UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16 UNDER THE

SECURITIES ACT OF 1934

For the Month of May 2004

Commission File Number: 000-32115

ENTERRA ENERGY TRUST
(as successor issuer to Enterra Energy Corp.)

(Translation of registrant’s name into English)

2600, 500-4th Avenue S.W.
Calgary, Alberta, Canada T2P 2V6

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F  x    Form 40-F___

Indicate by check mark whether the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Yes___  No   x  

Indicate by check mark whether the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Yes_____ No   x  

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes       No  x  

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ENTERRA ENERGY TRUST
(Registrant)
By: Enterra Energy Corp.
Administrator of the Trust
By: /s/ Luc Chartrand
Luc Chartrand
President and Chief Executive Officer
Date: May 19, 2004

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ENTERRA ENERGY TRUST

FIRST QUARTER REPORT 2004

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following management’s discussion and analysis ("MD&A") should be read in conjunction with the unaudited interim consolidated financial statements of Enterra Energy Trust ("the Trust") for the period ended March 31, 2004, other financial information included in this quarterly report and with the MD&A and consolidated financial statements contained in the 2003 Annual Report. This MD&A was written as of May 14, 2004. All amounts are stated in Canadian dollars except where otherwise indicated. Natural gas volumes have been converted to a crude oil equivalent using a ratio of 6 mcf to 1 bbl of oil.

Cash flow from operations, expressed before changes in non-cash working capital, is used by the Trust to measure and evaluate operating performance and liquidity. Cash flow from operations does not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles ("GAAP") and therefore may not be comparable with the calculation of similar measures for other companies.

It is management’s view, based on its communications with investors during events like conference calls, webcasts or road shows, that cash flow from operations is most relevant to our investors and unitholders, especially since the Trust’s conversion to an oil and gas income trust. Cash flow from operations is extremely relevant to investors because it is the starting point for setting the monthly distribution level.

Cash flow from operations is reconciled to GAAP earnings in a table included in the MD&A.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This interim report includes forward-looking statements. All statements other than statements of historical facts contained in this interim report, including statements regarding our future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. The words "believe," "may," "will," "estimate," "continue," "anticipate," "intend," "should," "plan," "expect" and similar expressions, as they relate to us, are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends that we believe may affect our financial condition, results of operations, business strategy and financial needs. These forward-looking statements are subject to a number of risks, uncertainties and assumptions described in "Risk Factors" and elsewhere in this interim report.

Other sections of this interim report may include additional factors which could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

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

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OVERVIEW

The Trust’s first quarter as an oil and gas income trust was very successful, with a 21% increase in production. Cash flow from operations was $9.5 million for the quarter or $0.44 on a per unit basis. The Trust established its initial monthly distribution level at US$0.10 per unit, with an increase to US$0.11 per unit declared on March 15 for April production. The Trust acquired properties in East Central Alberta for $19,847,000. This transaction closed on January 30, 2004. Included in the first quarter results are two months of production (February and March) from these properties.

 

PRODUCTION INCOME

Production income decreased by 2% in the three months ended 2004 from $22.0 million in Q1, 2003 to $21.6 million in Q1, 2004. Higher production volumes in the three months ended March 31, 2004 were offset by lower commodity prices in effect during the quarter and by the stronger foreign exchange rate in effect during Q1, 2004 (1.32 on average compared with 1.51 in Q1, 2003). The oil production in 2003 was also more heavily weighted with light crude which commands a better price than medium or heavy crude. Light oil accounted for 80% of Enterra’s oil production in 2003 compared to 40% in 2004.

The Trust exited the first quarter of 2004 at a rate of 6,790 boe/day, consisting of 5,755 bbls/day of oil and 6,210 mcf/day of natural gas, for a mix of 85% oil and 15% natural gas.  This represents a 20% increase over the 2003 exit rate of 5,646 boe/day.

 

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PRODUCTION EXPENSES

Production expenses increased by 60% in the first quarter of 2004 compared to the respective period in 2003. The increase is due to the higher operating costs associated with the recently acquired East Central Alberta properties. Enterra’s existing properties have an average operating cost per boe of $7.30 while the East Central properties have an average operating cost of $14.00 per boe.

 

ROYALTIES

Royalties, which include Crown, freehold and overriding royalties, increased slightly by 5% in the quarter ended March 31, 2004 compared to the respective period in 2003. The increase is the result of the increased production in 2004 offset somewhat by the lower royalty rates on the East Central Alberta properties.

 

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GENERAL AND ADMINISTRATIVE EXPENSES

The cash portion of general and administrative expenses increased only slightly (1%) in the first quarter of 2004 compared to the first quarter of 2003. Additional staffing was required in conjunction with the newly acquired properties and to assess further acquisitions. Other areas which incurred higher expenses were marketing and travel costs, insurance premiums, and higher regulatory compliance costs both for the Canadian and U.S. exchanges. The non-cash portion of general and administrative expenses in 2004 relate to the value assigned to 920,000 options granted to employees and directors.

INTEREST EXPENSE

Interest expense increased by 20% in the first quarter of 2004 compared to the first quarter of 2003. The 2004 increase is due to the higher average outstanding loan balances during the period.

 

DEPLETION AND DEPRECIATION

Depletion and depreciation expense increased by 44% in the first quarter of 2004 compared to the first quarter in 2003, primarily due to the higher depletable base with the addition of the East Central Alberta properties.

 

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INCOME AND CAPITAL TAXES

The Trust recorded an income tax recovery of $2.3 million in Q1, 2004 compared with a provision of $3 million in 2003. The decrease in income tax is primarily due to larger interest payments from Enterra to the Trust, which are a permanent difference for Enterra in calculating future taxes, together with a decrease in a substantively enacted Alberta income tax rate by 1% and the tax impact of adopting the new accounting policies.

EARNINGS

The Trust’s net earnings for the first quarter of 2004 are 39% less than the first quarter of 2003 mainly due to :

• lower revenue as a result of lower pricing and hedging losses. The stronger foreign exchange rate in Q1, 2004 compared to Q1, 2003 was the main reason behind the reduced pricing.

• higher depletion expense as a result of the increased production and the higher depletable base.

• higher operating costs related to the East Central Alberta properties.

• a future income tax recovery of $2.3 million, which actually offset some the higher expenses. This recovery is due to lower corporate income tax rates during Q1, 2004 and to the tax deductibility of the Trust’s distributions in Q1, 2004.

On a before tax basis, earnings for the three months ended March 31, 2004 were $0.3 million compared to $7.2 million in 2003 as a result of the items described above.

 

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CASH FLOW FROM OPERATIONS

Cash flow from operations decreased by 25% in the first quarter of 2004 compared to the first quarter of 2003. This is attributable to the same factors that reduced earnings, namely lower pricing received, higher operating costs on the newly acquired properties, and higher royalties and interest expense.

The changes on a per unit basis showed similar results: a decrease of 36% in Q1 of 2004 compared to Q1 of 2003.

As mentioned earlier, it is management’s view that cash flow from operations is a very useful measure of performance. Cash flow from operations is the key factor in setting the Trust’s monthly distribution rate. Cash flow from operations is also a good benchmark when comparing results from year to year or quarter to quarter because it excludes one-time non-recurring events which may otherwise distort the financial results. Cash flow from operations is a non-GAAP measure, reconciled with GAAP net earnings in the table below:

 

CAPITAL EXPENDITURES

Capital expenditures, net of disposals, for the quarter ended March 31, 2004 were $23.4 million (2003 – $7.9 million in net proceeds, i.e. Enterra received proceeds on disposal of properties of $14.9 million and spent $7 million on capital expenditures).

The 2004 capital expenditures were almost exclusively entirely related to the acquisition of the East Central Alberta properties ($19,847,000) which was completed on January 30, 2004.

 

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CASH DISTRIBUTIONS

The Trust paid distributions of US$0.10 per unit for the month of December 2003 and for the first two months of 2004. The distribution for the month of March 2004 was raised to US$0.11 per unit. Cash distributions are paid on the 15^th of the following month (e.g. the March distribution is paid on April 15).

Total distributions paid out during Q1, 2004 were $7.8 million, representing 82.43% of Enterra’s cash flow for the period.

LIQUIDITY AND CAPITAL RESOURCES

The Trust’s bank debt at March 31, 2004 was $31.3 million (December 31, 2003 - $34 million). In both periods the funds were used to acquire capital assets and support ongoing operations. At March 31, 2004 the Trust’s bank facility consisted of a line of credit of $35.6 million (December 31, 2003 - $34.7 million). Interest on amounts drawn is based on the bank’s prime rate plus 0.25%.

On January 16, 2004 the Trust entered into a financing agreement whereby the Trust 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 units. The registration of these units was filed on May 10, 2004. These funds will be applied towards the East Central Alberta property acquisition described below.

On January 30, 2004 the Trust closed an acquisition of properties in East Central Alberta for $19,847,000.

On February 20, 2004 the Trust completed a private placement of 1,049,400 Trust Units at a price of US$11.25 per unit for gross proceeds of US$11,805,750 (US$10,265,463 net of financing costs). These funds will be used for drilling projects which Enterra began prior to its conversion to a trust.

Capital expenditures should be approximately $5-$10 million in 2004 because Enterra, as an income trust, will be distributing approximately 80% of its cash flow through its monthly distributions. The Trust’s strategy for growth in 2004 will be focused on property acquisition which will be funded with a combination of additional debt and equity.

Enterra has approximately $84 million in tax pools available at March 31, 2004. (March 31, 2003 - $39 million)

The Trust had a number of forward contracts in place during the year in order to minimize the volatility in crude oil pricing. Below is a summary of the Trust’s hedging operations in 2004:

At March 31, 2004, the Trust had a total of 21,135,328 Trust units (December 31, 2003 – 18,955,960) and 879,611 Exchangeable shares (December 31, 2003 – 1,995,596) outstanding.

CRITICAL ACCOUNTING POLICIES

The Trust follows the full cost method of accounting for oil and natural gas properties and equipment whereby we capitalize all costs relating to its acquisition of, exploration for and development of oil and natural gas reserves. The Trust’s consolidated financial condition and results of operations are sensitive to, and may be adversely affected by, a number of subjective or complex judgments relating to methods, assumptions or estimates required under the full cost method of accounting concerning the effect of matters that are inherently uncertain. For example:

 

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1. Capitalized costs under the full cost method are generally depleted and depreciated using the unit-of-production method, based on estimated proved oil and gas reserves as determined by independent engineers. In addition, capital costs are also restricted from exceeding the ceiling test under Accounting Guideline No. 16 as more fully described below. Should this comparison indicate an excess carrying value, a write-down would be recorded. To economically evaluate the Trust’s proved oil and natural gas reserves, these independent engineers must necessarily make a number of assumptions, estimates and judgments that they believe to be reasonable based upon their expertise and professional and CICA and SEC guidelines. Were the independent engineers to use differing assumptions, estimates and judgments, then the Trust’s consolidated financial condition and results of operations would be affected. For example, the Trust would have lower revenues and net profits (or higher net losses) in the event the revised assumptions, estimates and judgments resulted in lower reserve estimates, since our depletion and depreciation rate would then be higher and it might also result in a write-down under the ceiling test. Similarly, the Trust would have higher revenues and net profits (or lower net losses) in the event the revised assumptions, estimates and judgments resulted in higher reserve estimates.

2. The Trust’s management also periodically assesses the carrying values of unproved properties to ascertain whether any impairment in value has occurred. This assessment typically includes a determination of the anticipated future net cash flows based upon reserve potential and independent appraisal where warranted. Impairment is recorded if this assessment indicates the future potential net cash flows are less than the capitalized costs. Were the Trust’s management to use differing assumptions, estimates and judgments, then the Trust’s consolidated financial condition and results of operations would be affected. For example, the Trust would have lower net profits (or higher net losses) in the event the revised assumptions, estimates and judgments resulted in increased impairment expense.

3. Effective January 1, 2004, the Trust retroactively adopted CICA handbook Section 3110 "Asset Retirement Obligations". The new recommendations require the recognition of the fair value of obligations associated with the retirement of tangible long-lived assets be recorded in the period the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is accreted over time for changes in the fair value of the liability through charges to accretion expense which is included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and depreciation of the underlying asset.

4. In January 1, 2004, the Trust adopted CICA Accounting Guideline 13, "Hedging Relationships" (AcG-13). AcG-13 establishes certain conditions for when hedge accounting may be applied and addresses the identification, designation, documentation and effectiveness of hedging transactions. Where hedge accounting does not apply, any changes in the mark to market values of the option contracts relating to a financial period can either reduce or increase net income and net income per trust unit for that period. The Trust has elected not to apply hedge accounting to any of its financial instruments. Effective January 1, 2004, the Trust has recorded the fair value of financial instruments as a deferred financial loss of $958,359 and a deferred financial liability of $958,359 on the balance sheet. At March 31, 2004, the deferred financial loss was amortized to a balance of $479,180 through revenues and the deferred liability was increased to the mark to market value of $1,688,149 through an unrealized hedging loss of $729,790.

5. Effective January 1, 2004, the Trust adopted the fair value method of accounting for options on a retroactive basis, without prior period restatement. In the past, the Trust measured stock option compensation cost based on the intrinsic value of the award at the date of issuance. As the exercise price and the market price were the same at the grant date, no compensation cost was recognized on any option issuance. In 2003, the Trust disclosed pro forma net income and earnings per share as if compensation cost for the Trust's unit-based compensation plan had been determined based on the fair value at the grant date for awards made under the plan subsequent to January 1, 2002.

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                                                                                                                                                                                                                                             As a result of the adoption of this policy, the Trust has recorded a charge to retained earnings of $646,031 as at January 1, 2004 to reflect the accumulated stock option expense awards made under the plan subsequent to January 1, 2002. The estimated fair value of the options issued in 2003 and 2002 has been determined using a Black-Scholes option-pricing model.

6. Effective January 1, 2004, the Trust adopted Accounting Guideline 16, "Oil and Gas Accounting – Full Cost" which replaces AcG-5 – Full Cost Accounting in the Oil and Gas industry. AcG-16 modifies how the ceiling test is performed and is consistent with CICA Section 3063, Impairment of Long-lived Assets. The new guideline modifies the ceiling test to be performed in two stages. The first stage requires the carrying value to be tested for recoverability using undiscounted future cash flows from proved reserves using forward indexed prices. If the carrying value is not recoverable, the second stage, which is based on the calculation of discounted future cash flows from proved plus probable reserves, will determine the impairment to the fair value of the asset. There is no write down of the Trust’s property, plant and equipment under either the old or the new method as of January 1, 2004 or March 31, 2004.

 

 

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ENTERRA ENERGY TRUST

Financial Statements

March 31, 2004

 

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ENTERRA ENERGY TRUST

Notes to Consolidated Financial Statements

For the Three Months ended March 31, 2004 and 2003

(Unaudited)

The interim consolidated financial statements of Enterra Energy Trust (the "Trust") have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim consolidated financial statements have been prepared following the same accounting policies and methods used in preparing the consolidated financial statements for the fiscal year ended December 31, 2003, except as described in note 1, and should be read in conjunction with those consolidated financial statements. The interim consolidated financial statements contain disclosures, which are supplemental to the Trust’s annual consolidated financial statements. Certain disclosures, which are normally required to be included in the notes to the annual consolidated financial statements have been condensed or omitted.

1. Changes in Accounting Policies

(a) Full Cost Accounting

Effective January 1, 2004, the Trust adopted Accounting Guideline 16, "Oil and Gas Accounting – Full Cost" which replaces AcG-5 – Full Cost Accounting in the Oil and Gas industry. AcG-16 modifies how the ceiling test is performed and is consistent with CICA Section 3063, Impairment of Long-lived Assets. The new guideline modifies the ceiling test to be performed in two stages. The first stage requires the carrying value to be tested for recoverability using undiscounted future cash flows from proved reserves using forward indexed prices. If the carrying value is not recoverable, the second stage, which is based on the calculation of discounted future cash flows from proved plus probable reserves, will determine the impairment to the fair value of the asset. There is no write down of the Trust’s property, plant and equipment under either the old or the new method as of January 1, 2004 or March 31, 2004.

(b) Asset Retirement Obligations

Effective January 1, 2004, the Trust retroactively adopted CICA handbook Section 3110 "Asset Retirement Obligations". The new recommendations require the recognition of the fair value of obligations associated with the retirement of long-lived assets to be recorded in the period the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is accreted over time for changes in the fair value of the liability through charges to accretion expense which are included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and depreciation of the underlying asset.

At March 31, 2004, the Trust estimated the asset retirement obligation to be $3.4 million (December, 2003 - $2.2 million), based on a total future liability of $13.0 (December 31, 2003 - $4.2 million). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extend up to 30 years into the future. This amount has been calculated using an inflation rate of 2% and discounted using a weighted average credit-adjusted risk-free interest rate of 5.9%.

The following table summarizes the changes resulting from this restatement.

 

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There was no material change in the earnings statement for the three months ended March 31, 2003 related to this change in policy.

The following table reconciles the asset retirement obligation associated with the retirement of oil and gas properties.

 

(c) Financial Instruments

On January 1, 2004, the Trust adopted CICA Accounting Guideline 13, "Hedging Relationships" (AcG-13). AcG-13 establishes certain conditions for when hedge accounting may be applied and addresses the identification, designation, documentation and effectiveness of hedging transactions. Where hedge accounting does not apply, any changes in the mark to market values of the option contracts relating to a financial period can either reduce or increase net earnings and net earnings per unit for that period. The Trust has elected not to apply hedge accounting to any of its financial instruments. Effective January 1, 2004, the Trust has recorded the fair value of financial instruments as a deferred financial loss of $958,359 and a deferred financial liability of $958,359 on the balance sheet. At March 31, 2004, the deferred financial loss was amortized to a balance of $479,180 through revenues and the deferred liability was increased to the mark to market value of $1,688,149 through an unrealized hedging loss of $729,790.

The following table reflects the changes in the financial derivative liability and deferred financial derivative loss accounts during the period.

 

 

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(d) Unit-based Compensation

Effective January 1, 2004, the Trust adopted the fair value method of accounting for options on a retroactive basis, without prior period restatement. In the past, the Trust measured stock option compensation cost based on the intrinsic value of the award at the date of issuance. As the exercise price and the market price were the same at the grant date, no compensation cost was recognized on any option issuance. In 2003, the Trust disclosed pro forma net earnings and earnings per unit as if compensation cost for the Trust's unit-based compensation plan had been determined based on the fair value at the grant date for awards made under the plan subsequent to January 1, 2002.

As a result of the adoption of this policy, the Trust has recorded a charge to retained earnings of $646,031 as at January 1, 2004 to reflect the accumulated unit option expense awards made under the plan subsequent to January 1, 2002. The estimated fair value of the options issued in 2003 and 2002 has been determined using a Black-Scholes option pricing model.

In 2003, had the Trust recorded compensation cost for the Trust's unit-based compensation plan based on the fair value at the grant date for awards made under the plan subsequent to January 1, 2002, consistent with the fair value method of accounting for stock-based compensation, the Trust's net earnings and earnings per share would have been as follows:

 

In 2004, 920,000 options were issued to employees at a fair value of $3.47 per unit as determined by the Black-Scholes model resulting in compensation expense for the three months ended March 31, 2004 of $200,717 with a corresponding credit to contributed surplus. Assumptions used in the 2004 Black-Scholes model were a risk free interest rate of 3.8%, a distribution yield of 9%, a 5 year life and volatility of 21%. Assumptions in the 2003 Black-Scholes model applied before the conversion to a Trust were a risk free interest rate of 5.0%, a distribution yield of 0%, a 5 year life and volatility of 50%.

2. Advance from joint venture partner

The advance from joint venture partner is unsecured and bears interest at 0.25% above the bank’s prime lending rate with no set repayment terms.

3. Bank indebtedness

Bank indebtedness represents the outstanding balance under a line of credit of $35,600,000 (2003 - $26,700,000). Drawings bear interest at 0.25% above the bank’s prime lending rate. Security is provided by a first charge over all of the Trust’s assets. The balance is repayable on demand. While the loan is due on demand, the Trust is not subject to scheduled repayments. The balance was increased in January 2004 to $39,650,000 and is decreasing by $1,350,000 per month until May 31, 2004 to a balance of $32,900 000.

4. Future income tax liability

The decrease in the future income tax liability is primarily due to larger interest payments from Enterra Energy Corp. ("Enterra") to the Trust, which are a permanent difference for Enterra in calculating future taxes, together with a decrease in a substantively enacted Alberta income tax rate by 1% and the tax impact of adopting the new accounting policies as set out in note 1.

 

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5. Unitholders’ Equity

(a) Issued Trust Units:

 

(b) Issued Exchangeable Shares

The exchangeable shares are exchangeable into Trust units at an exchange ratio which is adjusted each time the Trust makes a distribution to its unitholders. The exchange ratio was 1:1 on December 31, 2003 and is 1:1.02480 on March 31, 2004.

(c) Options :

Reconciliation of earnings per unit/share calculation

The weighted average number of units outstanding for the quarter ended March 31, 2004 was 21,528,149. There was no dilutive impact on earnings per unit under the treasury stock method due to the inclusion of the average unrecognized unit based compensation expense in the assumed proceeds.

 

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Form 52-109FT2 – Certification of Interim Filings during Transition Period

I, Luc Chartrand, President & CEO of Enterra Energy Trust, certify that:

1. I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings) of Enterra Energy Trust, (the issuer) for the interim period ending March 31, 2004;

2. Based on my knowledge, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings; and

3. Based on my knowledge, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the interim filings.

Date:	May 17, 2004
/s/Luc Chartrand

Luc Chartrand, President & CEO

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Form 52-109FT2 – Certification of Interim Filings during Transition Period

I, Lynn Wiebe, CFO of Enterra Energy Trust, certify that:

4. I have reviewed the interim filings (as this term is defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings) of Enterra Energy Trust (the issuer) for the interim period ending March 31, 2004;

5. Based on my knowledge, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings; and

6. Based on my knowledge, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date and for the periods presented in the interim filings.

Date:	May 17, 2004
/s/ Lynn Wiebe

Lynn Wiebe, CFO

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