073
	Undeveloped	-	-	-	-
Total Proved		124,416	102,612	109,243	90,559
Probable		52,314	35,268	34,890	23,248
Total Proved plus Probable		176,730	137,880	144,133	113,807

Additional Information Concerning Future Net Revenue – (Undiscounted)

	Revenue	Royalties	Operating Costs	Develop- ment Costs	Abandon-ment and Reclamation Costs	Future Net Revenue Before Income Taxes		Future Net Revenue After Income Taxes
							Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	205,484	30,467	46,475	200	3,926	124,416	15,173	109,243
Total Proved plus Probable	283,864	43,640	59,383	200	3,911	176,730	32,597	144,133

Future Net Revenue by Production Group

		Future Net Revenue Before Income Taxes and Discounted at 10%
		(M$)
Proved
	Light and Medium Crude Oil(1)	66,001
	Heavy Oil	16,801
	Natural Gas(2)	17,926
	ARTC	1,884
		102,612
Proved plus Probable
Light and Medium Crude Oil(1)		91,536
Heavy Oil		21,227
Natural Gas(2)		22,742
ARTC		2,375
		137,880

Notes:

(1)

Including solution gas and other by-products.

(2)

Including by-products, but excluding solution gas from oil wells.

Reserves Data – Forecast Prices and Costs

Summary of Oil and Gas Reserves

	Gross Reserves				Net Reserves
	Light and Medium Crude Oil (Bbls)	Heavy Oil (Bbls)	Natural Gas Liquids (Bbls)	Natural Gas (Mmcf/)	Light and Medium Crude Oil (Bbls)	Heavy Oil (Bbls)	Natural Gas Liquids (Bbls)	Natural Gas (Mmcf/)
Proved
Developed Producing	2,562	1,814	45	5,327	2,197	1,583	31	3,900
Developed Non-Producing	680	-	23	774	545	-	15	559
Undeveloped	-	-	-	-	-	-	-	-
Total Proved	3,242	1,814	68	6,101	2,742	1,583	46	4,459
Probable	1,359	590	22	1,926	1,114	516	15	1,397
Total Proved plus Probable	4,601	2,404	90	8,027	3,856	2,099	61	5,856

		Gross Reserves			Net Reserves
		Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Natural Gas    Liquids	Natural Gas
		Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mmcf
Proved
	Developed Producing	2,562	1,814          45	5,327	2,197	1,583         31	3,900
	Developed Non-Producing	680	-          23	774	545	-         15	559
	Undeveloped	-	-             -	-	-	-            -	-
Total Proved		3,242	1,814          68	6,101	2,742	1,583         46	4,459
Probable		1,359	590          22	1,926	1,114	516         15	1,397
Total Proved plus Probable		4,601	2,404          90	8,027	3,856	2,099         61	5,856

Net Present Value of Future Net Revenue of Oil and Gas Reserves

		Before Future Income Tax Expenses and Discounted at
		0%	5%	10%	15%	20%
		(M$)	(M$)	(M$)	(M$)	(M$)
Proved
	Developed Producing	78,467	73,012	67,943	63,458	59,553
	Developed Non-Producing	18,315	16,619	15,277	14,188	13,283
	Undeveloped	-	-	-	-	-
Total Proved		96,782	89,631	83,220	77,646	72,836
Probable		41,065	33,965	28,661	24,664	21,596
Total Proved plus Probable		137,847	123,596	111,881	102,310	94,432

		After Future Income Tax Expenses and Discounted at
		0%	5%	10%	15%	20%
		(M$)	(M$)	(M$)	(M$)	(M$)
Proved
	Developed Producing	76,731	71,463	66,552	62,202	58,413
	Developed Non-Producing	12,469	11,218	10,261	9,508	8,898
	Undeveloped	-	-	-	-	-
Total Proved		89,200	82,681	76,813	71,710	67,311
Probable		27,907	22,858	19,089	16,275	14,139
Total Proved plus Probable		117,107	105,539	95,902	87,985	81,450

Additional Information Concerning Future Net Revenue – (Undiscounted)

	Revenue	Royalties	Operating Costs	Develop- ment Costs	Abandon-ment and Reclamation Costs	Future Net Revenue Before Income Taxes		Future Net Revenue After Income Taxes
							Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	181,888	29,115	50,611	230	5,150	96,782	7,582	89,200
Total Proved plus Probable	250,772	40,950	66,368	230	5,377	137,847	20,739	117,108

Future Net Revenue by Production Group

		Future Net Revenue Before Future Income Tax Expenses Discounted at 10%
		(M$)
Proved
	Light and Medium Crude Oil(1)	51,602
	Heavy Oil	14,437
	Natural Gas(2)	15,421
	ARTC	1,760
		83,220
Proved plus Probable
Light and Medium Crude Oil(1)		71,972
Heavy Oil		18,327
Natural Gas(2)		19,358
AR|TC		2,224
		111,881

Notes:

(1)

Including solution gas and other by-products.

(2)

Including by-products, but excluding solution gas from oil wells.

Pricing Assumptions – Constant Prices and Costs

McDaniel and Associates employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2003 in estimating the Trust's reserves data using constant prices and costs.

Year	WTI at Cushing	Edmonton Par Price 40” API	Bow River Medium 25 API	Hardisty Heavy 12” API	Alberta Average Plantgate Price	Natural Gas Liquids FOB Field Gate	Exchange Rate
	($US/bbl)	($Cdn/bbl )	($Cdn/bbl )	($Cdn/bbl )	($Cdn/Mmbtu)	($Cdn/bbl )	($US/$Cdn)
2003 (Year end)	32.78	39.76	32.74	22.75	5.87	31.50	.715

Pricing Assumptions – Forecast Prices and Costs

McDaniel employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2003 in estimating the Trust's reserves data using forecast prices and costs.  

Year	WTI at Cushing	Edmonton Par Price 40” API	Bow River Medium 25 API	Hardisty Heavy 12” API	Alberta Average Plantgate Price	Natural Gas Liquids FOB Field Gate	Inflation Rate %/Yr	Exchange Rate
	($US/bbl)	($Cdn/bbl )	($Cdn/bbl )	($Cdn/bbl )	($Cdn/Mmbtu)	($Cdn/bbl )	%/Yr	($US/$Cdn)
2003 (est.)	30.95	43.10	36.90	27.45	6.35	33.80	2.0	.715
Forecast
2004	29.00	37.70	27.70	22.70	5.65	27.90	2.0	0.75
2005	26.50	34.30	26.65	21.55	5.30	25.50	2.0	0.75
2006	25.50	33.00	26.24	21.56	4.95	24.50	2.0	0.75
2007	25.00	32.30	25.40	20.63	4.75	23.80	2.0	0.75
2008	25.00	32.30	25.26	20.39	4.60	23.70	2.0	0.75
2009	25.50	32.90	25.72	20.76	4.65	24.10	2.0	0.75
2010	26.00	33.50	26.18	21.11	4.65	24.50	2.0	0.75
2011	26.50	34.20	26.73	21.56	4.75	25.00	2.0	0.75
2012	27.00	34.80	27.18	21.91	4.85	25.40	2.0	0.75
2013	27.50	35.50	27.73	22.35	4.95	26.00	2.0	0.75
2014	28.10	36.20	28.28	22.79	5.05	26.50	2.0	0.75
Thereafter	+2%

The weighted average realized sales prices for the Trust for the year ended December 31, 2003 were $6.61/Mcf for natural gas, $39.97/Bbl for crude oil and $33.00/Bbl for NGL's.

Reconciliations of Changes in Reserves and Future Net Revenue

Reserves Reconciliation

The following table sets forth a reconciliation of the Trust's total proved, probable and total proved plus probable reserves as at December 31, 2003 against such reserves as at December 31, 2002 based on forecast price and cost assumptions.

	Light and Medium Crude Oil			Natural Gas Liquids
	Total Proved Reserves	Probable Reserves	Total Proved Plus Probable	Total Proved Reserves	Probable Reserves	Total Proved Plus Probable
	Mbbls	Mbbls	Mbbls	Mbbls	Mbbls	Mbbls
December 31, 2002	4,409.3	2500.8	6,910.1	313.4	86.9	400.3
Acquisitions	113.4	30.0	143.4
Disposals	-401.0	-368.0	-769.0	-199.8	-38.0	-237.8
Drilling Additions	747.1	422.0	1,169.1
Production	-1,175.6		-1,175.6	-46.1		-46.1
Technical Revisions	-449.7	-1,225.8	-1,675.5		-26.7	-26.7
December 31, 2003	3,243.5	1,359.0	4,602.5	67.5	22.2	89.7
	Associated and Non-Associated Gas			Heavy Oil
	Total Proved Reserves	Probable Reserves	Total Proved Plus Probable	Total Proved Reserves	Probable Reserves	Total Proved Plus Probable
	Mmcf	Mmcf	Mmcf	Mbbls	Mbbls	Mbbls
December 31, 2002	13,044.1	4,917.1	17,961.2	479.7	287.4	767.1
Acquisitions	156.5	15.6	172.1
Disposals	-6,638.5	-3,141.9	-9,780.4
Drilling Additions	3,204.2	817.1	4,021.3	1,519.2	302.3	1,821.5
Production	-2,561.9		-2,561.9	-184.5		-184.5
Technical Revisions	-1,100.3	-681.2	-1,781.5
December 31, 2003	6,104.1	1,926.7	8,030.8	1,814.4	589.7	2,404.1

Future Net Revenue Reconciliation

The following table sets forth a reconciliation of the estimate of the net present value of future net revenue attributable to the Trust's reserves as evaluated in the McDaniel Report as at December, 31, 2003 against the estimate of such amount as at December, 31, 2002, calculated after tax using a discount rate of 10% and constant price and cost assumptions.

	(M$)
December 31, 2002	$106,671
Sales and Transfers of Oil and Gas Produced during the Period Net of Production Costs and Royalties	(41,679)
Net Change in Sales and Transfer Prices and in Production Costs and Royalties related to Future Production	(45,194)
Changes in Previously Estimated Development Costs Incurred During the Period	7,486
Changes in Estimated Future Development Costs	9
Net Change Resulting from Extensions, Discoveries and Improved Recovery	46,433
Changes Resulting from Acquisitions of Reserves	-
Changes Resulting from Dispositions of Reserves	(18,263)
Net Change Resulting from Revisions in Quantity Estimates	(8,106)
Accretion of Discount	10,667
Net Change in Income Taxes	30,391
Other Significant Factors	2,144
December 31, 2003	$90,559

Undeveloped Reserves

The following discussion generally describes the basis on which the Trust attributes Proved and Probable Undeveloped Reserves and its plans for developing those Undeveloped Reserves.

Proved Undeveloped Reserves

Proved undeveloped reserves are generally those reserves related to wells that have been tested and not yet tied-in, wells drilled near the end of the fiscal year or wells further away from the Trust's gathering systems.  In addition, such reserves may relate to planned infill drilling locations.  The majority of these reserves are planned to be on stream within a two year timeframe.

Probable Undeveloped Reserves

Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production.  The majority of these reserves are planned to be on stream within a two year timeframe.

Significant Factors or Uncertainties Affecting Reserves Data

The process of estimating reserves is complex.  It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data.  These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.  The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. The Trust's reserves are evaluated by McDaniel, an independent engineering firm.

As circumstances change and additional data become available, reserve estimates also change.  Estimates made are reviewed and revised, either upward or downward, as warranted by the new information.  Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science.  As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates.  Revisions to reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance.  Such revisions can be either positive or negative.

Future Development Costs

The table below sets out the development costs deducted in the estimation of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

	Constant Prices and Costs	Forecast Prices and Costs
	Proved Reserves	Proved Reserves	Proved Plus Probable Reserves
	(M$)	(M$)	(M$)
2004	-	-	-
2005	-	-	-
2006	-	-	-
2007	-	-	-
2008	-	-	-
Remaining Years	200	229.7	229.7
Total Undiscounted	200	229.7	229.7
Total Discounted at 10% per year	112.9	129.7	129.7

The Trust estimates that its internally generated cash flow will be sufficient to fund the future development costs disclosed above.  The Trust typically has available three sources of funding to finance its capital expenditure program; internally generated cash flow from operations, debt financing when appropriate and new equity issues, if available on favourable terms.  Debt financing is available to the Trust at 0.25% above prime rate, which is currently 3.75% per annum.

The Trust expects to fund its total 2004 capital program with internally generated cash flow and, although quarterly fluctuations in funding levels are expected, the objective is to remain at the current net debt level throughout the 2004 financial year.  The Trust's objective is to maintain its debt to cash flow ratio at less than 2 times estimated future cash flows.

Oil and Gas Properties

Enterra's core areas included the Peace River Arch area of Alberta, Central Alberta and East Central Alberta.  Enterra also has a large inventory of prospects, the development of which could significantly increase the size of Enterra’s existing production and reserve base.

Peace River Arch of Alberta

Clair

The Clair property is located 13 km north of the city of Grande Prairie, Alberta.  Enterra’s assets include a 100% working interest in 3,840 acres of land, 20 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.  Production is light, 44 degree API gravity crude and solution gas is produced from the Doe Creek oil pool.  At December 31, 2003 there were 20 oil wells producing a combined 2,175 bbl/d of oil and 2.1 mmcf/d of solution gas.  One dually completed Charlie Lake and Halfway gas well also produces combined daily gas of 400 mcf/d. Enterra has a 100% working interest in this well.  To date, Enterra has drilled or recompleted 29 wells for oil and seven wells for water injection.  There are no further drilling plans for the pool.  Enterra has received waterflood approval  in June 2003 (with two recent amendment approvals) and is in the final stages of achieving 100% voidage replacement pending minor waterflood modifications.  Nine wells shut-in in 2003 due to excessive gas production will be reactivated once pressure support from the waterflood is received at the wells.

Total proved reserves assigned to the Doe Creek ‘A’ (Dunvegan) pool are 1,997 mbbl of oil, 1,236 mmcf of gas and 38 mbbl of natural gas liquids.  Total proved and probable reserves assigned to the Doe Creek ‘A’ (Dunvegan) pool are 2,998 mbbl of oil, 1,633 mmcf of gas and 51 mbbl of natural gas liquids.  The probable reserves category contains the incremental reserves and net present value of the waterflood.  McDaniel and Associates have stated that the additional reserves associated with the waterflood would be moved into the proven category in a staged approach.  Critical stages include the achievement of 100% voidage replacement and continued performance.  Total proved reserves assigned to the 13-07-073-5W6 Charlie Lake / Halfway gas well are 256 mmcf of gas and 8 mbbl of natural gas liquids.  Total proved and probable reserves assigned to the Charlie Lake / Halfway gas well are 368 mmcf of gas and 11 mbbl of natural gas liquids.

Enterra also owns and operates a central oil treating facility at Clair which was connected into the Pembina Peace Pipeline system in September 2003.

Gordondale

The Gordondale property is located 75 km northwest of the city of Grande Prairie, Alberta.  Enterra’s assets included an average working interest of 79% in 6,240 gross acres of land as well as two flowing gas wells, one gas well awaiting tie in and one oil well.  Production is currently from the Upper Kiskatinaw and Halfway zones.  Enterra’s share of production for the property was 300 mcf/d of gas, 8 bbl/d of oil and 4 bbl/d of natural gas liquids.  The property was sold in December 2003.

McDaniel and Associates had assigned Company’s share of total proved reserves to Gordondale of 164 mmcf of gas, 2 mbbl of oil, and 2 mbbl of natural liquids.  Total proved and probable reserves were 217 mmcf of gas, 3 mbbl of oil, and 3 mbbl of natural gas liquids.

Rolla

The Rolla property is located 70 km north of the city of Grande Prairie, Alberta.  Enterra’s assets include a 50% working interest in 1,920 acres of land, 3 operated producing gas wells and a 12.5% working interest in two field compressors.  Enterra’s share of current gas production is approximately 800 mcf/d from three 50% working interest Dunvegan gas wells.  This gas is processed at the Duke Midstream, Gordondale East gas plant.

Total proved reserves assigned to the Dunvegan are 512 mmcf of gas, and total proved and probable reserves assigned to the Dunvegan are 725 mmcf of gas.  All of the proved reserves are in the proved producing category.  The Dunvegan sand development in the Rolla area is part of a large Delta complex from the northwest.

Hines Creek

The Hines Creek property is located 150 km north of the city of Grande Prairie, Alberta.  Enterra’s assets include a 50% working interest in 5,760 acres of land, one producing gas well and one shut-in gas well currently awaiting a fracture stimulation.  Enterra’s share of current gas production is approximately 850 mcf/d from the 50% working interest well, and expects Enterra’s share of production from the 50% working interest shut-in well to be in excess of 200 mcf/d.

Total proved reserves assigned to the Hines Creek property are 728 mmcf of gas, and total proved and probable reserves are 882 mmcf of gas.  All of the proved reserves are in the proved producing category.

East Central Alberta

Sounding Lake

The Sounding Lake package is located 10 km southwest of the town of Provost, Alberta.  Enterra’s assets include an average working interest of 58.7% in 5,496 gross acres of land as well as 56 producing oil wells and 2 producing gas wells.  Production is obtained primarily from the Dina, Cummings and Belly River formations.  The three main oil pools are Sounding Lake West, Sounding Lake East, and Sounding Lake North.  Enterra’s share of current production for the entire area is 520 bbl/d of oil and 1,700 mcf/d of gas.  Enterra has and continues to upgrade pump sizes to maximize oil production and upgrade oil batteries to handle higher volumes of total fluid and injection water.  Enterra has also tied-in the flared solution gas from two of its key facilities in the area.

Enterra was assigned proved reserves at Sounding Lake of 741 mbbl of oil and 1,451 mmcf of natural gas.  Total proved and probable reserves are 926 mbbl oil and 1,870 mmcf natural gas based on improved performance from the existing wells.

Central Alberta

Sylvan Lake

The Sylvan Lake property is located 40 km west of the town of Red Deer, Alberta.  Enterra’s assets include an average working interest of 74.8% in 4,320 gross acres of land as well as 24 producing oil wells and 1 producing gas well.  Enterra completed the development of 40-acre spacing wells in the Pekisko G pool, increasing the number of producing wells from five to 24 wells.  The property currently produces 1,225 bbl/d (gross), 1,100 bbl/day (net) of 14 degree API oil from 24 wells with 850 mcf/d (net) of associated gas plus an additional 30 mcf/d (net) of non-associated gas.  Production is flowlined into a central treating facility constructed in September 2003 which is owned and operated by Enterra Energy.  Non-associated gas is conserved and flowlined to the Husky Sylvan Lake gas plant.  Clean oil is trucked from the facility to sales.

McDaniel and Associates has assigned total proved reserves of 1,814 mbbl of oil, 1,014 mmcf of solution gas, and 32 mmcf of non-associated gas to this property.  Total proved and probable reserves are 2,404 mbbl of oil, 1,344 mmcf of solution gas, and 40 mmcf of non-associated gas.  Probable reserves were assigned based on an assumption that the wells will achieve a slightly higher oil recovery than estimated.  Based on the success of the 2003 drilling program, Enterra plans to drill seven wells with further downspacing in the centre of the pool as well as initiate a waterflood feasibility study for 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.

Kaybob

This property is located 50 kilometers north of Edson, Alberta and is pipeline connected to a major gas and oil processing facility in the area.  There is one well with a working interest of 100% on production in this property.  With the construction of a pipeline tie-in in September 2003 and the addition of a gas-lift system in November 2003, the well was returned to production.  The well is producing 130 bbl/d light crude oil with 110 mcf/d of associated gas.

McDaniel and Associates have assigned total proved reserves of 391 mbbl of oil, 230 mmcf of gas, and 8 mbbl of natural gas liquids to this property.  Total proved and probable reserves are 548 mbbl of oil, 323 mmcf of gas, and 11 mbbl of natural gas liquids.  Enterra acquired its interest in the Kaybob South Nisku C Pool in the year 2000.  Enterra owns a 90% working interest in 320 acres of land, subject to a 7.5% NCORR on 100% of production.  Enterra has a licensed copy of a 7 square mile 3-D program over the well and adjacent lands.

Oil and Gas Wells

The following table summarizes the Trust's interest as at December 31, 2003 in wells that are producing and non-producing.

	Producing Wells
	Oil		Natural Gas
	Gross	Net	Gross	Net
Kaybob	1	0.90
Highvale			2	0.75
Leduc	1	0.39	1	0.62
Garden Plains
Gilby			1	0.39
Leedale			1	0.02
Lubicon	1	0.23
Willesden Green	101	5.98	1	0.43
Timber Draw	1	0.15
Sounding Lake East	17	16.50
Sounding Lake West	55	27.50
Sounding Lake North	22	6.92
Sylvan lake	24	22.75	1	0.32
Clair	28	28.00	5	5.00
Gordondale	1	0.50	2	1.00
Rolla			2	1.00
Swan Hills	1	0.50
Campbell	1	0.12
Total	254	110.44	16	9.53

	Non-Producing Wells
	Oil		Natural Gas
	Gross	Net	Gross	Net
Sylvan Lake	5	2.6	1	-
Provost	2	1.0
Clair	14	7.3
Other	2	1.1
Total	23	12.0	1	-

Properties with no Attributed Reserves

The following table summarizes the gross and net acres of unproved properties in which the Trust has an interest and also the number of net acres for which the Trust's rights to explore, develop or exploit will, absent further action, expire within one year.

	Gross Acres	Net Acres	Net Acres Expiring Within One Year
Alderson	1,920	1,920
Bellis	640	320	320
Cheyenne River	58,186	9,002
Clair	160	160
Doig	1,280	1,280
Doris	3,200	256
Entwistle	1,280	678
Ferrybank	640	320	320
Glacier	640	224
Gull Lake	1,763	882	882
Hines Creek	5,120	2,560
Little Bow	640	0.0
Lubicon	160	37
Misty	640	80
Pembina	640	51
Provost	2,442	1,316
Ricinus	3,200	3,200	3,200
Rolla	1,920	960
Saddle Hills	320	80
Spirit River	1,280	499
Swan Hills	480	480
Sylvan Lake	2,400	1,680
Tee Pee	2,560	2,240
Tindastoll	802	640
Wembley	640	640
Willesden Green	320	176	176
Worsley	6,880	3,010	1,330
Total	100,153	32,691	6,228

Drilling Activity

The following table summarizes the Trust's drilling results for the year ended December 31, 2003.

	2003
	Gross	Net
Oil	31	31.0
Natural Gas	3	1.1
Injection and Water Disposal	6	6.0
Dry & Abandoned	7	6.4
Total	47	44.5

Additional Information Concerning Abandonment and Reclamation Costs

The Trust estimates well abandonment costs stereotypically area by area.  Such costs are included in the McDaniel Report as deductions in arriving at future net revenue.  The expected total abandonment costs included in the McDaniel Report for 85.5 net wells under the proved reserves category is $5.1 million undiscounted  ($1.5 million discounted at 10%), of which a total of $60,400 is estimated to be incurred in 2004, 2005 and 2006.  

Tax Horizon

The Trust was not required to pay income taxes during the year ended December 31, 2003.  Based on a strategy of re-investing fully all internally generated cash flow in an exploration and development program and based on the commodity prices used in the McDaniel Report, the Trust estimates that it will not be required to pay income taxes until after 2007.

Costs Incurred

The following table summarizes the Trust's property acquisition costs, exploration costs and development costs for the year ended December 31, 2003.

	Property Acquisition Costs
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Total (M$)	-	$8,028,000	$766,000	$24,240,000

Production Estimates

The following table discloses for each product type the total volume of production estimated by McDaniel for 2004 in the estimates of future net revenue from proved reserves disclosed above under the heading "Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue".

	Light and Medium Crude Oil (Bbls/d)	Heavy Oil (Bbls/d)	Natural Gas (Mcf/d)	Natural Gas Liquids (Bbls/d)	BOE (BOE/d)	%
Clair	2,332		1,208	38	2,571	50
Hines Creek			614		102	2
Kaybob	170		288	6	223	4
Rolla			518		86	2
Sounding Lake	411		1,351		636	12
Sylvan Lake		1,247	753		1,372	27
Other	106		435	8	189	3
Estimated Total Production	3,019	1,247	5,167	52	5,179	100

Production History

The following table discloses, on a quarterly basis for the year ended December 31, 2003, the Trust's share of average daily production volume, prior to royalties, and the prices received, royalties paid, production costs incurred and netbacks on a per unit of volume basis for each product type.

Average Daily Production Volume

	Three Months Ended
	March 31, 2003	June 30, 2003	Sept. 30, 2003	Dec. 31, 2003	Total
Natural gas (Mcf/d)	7,984	6,144	7,201	6,572	6,972
Light and Medium Crude Oil (Bbl/d)	3,757	3,879	3,374	3,959	3,742
NGL (Bbl/d)	90	99	139	152	120
Total (BOE/d)	5,178	5,002	4,713	5,206	5,024

Prices Received, Royalties Paid, Production Costs and Netback – Light and Medium Crude Oil

($ per Bbl)	Three Months Ended
	March 31, 2003	June 30, 2003	Sept. 30, 2003	Dec. 31, 2003	Total
Prices Received	48.40	43.90	41.81	31.78	39.29
Royalties Paid	12.47	10.67	9.06	7.31	9.37
Production Costs	6.46	6.90	8.41	6.19	6.96
Netback	29.47	26.33	24.34	18.28	22.96

Prices Received, Royalties Paid, Production Costs and Netback – Natural Gas and NGLs

($ per McfGE)	Three Months Ended
	March 31, 2003	June 30, 2003	Sept. 30, 2003	Dec. 31, 2003	Total
Prices Received	7.27	7.19	5.96	5.80	6.55
Royalties Paid	2.13	1.99	1.69	1.71	1.80
Production Costs	1.07	1.15	1.40	1.03	1.16
Netback	4.07	4.05	2.87	3.06	3.59
Gas price	7.27	7.36	6.04	5.91	6.65
NGL price	7.16	5.51	5.28	5.01	5.59

Production Volume by Field

The following table discloses for each important field, and in total, the Trust's production volumes for the financial year ended December 31, 2003 for each product type.

Field	Light and Medium Crude Oil (Bbls/d)	Heavy Oil (Bbls/d)	Natural Gas (Mcf/d)	Natural Gas Liquids (Bbls/d)	BOE (Bbls/d)	%
Clair	2,630		2,613	81	3,147	63
Gordondale	8		300	4	59	1
Rolla			972		162	3
Hines Creek			462		77	2
Sounding Lake	490		1,373	9	728	14
Sylvan Lake		493	257	13	549	11
Other	121		995	13	302	6
Total	3,249	493	6,972	120	5,024	100

Material Change to Reserve Information Since December 31, 2003

On January 31, 2004, the Trust acquired several properties in East Central Alberta for $20 million.  These properties currently produce approximately 1,800 boe/day, consisting of 1,600 bbl/day of oil and 1,200 mcf/day of gas, along with approximately  22,166 acres of undeveloped land.  This acquisition added approximately 2,078.2 mbbls of oil, 28.6 mbbls of NGL’s and 1,622.0 mmcf of gas to our proved reserves and 800.5 mbbls of oil, 25.9 mbbls of NGL’s and 1,051.0 mmcf of gas to our probable reserves.  For further details of this acquisition, see Appendix "A" hereto.

ADDITIONAL INFORMATION RESPECTING THE 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").  In addition, in certain circumstances Unitholders will have the right to instruct the trustees of EEC Trust with respect to the voting of common shares of Enterra held by EEC Trust at meetings of holders of common shares of Enterra. See "Meetings of Unitholders" and "Exercise of Voting Rights".

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's assets. 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 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, 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 Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and 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.

As of April 19, 2004, there were 21,156,489 Trust Units outstanding, 868,868 Trust Units reserved for issuance on the exchange of Exchangeable Shares and 920,000 Trust Units reserved for issuance pursuant to the Trust Unit option plan of the Trust.

Income Streams

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, less all expenses and liabilities of the Trust due and accrued and which are chargeable to the net income of the Trust.  The Trust's primary sources of cash flow are payments of interest and principal from Enterra and EEC Trust in respect of the Series A Notes and the CT Note.

The Series A Notes

The Series A Notes were created and issued by Enterra to the Trust pursuant to the Arrangement.  The principal amount of the Series A Notes issued pursuant to the Arrangement was $125,000,000.  The Series A Notes are unsecured and bear interest at a rate of 14% per annum, which is payable for each month during the term on the 15^th day of the month following such month.  For a detailed description of the Series A Notes, see "Additional Information Respecting Enterra – Series A Notes".

The CT Note

The CT Note is a subordinated, demand participating promissory note.  The CT Note was issued by EEC Trust to the Trust pursuant to the Arrangement with a principal amount of $117,742,660.90.  The principal amount of the CT Note was adjusted to $126,093,310.61 on December 25, 2003, based upon the market price of the Trust Units at such date.  Redemptions and returns of capital on shares of Enterra held by EEC Trust may be made from time to time and applied as prepayments of the principal amount of the CT Note.  The CT Note will bear interest at a rate that is re-set from time to time so as to approximate the return on the shares of Enterra held by EEC Trust.

Distributions to Unitholders

The Trustee may declare payable to the Unitholders all or any part of the net income of the Trust, less all expenses and liabilities of the Trust due and accrued and which are chargeable to the net income of the Trust.  We currently anticipate that 80% of the cash flow generated by our oil and gas assets will be distributed to our Unitholders.  As of March, 2004, the monthly distribution payable to Unitholders has been set at US$0.11.  See "Distributions".  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 we cannot assure that cash flows will be available for distribution to Unitholders in the amounts anticipated or at all.  See "Risk Factors".

Special Voting Rights

The Trust Indenture allows for the creation and issuance of an unlimited number of special voting rights ("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 entitled to any distributions of any nature whatsoever from the Trust.  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 securities relating to such Special Voting Rights held by such holder are exchangeable, exercisable or convertible. Holders of Special Voting Rights are also 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 one 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.

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 that 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 terms of the Trust Indenture, Unitholders may not be protected from liabilities of the Trust to the same extent a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against the Trust (to the extent that claims are not satisfied by the Trust) that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability to Unitholders of this nature arising is considered unlikely in view of the fact that the sole activity of the Trust is to hold securities, and all of the business operations are carried on by Enterra, directly or indirectly.

The activities of the Trust, EEC Trust, Enterra and the Partnership are conducted, upon the advice of counsel, 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, for the operations of Enterra and having contracts signed by or on behalf of the Trust include a provision that such obligations are not binding upon Unitholders personally.

Issuance of Trust Units

The Trust Indenture provides that Trust Units, including rights, warrants (including so called "special warrants" which may be exercisable for no additional consideration) and other securities to purchase, to convert into or to exchange into Trust Units, may be created, issued, sold and delivered on such terms and conditions and at such times as the Enterra Board may determine, including, without limitation, installment or subscription receipts.  The Trust Indenture also provides that Enterra may authorize the creation and issuance of debentures, notes and other evidences of indebtedness of the Trust which debentures, notes or other evidences of indebtedness may be created and issued from time to time on such terms and conditions to such persons and for such consideration as Enterra may determine.

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 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, as the case may be, 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 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 proxyholder 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 directing the Trustee as to the manner in which the Trustee shall vote the EEC Trust Units held by the Trust in respect of those matters voted on at such meeting of Unitholders. 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 favour of or in opposition to, or to vote or withhold 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 EEC Trust to vote any shares of Enterra in respect of:

(d)

any sale, lease or other disposition of, or any interest in, all or substantially all of the assets owned, directly or indirectly, by Enterra, the Trust or the Partnership, except in conjunction with an internal reorganization 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;

(e)

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;

(f)

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;

(g)

any amendment to the articles of Enterra to increase or decrease the minimum or maximum number of directors;

(h)

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

(i)

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.

Finally, the Trustee is prohibited from authorizing EEC Trust 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 initial 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, pursuant to the Trust Indenture, 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 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; and (vii) all matters relating to the voting rights on any instruments held by the Trust, other than the EEC Trust Units.

In addition, pursuant to an administration agreement dated November 25, 2003 between the Trust and Enterra (the "Administration Agreement"), Enterra has been appointed the administrator of the Trust and is responsible for the administration and management of all general and administrative affairs of the Trust.  Enterra is not entitled to the payment of a fee for the services provided to the Trust pursuant to the Administration Agreement.  

Liability of The Trustee

The Trustee, its directors, officers, employees, shareholders and agents are not 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 the purpose of:

(a)

ensuring the Trust's continuing compliance with applicable laws or requirements of any governmental agency or authority;

(b)

ensuring that the Trust will satisfy the provisions of each of subsections 108(2) and 132(6) and paragraph 132(8)(a) of the Tax Act as from time to time amended or replaced;

(c)

providing for and ensuring (i) the allocation of items of income, gain, loss, deduction and credit in respect of the Trust for United States federal income tax purposes; (ii) the filing of income tax returns necessary or desirable for the purposes of United States federal income tax; or (iii) compliance by the Trust with any other applicable provisions of United States federal income tax law;

(d)

ensuring that such additional protection is provided for the interests of Unitholders as the Trustee may consider expedient;

(e)

removing or curing any conflicts or inconsistencies between the provisions of the Trust Indenture or any supplemental indenture and any other agreement of the Trust or any offering document pursuant to which securities of the Trust are issued with respect to the Trust, or any applicable law or regulation of any jurisdiction, provided that in the opinion of the Trustee the rights of the Trustee and of the Unitholders are not prejudiced thereby;

(f)

curing, correcting or rectifying any ambiguities, defective or inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of the Trustee the rights of the Trustee and of the Unitholders are 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.

Takeover Bid

The Trust Indenture contains provisions to the effect that if a takeover bid is made for the Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Unitholders who did not accept the take-over bid on the terms offered by the offeror.  In the event of a take-over bid for Trust Units, any holder of a security exchangeable directly indirectly into Trust Units may, unless prohibited by the terms and conditions of such exchangeable security, convert, exercise or exchange such exchangeable security for the purpose of tendering Trust Units to the take-over bid, unless an identical offer is made by the offeror to purchase such exchangeable security.

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; (b) a quorum of 50% of the issued and outstanding Trust Units must be present in person or by proxy; and (c) the termination must be approved by Special Resolution of Unitholders.

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 is 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 http://www.sec.gov.

ADDITIONAL INFORMATION RESPECTING ENTERRA

Enterra has generally been delegated responsibility relating to significant management and operational decisions involving the Trust and the crude oil and natural gas properties underlying the Trust.  See "Additional Information Respecting the Trust – Delegation of Authority, Administration and Trust Governance".

Directors and Officers

The Enterra Board currently consists of 5 individuals.  The directors are elected by EEC Trust at the direction of Unitholders by ordinary resolution, and hold office until the next annual meeting of Unitholders, which is anticipated to be held in May, 2004.

Name, Occupation and Securityholding

The following table sets forth certain information respecting the directors and officers of Enterra.

Name and Municipality of Residence	Position Held	Date First Elected or Appointed as Director
Luc Chartrand Calgary, Alberta	President, Chief Executive Officer and Director	2003
Reginald J. Greenslade(2) (4) Calgary, Alberta	Director and Chairman	2003
William B. Turko Calgary, Alberta	Vice President, Engineering	Not applicable
Lynn Wiebe Calgary, Alberta	Chief Financial Officer	Not applicable
H.S. (Scobey) Hartley(1) (2)(3)(4) Calgary, Alberta	Director	2003
Norman Wallace(1) (2) (3) (4) Saskatoon, Saskatchewan	Director	2003
William E. Sliney (1) San Ramon, California	Director	2004

Notes:

(1)

Member of Audit Committee

(2)

Member of Compensation Committee

(3)

Member of Reserves Committee

(4)

Member of Corrporate Governance Committee

As at April 19, 2004, the directors and executive officers of Enterra, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 252,497 Trust Units, representing approximately 1.19% of the issued and outstanding Trust Units, and 24,973 Exchangeable Shares, representing approximately 2.9% of the issued and outstanding Trust Units.  Assuming all Exchangeable Shares were exchanged for Trust Units, using the exchange ratio of 1.03231 in effect as at April 19, 2004, the directors and executive officers of Enterra would hold 278,277 Trust Units, representing approximately 1.26% of the issued and outstanding Trust Units.

Profiles of Enterra’s directors and executive officers and the particulars of their respective principal occupations during the last five years is set forth below.

Luc Chartrand, President, Chief Executive Officer and Director

Mr. Chartrand worked for KPMG LLP as a Chartered Accountant from 1985 to 1988 when he became a tax manager in their Calgary office. He left shortly thereafter and worked as a consultant to several Calgary companies. He moved to Toronto in 1990 to assist in the relocation and takeover of Financial Trust by Central Capital. He remained in Toronto until 1992 when he returned to Calgary with Morgan Financial Corporation. Shortly thereafter, he joined Bonus Resource Services Corp. as its Chief Financial Officer. Mr. Chartrand joined Big Horn Resources Ltd. in the fall of 1994 and became Chief Financial Officer in 1996. He became Chief Financial Officer of Old Enterra in August 2001 and Chief Executive Officer, President and director of Enterra in November 2003.

Lynn Wiebe, Chief Executive Officer

Ms. Wiebe joined Enterra on October 1, 2003 as Chief Financial Officer. Ms. Wiebe is a Chartered Accountant and held various progressive positions at KPMG LLP from 1980 to 1986. From 1986 to 1995, Ms. Wiebe was employed by Gulf Canada Resources in supervisory positions in Financial Reporting, Corporate Reporting, Oil Marketing and Accounting and various other areas within the company. From 1995 to May 2001 Ms. Wiebe left the permanent workforce to pursue other interests. During the period from May 2001 to October 2002, she provided financial services to a number of organizations, including Trans Canada Pipelines and a private mortgage company, through contracting and consulting engagements. In May of 2003, Ms. Wiebe was employed by Control-F1 Corporation, an eSupport software company, as Chief Financial Officer, until she joined Enterra in October, 2003.

William B. Turko, Vice President, Engineering

Mr. Turko joined Enterra Energy Trust on February 1, 2004 as Chief Operating Officer.  From 1988 to 1991, Mr. Turko was employed by Coopers & Lybrand Chartered Accountants as a Chartered Accountant Articling Student, responsible for planning and executing financial statement audits of public and private corporations primarily in the oil and gas industry.  From 1995 to 1997, Mr Turko was employed by Mobil Oil Canada as a Reservoir Engineer responsible for evaluating and pursuing a multitude of exploration and development opportunities primarily in Central Alberta.  In 1997, Mr. Turko joined Renaissance Energy Ltd. as a Gas Exploitation Engineer responsible for the exploitation of the company’s eastern Alberta gas assets. In December, 1997, Mr. Turko joined Startech Energy Inc. as a Senior Engineer responsible for a multitude of engineering duties including drilling, completions, production operations, reservoir engineering and evaluations relating to the company’s assets in Southeast Saskatchewan, Alberta, British Columbia and Montana.  In January, 2001, Startech was acquired by ARC Energy Trust.  From February 2001 to January, 2003, Mr Turko was a Senior Exploitation Engineer at ARC where he was responsible for identifying, generating and pursuing exploitation, development, production and acquisition opportunities in the Drayton Valley and Central Alberta areas.  In January, 2003, Mr Turko joined Impact Energy Inc. as a Senior Engineer responsible for a multitude of engineering related duties in Alberta and British Columbia.  In March, 2004, Impact Energy was acquired by Thunder Energy Inc.

Mr. Turko holds a Bachelor of Management with Distinction from the University of Lethbridge and a Bachelor of Science in Mechanical Engineering with Distinction from the University of Alberta.  Mr. Turko is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and has over 12 years experience in the oil and gas industry.

Reginald (Reg) J. Greenslade. Director

Mr. Greenslade was President, CEO and Director of Old Enterra from the fall of 2001 until November 2003 and continued as Chairman of the Enterra Board following the Arrangement.  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.

H.S. (Scobey) Hartley, Director

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 Wallace, Director

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, Director

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. Mr. Sliney holds a masters degree in business administration from the University of California at Los Angeles.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

No director or executive officer of Enterra is, as at the date hereof, or has been, within the 10 years prior to the date hereof, a director or executive officer of any company that, while that person was acting in that capacity,

(a)

was the subject of a cease trade or similar order or an order that denied such company access to any exemption under securities legislation for a period of more than 30 consecutive days,

(b)

was subject to an event that resulted, after the director or executive officer ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied such company access to any exemption under securities legislation for a period of more than 30 consecutive days, or

(c)

within a year of such person ceasing to act in such capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

In addition, no director or executive officer of Enterra has, within the 10 years prior to the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of such director or officer.

Conflicts of Interest

Circumstances may arise where members of the board of directors or officers of Enterra are directors or officers of corporations which are in competition to the interests of Enterra and the Trust.  No assurances can be given that opportunities identified by such board members or officers will be provided to Enterra or the Trust.  In accordance with Business Corporations Act (Alberta), a director or officer who is a party to a material contract or proposed material contract with Enterra or the Trust or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with Enterra or the Trust shall disclose to Enterra the nature and extent of the director's or officer's interest. In addition, a director shall not vote on any resolution to approve a contract of the nature described except in limited circumstances.

Description of Share Capital

Enterra is authorized to issue an unlimited number of common shares, an unlimited number of thirty separate classes of preferred shares and an unlimited number of exchangeable shares, issuable in series, of which an unlimited number of Series A Exchangeable Shares (the "Exchangeable Shares") are authorized.  EEC Trust is the sole holder of all of  the issued and outstanding common shares and preferred shares of Enterra.

Common Shares

Each common share entitles its holder to receive notice of and to attend all meetings of the shareholders of Enterra and to one vote at such meetings.  The holders of common shares will be, at the discretion of the Enterra Board and subject to applicable legal restrictions and to certain preferences of holders of Exchangeable Shares and preferred shares, entitled to receive any dividends declared by the Enterra Board on the common shares to the exclusion of the holders of Exchangeable Shares, subject to the proviso that no dividends shall be paid on the common shares unless all declared dividends on the outstanding Exchangeable Shares and any other shares having priority over the common shares with respect to the payment of dividends have been paid in full.  The holders of common shares will be entitled to share equally in any distribution of the assets of Enterra upon the liquidation, dissolution, bankruptcy or winding up of Enterra or other distribution of its assets among its shareholders for the purpose of winding up its affairs.  Such participation is subject to the rights, privileges, restrictions and conditions attaching to the Exchangeable Shares and any other shares having priority over the common shares.  As of December 31, 2003, two common shares were issued and outstanding and held by EEC Trust.

Preferred Shares

Enterra has created and authorized for issuance thirty classes of preferred shares.  The preferred shares can be redeemed at any time by Enterra or at the request of the holder.  Preferred shares of each class will rank prior to the common shares and to the Exchangeable Shares with respect to the payment of dividends, if any, that have been declared and the distribution of assets in the event of the liquidation, dissolution or winding up of Enterra.  As of December 31, 2003, an aggregate of 116,968,687 preferred shares(Classes 1 through 30) were outstanding and held by EEC Trust.

Exchangeable Shares

The following is a summary description of the material provisions of the Exchangeable Shares and the related ancillary and indirect rights of holders of Exchangeable Shares under the terms of the Voting and Exchange Trust Agreement and the Support Agreement.  This summary is qualified in its entirety by reference to the full text of (i) the Exchangeable Share Provisions, (ii) the Support Agreement, and (iii) the Voting and Exchange Trust Agreement.

Each Exchangeable Share has economic rights (including the right to have the Exchange Ratio adjusted to account for Distributions paid to Unitholders) and voting attributes (through the benefit of the Special Voting Right granted to the Voting and Exchange Trust Agreement Trustee) equivalent to those of the Trust Units into which they are exchangeable from time to time.  In addition, holders of Exchangeable Shares have the right to receive Trust Units at any time in exchange for their Exchangeable Shares, on the basis of the Exchange Ratio in effect at the time of the exchange.  Fractional Trust Units will not be delivered on any exchange of Exchangeable Shares.  In the event that the Exchange Ratio in effect at the time of an exchange would otherwise entitle a holder of Exchangeable Shares to a fractional Trust Unit, the number of Trust Units to be delivered will be rounded down to the nearest whole number of Trust Units.  Holders of Exchangeable Shares do not receive cash Distributions from the Trust or Enterra.  Rather, the Exchange Ratio is adjusted to account for Distributions paid to Unitholders.  As of December 31, 2003, 1,995,596 Exchangeable Shares were outstanding.

Ranking

The Exchangeable Shares rank rateably with shares of any other series of exchangeable shares of Enterra and prior to the common shares and any other shares ranking junior to the Exchangeable Shares with respect to the payment of dividends, if any, that have been declared and the distribution of assets in the event of the liquidation, dissolution or winding up of Enterra.

Dividends

Holders of Exchangeable Shares are entitled to receive cash dividends if, as and when declared by the Enterra Board.  Enterra anticipates that it may from time to time declare dividends on the Exchangeable Shares up to but not exceeding any cash Distributions on the Trust Units into which such Exchangeable Shares are exchangeable.  In the event that any such dividends are paid, the Exchange Ratio will be correspondingly reduced to reflect such dividends.

Certain Restrictions

Enterra will not, without obtaining the approval of the holders of the Exchangeable Shares as set forth below under the subheading "Amendment and Approval":

(a)

pay any dividend on the common shares or any other shares ranking junior to the Exchangeable Shares, other than stock dividends payable in common shares or any other shares ranking junior to the Exchangeable Shares;

(b)

redeem, purchase or make any capital distribution in respect of the common shares or any other shares ranking junior to the Exchangeable Shares;

(c)

redeem or purchase any other shares of Enterra ranking equally with the Exchangeable Shares with respect to the payment of dividends or on any liquidation distribution; or

(d)

amend the articles or by laws of Enterra in any manner that would affect the rights or privileges of the holders of Exchangeable Shares.

The restrictions in (a), (b) and (c) above shall not apply if all declared dividends on the outstanding Exchangeable Shares shall have been paid in full.

Liquidation or Insolvency of Enterra

In the event of the liquidation, dissolution or winding up of Enterra or any other proposed distribution of the assets of Enterra among its shareholders for the purpose of winding up its affairs, a holder of Exchangeable Shares will be entitled to receive from Enterra, in respect of each such Exchangeable Share, that number of Trust Units equal to the Exchange Ratio as at the effective date of such event.

Upon the occurrence of such an event, the Trust and Exchangeco will each have the overriding right to purchase all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by the Trust or any subsidiary of the Trust) at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time and, upon the exercise of this right, the holders thereof will be obligated to sell such Exchangeable Shares to the Trust or Exchangeco, as applicable.  This right may be exercised by either the Trust or Exchangeco.

Upon the occurrence of an Insolvency Event, the Voting and Exchange Trust Agreement Trustee on behalf of the holders of the Exchangeable Shares will have the right to require the Trust or Exchangeco to purchase any or all of the Exchangeable Shares then outstanding and held by such holders at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time, as described under the subheading "Voting and Exchange Trust Agreement - Optional Exchange Right".

Automatic Exchange Right on Liquidation of the Trust

The Voting and Exchange Trust Agreement provides that in the event of a Trust liquidation event, as described below, the Trust or Exchangeco will be deemed to have purchased all outstanding Exchangeable Shares and each holder of Exchangeable Shares will be deemed to have sold their Exchangeable Shares immediately prior to such Trust liquidation event at a purchase price per Exchangeable Share to be satisfied by the issuance or delivery, as the case may be, of that number of Trust Units equal to the Exchange Ratio at such time.  "Trust liquidation event" means:

(a)

any determination by the Trust to institute voluntary liquidation, dissolution or winding up proceedings in respect of the Trust or to effect any other distribution of assets of the Trust among the Unitholders for the purpose of winding up its affairs; or

(b)

the earlier of, the Trust’s receiving notice of and the Trust’s otherwise becoming aware of, any threatened or instituted claim, suit, petition or other proceedings with respect to the involuntary liquidation, dissolution or winding up of the Trust or to effect any other distribution of assets of the Trust among the Unitholders for the purpose of winding up its affairs in each case where the Trust has failed to contest in good faith such proceeding within 30 days of becoming aware thereof.

Retraction of Exchangeable Shares by Holders and Retraction Call Right

Subject to the Retraction Call Right of the Trust and Exchangeco described below, a holder of Exchangeable Shares will be entitled at any time to require Enterra to redeem any or all of the Exchangeable Shares held by such holder for a retraction price (the "Retraction Price") per Exchangeable Share equal to the value of that number of Trust Units equal to the Exchange Ratio as at the date of redemption (the "Retraction Date"), to be satisfied by the delivery of such number of Trust Units.  Fractional Trust Units will not be delivered.  Any amount payable on account of the Retraction Price that includes a fractional Trust Unit will be rounded down to the nearest whole number of Trust Units.  Holders of the Exchangeable Shares may request redemption by presenting to Enterra or the transfer agent for the Exchangeable Shares a certificate or certificates representing the number of Exchangeable Shares the holder desires to have redeemed, together with a duly executed retraction request and such other documents as may be reasonably required to effect the redemption of the Exchangeable Shares.  Subject to extension as described below, the redemption will become effective on the Retraction Date, which will be seven business days after the date on which Enterra or the transfer agent receives the retraction notice.  Unless otherwise requested by the holder and agreed to by Enterra, the Retraction Date will not occur on such seventh business day if such day would occur between any Distribution Record Date and the Distribution Payment Date that corresponds to such Distribution Record Date.  In this case, the Retraction Date will instead occur on such Distribution Payment Date.  The reason for this is to ensure that the Exchange Ratio used in connection with such redemption is increased to account for the Distribution.

When a holder requests Enterra to redeem the Exchangeable Shares, the Trust and Exchangeco will have an overriding right (the "Retraction Call Right") to purchase on the Retraction Date all but not less than all of the Exchangeable Shares that the holder has requested Enterra to redeem at a purchase price per Exchangeable Share equal to the Retraction Price, to be satisfied by the delivery of that number of Trust Units equal to the Exchange Ratio at such time.  At the time of a Retraction Request by a holder of Exchangeable Shares, Enterra will immediately notify the Trust and Exchangeco.  The Trust or Exchangeco must then advise Enterra within two business days as to whether the Retraction Call Right will be exercised.  A holder may revoke his or her Retraction Request at any time prior to the close of business on the last business day immediately preceding the Retraction Date, in which case the holder’s Exchangeable Shares will neither be purchased by the Trust or Exchangeco nor be redeemed by Enterra.  If the holder does not revoke his or her Retraction Request, the Exchangeable Shares that the holder has requested Enterra to redeem will on the Retraction Date be purchased by the Trust or Exchangeco or redeemed by Enterra, as the case may be, in each case at a purchase price per Exchangeable Share equal to the Retraction Price.  In addition, a holder of Exchangeable Shares may elect to instruct the Voting and Exchange Trust Agreement Trustee to exercise the optional exchange right (the "Optional Exchange Right") to require the Trust or Exchangeco to acquire such holder’s Exchangeable Shares in circumstances where neither the Trust nor Exchangeco have exercised the Retraction Call Right.  See "Exchangeable Shares - Voting and Exchange Trust Agreement - Optional Exchange Right".

The Retraction Call Right may be exercised by either the Trust or Exchangeco.  If, as a result of solvency provisions of applicable law, Enterra is not permitted to redeem all Exchangeable Shares tendered by a retracting holder, Enterra will redeem only those Exchangeable Shares tendered by the holder as would not be contrary to such provisions of applicable law.  The holder of any Exchangeable Shares not redeemed by Enterra will be deemed to have required the Trust to purchase such unretracted Exchangeable Shares in exchange for Trust Units on the Retraction Date pursuant to the Optional Exchange Right.  See "Voting and Exchange Trust Agreement - Optional Exchange Right".

Redemption of Exchangeable Shares

Subject to applicable law and the Redemption Call Right of the Trust and Exchangeco, Enterra:

(a)

will, on November 25, 2006 subject to extension of such date by the Enterra Board (the "Automatic Redemption Date"), redeem all but not less than all of the then outstanding Exchangeable Shares for 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 (as that term is defined below) (the "Redemption Price"), to be satisfied by the delivery of such number of Trust Units; and

(b)

may, at any time when the aggregate number of issued and outstanding Exchangeable Shares is less than 1,000,000 (other than Exchangeable Shares held by the Trust and its subsidiaries and as such shares may be adjusted from time to time) (the "De Minimus Redemption Date" and, collectively with the Automatic Redemption Date, a "Redemption Date"), redeem all but not less than all of the then outstanding Exchangeable Shares for the Redemption Price per Exchangeable Share (unless contested in good faith by the Trust), to be satisfied by the delivery of such number of Trust Units.

Enterra will, at least 45 days prior to any Redemption Date, provide the registered holders of the Exchangeable Shares with written notice of the prospective redemption of the Exchangeable Shares by Enterra.

The Trust and Exchangeco will have the right (the "Redemption Call Right"), notwithstanding a proposed redemption of the Exchangeable Shares by Enterra on the applicable Redemption Date, pursuant to the Exchangeable Share Provisions, to purchase on any Redemption Date all but not less than all of the Exchangeable Shares then outstanding (other than Exchangeable Shares held by the Trust or its subsidiaries) in exchange for the Redemption Price per Exchangeable Share and, upon the exercise of the Redemption Call Right, the holders of all of the then outstanding Exchangeable Shares will be obliged to sell all such shares to the Trust or Exchangeco, as applicable.  If either the Trust or Exchangeco exercises the Redemption Call Right, then Enterra’s right to redeem the Exchangeable Shares on the applicable Redemption Date will terminate.  The Redemption Call Right may be exercised by either the Trust or Exchangeco.

Voting Rights

Except as required by applicable law, the holders of the Exchangeable Shares are not entitled as such to receive notice of or attend any meeting of the shareholders of Enterra or to vote at any such meeting.  Holders of Exchangeable Shares will have the notice and voting rights respecting meetings of the Trust that are provided in the Voting and Exchange Trust Agreement.  See "Voting and Exchange Trust Agreement - Voting Rights".

Amendment and Approval

The rights, privileges, restrictions and conditions attaching to the Exchangeable Shares may be changed only with the approval of the holders thereof.  Any such approval or any other approval or consent to be given by the holders of the Exchangeable Shares will be sufficiently given if given in accordance with applicable law and subject to a minimum requirement that such approval or consent be evidenced by a resolution passed by not less than two thirds of the votes cast thereon (other than shares beneficially owned by the Trust, or any of its subsidiaries and other affiliates) at a meeting of the holders of the Exchangeable Shares duly called and held at which holders of at least 10% of the then outstanding Exchangeable Shares are present in person or represented by proxy.  In the event that no such quorum is present at such meeting within one half hour after the time appointed therefor, then the meeting will be adjourned to such place and time (not less than ten days later) as may be determined at the original meeting and the holders of Exchangeable Shares present in person or represented by proxy at the adjourned meeting will constitute a quorum thereat and may transact the business for which the meeting was originally called.  At the adjourned meeting, a resolution passed by the affirmative vote of not less than two thirds of the votes cast thereon (other than shares beneficially owned by the Trust or any of its subsidiaries and other affiliates) will constitute the approval or consent of the holders of the Exchangeable Shares.

Actions by the Trust under the Support Agreement and the Voting and Exchange Trust Agreement

Under the Exchangeable Share Provisions, Enterra has agreed to take all such actions and do all such things as are necessary or advisable to perform and comply with its obligations under, and to ensure the performance and compliance by the Trust and Exchangeco with its obligations under, the Support Agreement and the Voting and Exchange Trust Agreement.

Non Resident and Tax Exempt Holders

Exchangeable Shares will not be issued to persons who are Non-Residents or who are exempt from tax under Part I of the Tax Act.

Voting And Exchange Trust Agreement

Voting Rights

In accordance with the Voting and Exchange Trust Agreement, the Trust issued a Special Voting Right to Olympia Trust Company, the Voting and Exchange Trust Agreement Trustee, for the benefit of the holders (other than the Trust and Exchangeco) of the Exchangeable Shares.  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 (rounded down to the nearest whole number) 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.  With respect to any written consent sought from the Unitholders, each vote attached to the Special Voting Right is exercisable in the same manner as set forth above.

Each holder of an Exchangeable Share on the record date for any meeting at which Unitholders are entitled to vote will be entitled to instruct the Voting and Exchange Trust Agreement Trustee to exercise that number of votes attached to the Special Voting Right which relate to the Exchangeable Shares held by such holder.  The Voting and Exchange Trust Agreement Trustee will exercise each vote attached to the Special Voting Right only as directed by the relevant holder and, in the absence of instructions from a holder as to voting, will not exercise such votes.

The Voting and Exchange Trust Agreement Trustee will send to the holders of the Exchangeable Shares the notice of each meeting at which the Unitholders are entitled to vote, together with the related meeting materials and a statement as to the manner in which the holder may instruct the Voting and Exchange Trust Agreement Trustee to exercise the votes attaching to the Special Voting Right, at the same time as the Trust sends such notice and materials to the Unitholders.  The Voting and Exchange Trust Agreement Trustee will also send to the holders copies of all information statements, interim and annual financial statements, reports and other materials sent by the Trust to the Unitholders at the same time as such materials are sent to the Unitholders.  To the extent such materials are provided to the Voting and Exchange Trust Agreement Trustee by the Trust, the Voting and Exchange Trust Agreement Trustee will also send to the holders all materials sent by third parties to Unitholders, including dissident proxy circulars and tender and exchange offer circulars, as soon as possible after such materials are first sent to Unitholders.

All rights of a holder of Exchangeable Shares to exercise votes attached to the Special Voting Right will cease upon the exchange of all such holder’s Exchangeable Shares for Trust Units.  With the exception of administrative changes for the purpose of adding covenants for the protection of the holders of the Exchangeable Shares, making necessary amendments or curing ambiguities or clerical errors (in each case provided that the board of directors of Exchangeco and Enterra are of the opinion that such amendments are not prejudicial to the interests of the holders of the Exchangeable Shares), the Voting and Exchange Trust Agreement may not be amended without the approval of the holders of the Exchangeable Shares.

Optional Exchange Right

Upon the occurrence and during the continuance of:

(a)

an Insolvency Event; or

(b)

circumstances in which the Trust or Exchangeco may exercise a 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 Voting and Exchange Trust Agreement Trustee to exercise the Optional Exchange Right 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.  Immediately upon the occurrence of (i) an Insolvency Event, (ii) any event which will, with the passage of time or the giving of notice, become an Insolvency Event, or (iii) the election by the Trust and Exchangeco not to exercise a call right which is then exercisable by the Trust and Exchangeco, Enterra, the Trust or Exchangeco will give notice thereof to the Voting and Exchange Trust Agreement Trustee.  As soon as practicable thereafter, the Voting and Exchange Trust Agreement Trustee will then notify each affected holder of Exchangeable Shares (who has not already provided instructions respecting the exercise of the Optional Exchange Right) of such event or potential event and will advise such holder of its rights with respect to the Optional Exchange Right.

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 at the day of closing of the purchase and sale of such Exchangeable Share under the Optional Exchange Right (the "Exchange Price").

If, as a result of solvency provisions of applicable law, Enterra is unable to redeem all of a holder’s Exchangeable Shares which 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.

Support Agreement

The Trust Support Obligation

Under the Support Agreement, the Trust agrees that:

(a)

the Trust 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; and

(b)

the Trust 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;

(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 or the approval of holders of Exchangeable Shares has been obtained.

In addition, 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 administrative changes for the purpose of adding covenants for the protection of the holders of the Exchangeable Shares, making certain necessary amendments or curing ambiguities or clerical errors (in each case provided that the Enterra Board and the Trustee are of the opinion that such amendments are not prejudicial to the interests of the holders of the Exchangeable Shares), the Support Agreement may not be amended without the approval of the holders of the Exchangeable Shares.

Under the Support Agreement, the Trust will agree to not 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 (including any approval sought from such holders in respect of matters arising under the Support Agreement).

The Series A Notes

Terms and Issue of Series A Notes

The principal amount of the Series A Notes issued pursuant to the Arrangement was $125,000,000. The Series A Notes are subordinated to senior indebtedness of Enterra and bear interest from the date of issue at 14% per annum.  Interest is be payable for each month during the term on the 15th day of the month following such month.  

The maturity date for the Series A Notes ("Maturity Date") November 24, 2024 or such later date as may be determined by the Enterra Board, provided that the Maturity Date will not extend beyond November 25, 2033.  Pursuant to the terms of the Note Indenture, Enterra is not required to make any payment in respect of principal until the Maturity Date and is not permitted to make payments against the principal amount of the Series A Notes outstanding at any time prior to the period beginning 180 days prior to the Maturity Date.  In the period commencing 180 days prior to the Maturity Date and ending on the Maturity Date, Enterra will be entitled to redeem, in whole but not in part, the Series A Notes, provided that no Series A Notes may be redeemed while any senior indebtedness of Enterra is outstanding.

Principal and interest on the Series A Notes (and any additional notes issued pursuant to the Note Indenture) is payable in lawful money of Canada directly to each holder of a Series A Note.  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 (each a "Deferral Period") 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 "Share Payment Election").

Ranking

The Series A Notes are unsecured debt obligations of Enterra and are subordinated to all senior indebtedness of Enterra.

Events of Default

The Note Indenture provides that any one or more of the following described events which has occurred and is continuing constitutes an event of default with respect to the Series A Notes:

(a)

failure for 30 days to pay interest on the Series A Notes in cash or pursuant to the Share Payment Election when due and which failure continues beyond the end of the Deferral Period, if any, in respect thereof, as last extended;

(b)

failure to pay principal on the Series A Notes in cash or pursuant to the Share Payment Election when due whether at maturity, upon redemption, by acceleration on default or otherwise;

(c)

acceleration of any senior indebtedness of Enterra or any indebtedness of any material subsidiary of Enterra exceeding $25 million;

(d)

failure to observe or perform any other covenant contained in the Note Indenture for 60 days after written notice thereof to Enterra from the Note Trustee or the holders of at least 25% in principal amount of the outstanding Series A Notes;

(e)

certain events of bankruptcy, insolvency or reorganization of Enterra, or of a material subsidiary of Enterra, under a bankruptcy or insolvency law; or

(f)

Enterra or any of its material subsidiaries ceasing to carry on, in the ordinary course, its business or a material part thereof.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government.  It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas companies and trusts of similar size.  All current legislation is a matter of public record, and we are unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing – Natural Gas

In Canada, the price of natural gas sold intraprovincially or to the United States is determined by negotiation between buyers and sellers.  Natural gas exported from Canada is subject to regulation by the National Energy Board ("NEB") and the government of Canada.  Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the NEB and the government of Canada.  Natural gas exports for a term of less than two years requires a general short term export license while terms greater than two years require a specific license for the particular gas sold (in quantities of not more than 30,000 cubic metres/d).  Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas, which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Pricing and Marketing – Oil

In Canada, producers of oil negotiate sales contracts directly with oil purchasers.  Oil prices are primarily based on worldwide supply and demand.  The specific price paid depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance.  Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, provided that an order approving any such export has been obtained from the 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 licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

The North American Free Trade Agreement

On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of Canada, the U.S. and Mexico became effective.  The NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement.  In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36-month period), (ii) impose an export price higher than the domestic price; and (iii) disrupt normal channels of supply.  All three countries are prohibited from imposing minimum export or import price requirements.

The NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes.  The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes, and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

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.  In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands, respectively.  The royalty regime is a significant factor in the profitability of oil 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.  Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and 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 Canada, Alberta, British Columbia and Saskatchewan have established incentive programs which have included royalty-rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects.  These programs reduce the amount of Crown royalties otherwise payable.

Environmental Regulation

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation.  Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced in association with certain oil and natural gas industry operations, and can affect the location of wells and facilities and the extent to which exploration and development is permitted.  In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities.  A breach of that legislation may result in the imposition of fines or issuance of clean-up orders.

We are committed to meeting its 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.  Our internal procedures are designed to ensure that the environmental aspects of new developments are taken into account prior to proceeding.  We believes that we is in material compliance with applicable environmental laws and regulations.

Kyoto Protocol

In December of 2002, Canada became a signatory to the Kyoto Protocol.  The implementation of this plan has not been fully defined by the federal government.  Until an implementation plan is developed it is impossible to assess the impact on specific industries and individual businesses within an industry.  It is generally believed that the oil and gas industry, as a major producer of carbon dioxide (as a necessary by-product and emission of hydrocarbon production), will bear a disproportionately large share of the anticipated cost of implementation.

RISK FACTORS

Set out below are certain risk factors that could materially adversely affect our cash flow, operating results, financial condition or the business of our operating subsidiaries. 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 labour 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 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. Funds used for such purposes will not be payable to the Trust. 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.

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 unfavourable 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 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;

·

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.

If we expand our operations beyond oil and natural gas production in western Canada, we may 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 are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside this geographic area. 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 may present 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.

Some of our properties are not operated by us 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, 2003, approximately 3% 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 wilful misconduct.

Delays in business operations could adversely affect distributions to Unitholders and the market price of our Trust Units.

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 reduces 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. 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.

We have a working capital deficiency at December 31, 2003; 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, 2003, we had a working capital deficiency of $38.2 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 2004.

Our assets are highly leveraged. Any material change in our liquidity could impair our ability to pay dividends and could adversely affect the value of your investment.

We carry a high amount of debt relative to 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 centre representing Enterra’s activity which is undertaken exclusively in 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. Capitalized costs, net of accumulated depletion and depreciation, are limited to estimated future net revenues from proven reserves, based on year-end prices, undiscounted, less estimated future abandonment and site restoration costs, general and administrative expenses, financing costs and income taxes. Estimated future abandonment and site restoration costs are provided for over the life of proven reserves on a unit-of-production basis. The annual charge is included in depletion and depreciation expense and actual abandonment and site restoration costs are charged to the provision as incurred. The amounts recorded for depletion and depreciation and the provision for future abandonment and site restoration costs are based on estimates of proven reserves and future costs. The recoverable value of capital assets is based on a number of factors including the estimated proven reserves and future costs. By their nature, these estimates are subject to measurement uncertainty and the impact on financial statements of future periods could be material.

We perform a cost recovery ceiling test which limits net capitalized costs to the undiscounted estimated future net revenue from proven oil and gas reserves plus the cost of unproven properties less impairment, using year-end prices or average prices in that year, if appropriate. In addition, the value is further limited by including financing costs, administration expenses, future abandonment and site restoration costs and income taxes. Under U.S. GAAP, companies using the "full cost" method of accounting for oil and gas producing activities perform a ceiling test using discounted estimated future net revenue from proven oil and gas reserves with 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 Old Enterra realized a U.S. GAAP ceiling test write-down of Cdn.$17,500,000, after tax. There were no such write-downs required at December 31, 2002 or 2003.

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 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 CCRA 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 CCRA will agree. If CCRA 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.

There would be material adverse tax consequences if the Trust lost its status as a mutual fund trust under the Tax Act.

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.

·

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 Canada Customs and Revenue Agency.

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.

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 or Enterra. 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.

Due to uncertainties in the law relating to investment trusts, there is a risk that a Unitholder could be held personally liable for obligations of the Trust in respect of contracts or undertakings which the Trust enters 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 operate to avoid Unitholder liability. Notwithstanding attempts to limit Unitholder liability, Unitholders may not be protected from liabilities of the Trust to the same extent that a shareholder is protected from the liabilities of a corporation. 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 is 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 in respect of the Enterra Debt. 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 Enterra Debt. 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 Enterra Debt 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 Enterra Debt 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.

DISTRIBUTIONS

Our distributions are highly dependent on commodity prices, primarily the price of crude oil. We mitigate this risk by hedging some of our oil production. A detailed schedule of our hedging history and current position is set forth under "Description of the Business of the Trust – Risk Management and Marketing – Commodity Price Risk".

Although the payout ratio will vary significantly from month to month, our objective is to pay to Unitholders approximately 80% of the Trust's operating cash flow over the long term.  The payout ratio for the first three months of 2004 was 82.43%.

We have currently set the level of monthly cash distributions at USD $0.11 per Trust Unit.  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".

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(1)	$0.10
January	$0.10
February	$0.10
March	$0.11
April	$0.11

Note:

(1)

This distribution was the first cash distribution of the Trust following the completion of the Arrangement.

The Trust makes cash distributions on the 15th day of each month (or the first business day thereafter) to Unitholders of record on the immediately preceding distribution record date.

MARKET FOR SECURITIES

Trading Price and Volume

The outstanding Trust Units are traded on the TSX under the trading symbol "ENT.UN" and on the Nasdaq under the symbol "EENC". The following table sets forth the price range and trading volume of the Trust Units as reported by the TSX and the Nasdaq for the periods indicated.

	TSX			Nasdaq
	High ($)	Low ($)	Volume (000's)	High (US$)	Low (US$)	Volume (000's)
2003
November(1)	12.50	12.50	1	10.44	9.50	142
December	15.08	11.51	134	5.815	4.625	5,782
2004
January	17.25	13.01	236	6.295	5.05	5,897
February	17.80	15.74	270	6.70	5.825	4,447
March	21.00	17.00	138	16.19	12.69	5,761
April	20.70	16.05	138,969	15.87	11.02	6,125
May 1 to 10	17.58	15.77	9,600	12.60	11.21	1,135

Note:

(2)

The Trust Units commenced trading on the TSX and Nasdaq on November 28, 2003.

Prior Sales

Pursuant to the Arrangement, on November 25, 2003 the Trust and Enterra issued 18,951,556 Trust Units and 2,000,000 Exchangeable Shares in exchange for all of the issued and outstanding shares of Old Enterra.  From November 25, 2003 to December 31, 2003, 4,404 Trust Units were issued upon the exchange of Exchangeable Shares.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings material to the Trust to which we are a party or in respect of which any of our properties are subject, nor are there any such proceedings known to be contemplated.  

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of Enterra's directors or executive officers, nor any person who beneficially owns directly or indirectly or exercises control or direction over securities carrying more than 10% of the voting rights attaching to the Trust Units, nor any known associate or affiliate of these persons, had any material interest, direct or indirect in any transaction since the commencement of the Trust’s last completed financial year which has materially affected Enterra.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our Trust Units is Olympia Trust Company in Calgary, Alberta.

MATERIAL CONTRACTS

Set out below are agreements that may be considered material to us entered into in 2003:

1.

Trust Indenture.  See "Additional Information Respecting the Trust".

2.

Note Indenture.  See "Additional Information Respecting Enterra – Series A Notes".

3.

Administration Agreement between the Trust and Enterra.  See "Additional Information Respecting the Trust – Delegation of Authority, Administration and Trust Governance".

5.

Support Agreement.  See "See Additional Information Respecting Enterra – Support Agreement".

6.

Voting and Exchange Trust Agreement.  See " See Additional Information Respecting Enterra –Voting and Exchange Trust Agreement"

INTERESTS OF EXPERTS

Reserve estimates contained herein are derived from reserve reports prepared by McDaniel.  As of the date hereof, McDaniel, as a group, does not beneficially own, directly or indirectly, any Trust Units.

AUDIT COMMITTEE

General

Enterra has established an Audit Committee (the "Audit Committee") comprised of three members:  H.S. (Scoby) Hartley, Norman Wallace and William Sliney, each of whom is considered "independent" and "financially literate" within the meaning of Multilateral Instrument 52-110 – Audit Committees.

Mandate of the Audit Committee

The mandate of the Audit Committee is to assist the Enterra Board in its oversight of the integrity of the financial and related information of the Trust, Enterra and their subsidiaries and related entities, including the financial statements, internal controls and procedures for financial reporting and the processes for monitoring compliance with legal and regulatory requirements.  In doing so, the Audit Committee oversees the audit efforts of our external auditors and, in that regard, is empowered to take such actions as it may deem necessary to satisfy itself that our external auditors are independent of us.  It is the objective of the Audit Committee to have direct, open and frank communications throughout the year with management, other Committee chairmen, the external auditors, and other key committee advisors or Enterra staff members as applicable.

The Audit Committee's function is oversight.  Management of Enterra is responsible for the preparation, presentation and integrity of the financial statements of the Trust and Enterra.  Management is responsible for maintaining appropriate accounting and financial reporting principles and policy and internal controls and procedures that provide for compliance with accounting standards and applicable laws and regulations.

While the Audit Committee has the responsibilities and powers set forth above, it is not the duty of the Audit Committee to plan or conduct audits or to determine whether the financial statements of the Trust and Enterra are complete and accurate and are in accordance with generally accepted accounting principles.  This is the responsibility of management and the external auditors, on whom the members of the Committee are entitled to rely upon in good faith.

The Charter of the Audit Committee is attached hereto as Appendix "B".

Relevant Education and Experience of Audit Committee Members

The following is a brief summary of the education or experience of each member of the Audit Committee that is relevant to the performance of his responsibilities as a member of the Audit Committee, including any education or experience that has provided the member with an understanding of the accounting principles used by us to prepare our annual and interim financial statements.

Name of Audit Committee Member	Relevant Education and Experience
H.S. (Scoby) Hartley	Mr. Hartley has been a director and officer of  numerous public and private companies in the energy and construction sectors.  He is well versed in understanding financial and reserves information.  Mr. Hartley holds a Bachelor of Science in Geology from Texas Tech university.
Norman Wallace	Mr. Wallace is the founder, director and CEO of a large private construction company located in Saskatchewan with overseas operations.  He is familiar with financial information as presented in audited financial statements and annual and interim reports.  Mr Wallace holds a Bachelor of Commerce degree form the university of Saskatchewan..
William Sliney	Mr Sliney is the chairman of the Audit Committee.  He has held various executive positions with public companies in the U.S., the most recent as President of PASW, Inc. and as Chief Financial Officer of Legacy Software.  Mr. Sliney is a CPA and holds a  Masters degree in Business Administration from UCLA.  He is experienced in dealing with public, audited financial information and is familiar with current accounting and auditing issues.

External Auditor Services Fees

For the year ended December 31, 2003 and 2002, Deloitte & Touche LLP and its affiliates were paid approximately $150,100 and $95,500, respectively, as detailed below:

		Year ended December 31
		2003		2002(2)
Deloitte & Touche LLP
	Audit fees(1)	$	150,100	$	95,500
	Audit-related fees	$		$
	Tax Fees	$		$
	All Other Fees	$		$
	Total	$	150,100	$	95,500

Note:

(1)

The audit fees include the costs related to the annual audit and services related to public financings and related reporting to regulators.

(2)

Includes fees paid to KPMG LLP, auditors of Old Enterra for a portion of 2002.

The Chairman of the Audit Committee has the authority to pre-approve non-audit services which may be required from time to time.

Audit Committee Oversight

At no time since the commencement of our most recently completed financial year, has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the board of directors of Enterra.

ADDITIONAL INFORMATION

Additional information in respect of the Trust may be found on SEDAR at www.sedar.com.  The Trust will provide to any person, upon request to the Corporate Secretary of Enterra, on behalf of the Trust:

1.

when the securities of the Trust are in the course of a distribution pursuant to a short form prospectus or a preliminary short form prospectus has been filed in respect of a proposed distribution of its securities:

(a)

one copy of the Annual Information Form of the Trust, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form;

(b)

one copy of the financial statements of Enterra for the completed financial year ended December 31, 2003, together with the accompanying report of the auditors thereon, as well as one copy of any interim financial statements of the Trust subsequent to December 31, 2003;

(c)

one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus that are not required under paragraphs (a), (b), or (c) above; or

2.

at any time, one copy of any of the document referred to in paragraphs 1(a), (b), and (c) above, provided that the Trust may require the payment of a reasonable charge if the request is made by a person who is not a security holder of the Trust.

Additional information related to the remuneration and indebtedness of the directors and officers of Enterra, and the principal holders of Trust Units and rights to purchase Trust Units, where applicable, is contained in the management information circular in respect of the next annual meeting of Unitholders of the Trust.  Additional financial information is provided in the audited financial statements and MD&A of the Trust for the year ended December 31, 2003.

Additional copies of this Annual Information Form maybe obtained from Enterra.  Please contact:

Enterra Energy Trust
c/o Enterra Energy Corp.
2600, 500 - 4th Avenue SW.
Calgary, Alberta T2P 2V6

Telephone:

(403) 263-0262
Fax:

(403) 294-1197

APPENDIX "A" -
INFORMATION CONCERNING THE ACQUISITION OF PROPERTIES IN EAST CENTRAL ALBERTA

Principal Properties

The East Central Alberta (“East Central”) properties acquired by Enterra from NCE Petrofund Corp. are included in townships 33 to 46 and ranges 03 to 14W4.  Working interest are high, ranging from 48% to 1005.  Areas include Wainwright, Alliance, Soapy/Sounding Lake and Monitor/Loyalist.  These properties include infrastructure, year round drilling and shallow, multi-target oil and gas zones.  Oil is conventionally produced and ranges from medium crude, 22^o API Sparky oil at Wainwright, to light crude, 34^o API Viking oil at Alliance.  Additional development opportunities include both gas and oil targets.

Oil and Natural Gas Reserves

The table below is a summary of the crude oil, NGL and natural gas reserves for the East Central properties and the present value of future net cash flow associated with such reserves (based on constant dollar and escalating dollar price assumptions) as evaluated in the independent engineering report dated May 4, 2004, effective as of December 31, 2003, prepared by GLJ relating to all of the East Central oil and natural gas properties (the "GLJ Report").  The reserves estimates have been prepared in accordance with the definitions set out in National Instrument 51-101.  

All evaluations of future net production revenue set forth in the tables below are stated prior to the provision for income taxes and general and administrative costs, but after overriding and lessor royalties, Crown royalties, freehold royalties, mineral taxes, direct lifting costs, normal allocated overhead and future capital investments. It should not be assumed that the discounted future net production revenue estimated by the GLJ Report represents the fair market value of the reserves.  Other assumptions relating to the costs, prices for future production and other matters are included in the GLJ Report.  There is no assurance that the future price and cost assumptions used in the GLJ Report will prove accurate and variances could be material.

	Petroleum and Natural Gas Reserves
	Oil		NGLs		Gas
	(Mbbls)		(Mbbls)		(Mmcf)
	Gross	Net	Gross	Net	Gross	Net
Constant Pricing
Proved Producing	2,348.9	2,157.2	32.6	20.6	1,574.0	1,098.0
Proved Developed Non-Producing	9.3	8.9	1.8	1.2	241.0	211.0
Proved Undeveloped	384.3	345.3	2.0	1.4	161.0	113.0
Total Proved	2,742.5	2,511.4	36.4	23.2	1,976.0	1,422.0
Probable	925.1	841.2	29.2	20.0	1,460.0	1,121.0
Total Proved Plus Probable	3,667.6	3,352.6	65.6	43.2	3,436.0	2,543.0
Escalated Pricing
Proved Producing	1,740.8	1,589.7	25.1	15.7	1,243.7	865.4
Proved Developed Non-Producing	6.7	6.4	1.8	1.2	245.3	214.7
Proved Undeveloped	330.7	295.7	1.7	1.1	133.0	94.3
Total Proved	2,078.2	1,891.8	28.6	18.0	1,622.0	1,174.4
Probable	800.5	732.5	25.9	17.8	1,051.0	921.6
Total Proved Plus Probable	2,878.7	2,624.3	54.5	35.8	2,673.0	2,096.0

	Present Value of Future Net Production Revenue ($thousands) Discounted at the rate of
	Undiscounted	10%	15%	20%
Constant Pricing
Proved Producing	29,101	21,196	18,801	16,966
Proved Developed Non-Producing	966	749	669	602
Proved Undeveloped	4,710	2,800	2,304	1,937
Total Proved	34,777	24,745	21,774	19,505
Probable	14,217	8,631	7,093	5,957
Total Proved Plus Probable	48,994	33,376	28,867	25,462
Escalated Pricing
Proved Producing	15,354	12,159	11,122	10,295
Proved Developed Non-Producing	693	543	488	441
Proved Undeveloped	2,134	1,068	813	631
Total Proved	18,181	13,770	12,423	11,367
Probable	6,843	4,262	3,534	2,983
Total Proved Plus Probable	25,024	18,032	15,957	14,350

Notes:

3.

The crude oil reserves estimates presented in the GLJ Report have been based on the definitions and guidelines prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society) as presented in the COGE Handbook. A summary of those definitions is presented below.

4.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

5.

Reserves are classified according to the degree of certainty associated with the estimates:

(a)

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b)

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

(c)

Other criteria that must also be met for the categorization of reserves are provided in Section 5.5 of the COGE Handbook.

6.

Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories:

(a)

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and nonproducing.

(b)

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(c)

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(d)

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

(e)

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest- level sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(f)

at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;

(g)

at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and

(h)

at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in Section 5.5.3 of the COGE Handbook.

7.

"Gross Reserves" are the total of the Trust's working and/or royalty interest share before deduction of royalties owned by others.

8.

"Net Reserves" are the total of the Trust's working and/or royalty interest share after deducting the amounts attributable to royalties owned by others.

APPENDIX "B" -
AUDIT COMMITTEE CHARTER

Organization

There shall be a committee of the board of directors to be known as the audit committee. The audit committee shall be composed of directors who are independent of the management of the corporation and are free of any relationship that, in the opinion of the board of directors, would interfere with their exercise of independent judgment as a committee member. For purposes of serving as a member of the audit committee, directors being considered shall comply with the Independent Director and Audit Committee requirements pursuant to NASD Market Place Rules. Examples of such relation-ships include:

•

A director being employed by the corporation or any of its affiliates for the current year or any of the past five years;

•

A director accepting any compensation from the corporation or any of its affiliates other than compensation for board service or benefits under a tax-qualified retirement plan;

•

A director being a member of the immediate family of an individual who is, or has been in any of the past five years, employed by the corporation or any of its affiliates, or predecessors as an executive officer;

•

A director being a partner in, or a controlling shareholder or an executive officer of, any for-profit business organization to which the corporation made, or from which the corporation received, payments that are or have been significant to the corporation or business organization in any of the past five years;

•

A director being employed as an executive of another company where any of the corporation’s executives serves on that company’s compensation committee.

A director who has one or more of these relationships may be appointed to the audit committee, if the board, under exceptional and limited circumstances, determines that membership on the committee by the individual is required by the best interests of the corporation and its shareholders, and the board discloses, in the next annual proxy statement subsequent to such determination, the nature of the relationship and the reasons for that determination.

Statement of Policy

The audit committee shall provide assistance to the corporate directors in fulfilling their responsibility to the shareholders, potential shareholders, and investment community relating to corporate accounting, reporting practices of the corporation, and the quality and integrity of the financial reports of the corporation. In so doing, it is the responsibility of the audit committee to maintain free and open means of communication between the directors, the independent auditors. the internal auditors, and the financial management of the corporation.

Responsibilities

In carrying out its responsibilities, the audit committee believes its policies and procedures should remain flexible, in order to best react to changing conditions and to ensure to the directors and shareholders that the corporate accounting and reporting practices of the corporation are in accordance with all requirements and are of the highest quality. In carrying out these responsibilities, the audit committee will:

•

Review and recommend to the directors the independent auditors to be selected to audit the financial statements of the corporation and its divisions and subsidiaries.

•

Meet with the independent auditors and financial management of the corporation to review the scope of the proposed audit for the current year and the audit procedures to be utilized, and at the conclusion thereof review such audit, including any comments or recommendations of the independent auditors.

•

Review with the independent auditors, the company’s internal auditor, and financial and accounting personnel, the adequacy and effectiveness of the accounting and financial controls of the corporation, and elicit any recommendations for the improvement of such internal control procedures or particular areas where new or more detailed controls or procedures are desirable. Particular emphasis should be given to the adequacy of such internal controls to expose any payments, transactions, or procedures that might be deemed illegal or otherwise improper. Further, the committee periodically should review company policy statements to determine their adherence to the code of conduct.

•

Review the internal audit function of the corporation including the independence and authority of its reporting obligations, the proposed audit plans for the coming year, and the coordination of such plans with the independent auditors.

•

Receive prior to each meeting, a summary of findings from completed internal audits and a progress report on the proposed internal audit plan, with explanations for any deviations from the original plan.

•

Review the financial statements contained in the annual report to shareholders with management and the independent auditors to determine that the independent auditors are satisfied with the disclosure and content of the financial statements to be presented to the shareholders. Any changes in accounting principles should be reviewed.

•

Provide sufficient opportunity for the internal and independent auditors to meet with the members of the audit committee without members of management present. Among the items to be discussed in these meetings are the independent auditors’ evaluation of the corporation’s financial, accounting, and auditing personnel, and the cooperation that the independent auditors received during the course of the audit.

•

Review accounting and financial human resources and succession planning within Enterra.

•

Submit the minutes of all meetings of the audit committee to, or discuss the matters discussed at each committee meeting with, the board of directors.

•

Investigate any matter brought to its attention within the scope of its duties, with the power to retain outside counsel for this purpose if, in its judgment, that is appropriate.

APPENDIX "C" –
REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning herein.

To the board of directors of Enterra Energy Corp. (the "Company"):

1.

We have evaluated the Company’s reserves data as at December 31, 2003.  The reserves data consists of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and

(ii)

the related estimated future net revenue.

2.

The reserves data are the responsibility of the Company's management.  Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluated in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.

Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement.  An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.

4.

The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2003, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Corporation's management.

Description and Preparation Data of Audit/ Evaluation/ Review Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate - $M)
		Audited	Evaluated	Reviewed	Total
December 31, 2003	Canada	$   -	$111,880.6	$   -	$111,880.6

5.

In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.

6.

We have no responsibility to update this evaluation for events and circumstances occurring after their respective preparation date.

7.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above.

(signed)

McDaniel & Associates Consultants Ltd.
Calgary, Alberta

Dated March 31, 2004.

APPENDIX "D" –
REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning herein.

Management of Enterra Energy Trust (the "Corporation") are responsible for the preparation and disclosure, or arranging for the preparation and disclosure of information with respect to the Corporation's oil and gas activities in accordance with securities regulatory requirements.  This information includes reserves data, which consist of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and

(ii)

the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Corporation's reserves data.  The report of the independent qualified reserves evaluator will be filed with the securities regulatory authorities concurrently with this report.

The Reserves Committee of the Board of Directors of the Corporation has:

(a)

reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator;

(b)

met with the independent qualified reserves evaluator  to determine whether any restrictions affected the ability of the independent qualified reserves evaluator   to report without reservation, to inquire whether there had been disputes between the previous independent qualified reserves evaluator and management;

(c)

reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the Board of Directors has reviewed the Corporation’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with Management.  The Board of Directors has, on the recommendation of  the Reserves Committee approved:

(a)

the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b)

the filing of the report of the independent qualified reserves evaluator; and

(c)

the content and filing of this report.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

(signed)

Luc Chartrand
President & Chief Executive Officer

(signed)

Lynn Wiebe
Chief Financial Officer

(signed)

Reg Greenslade
Director

(signed)

Scobey Hartley
Director

May 19, 2004