40-F

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

FORM 40-F

REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

OR

X

ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007		Commission File Number 001-32744
ENTERRA ENERGY TRUST (Exact name of Registrant as specified in its charter)
Alberta, Canada (Province or other jurisdiction of incorporation or organization)	1311 (Primary Standard Industrial Classification Code Number (if applicable))			None (I.R.S. Employer Identification Number (if applicable))
Suite 2700, 500 – 4th Avenue S.W. Calgary, Alberta, Canada T2P 2V6 (403) 263-0262 (Address and telephone number of Registrant’s principal executive offices)
CT Corporation System 2610, 520 Pike Street Seattle, Washington 98101 (206) 622-4511 (Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class			Name of each exchange on which registered
Trust Units			New York Stock Exchange
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this Form:

X Annual information form

X Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

There were 61,435,895 trust units issued and outstanding as of December 31, 2007.

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the Registrant in connection with such Rule.

Yes

No X

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes X

No

The documents forming part of this Form 40-F are incorporated by reference into the following registration statements under the Securities Act of 1933, as amended:

Form	Registration No.
S-8	333-120996
F-3	333-113609
F-3	333-115318

DISCLOSURE CONTROLS AND PROCEDURES

For information on disclosure controls and procedures, see the section entitled “Disclosure Controls and Procedures” contained in the Management’s Discussion and Analysis of Enterra Energy Trust (“Enterra”) for the fiscal year ended December 31, 2007, filed as part of this annual report.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

For information on management's annual report on internal control over financial reporting, see:

(a)

"Management’s Report" included in Enterra’s Audited Consolidated Financial Statements, filed as part of this annual report; and

(b)

the section entitled "Management’s Report on Internal Controls over Financial Reporting" under the heading "Management’s Evaluation of Disclosure Controls and Procedures" in Enterra’s Management's Discussion and Analysis for the fiscal year ended December 31, 2007, filed as part of this annual report.

KPMG LLP, a registered public accounting and Enterra’s independent auditors, has issued an attestation report on management’s assessment of Enterra’s internal control over financial reporting. This report is included in the “Report of Independent Registered Public Accounting Firm” that accompanies Enterra’s Audited Consolidated Financial Statements, filed as part of this annual report.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

The required disclosure is included in the section entitled “Changes to Internal Controls and Procedures for Financial Reporting” contained in Enterra’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2007, filed as part of this annual report.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This annual report, documents incorporated herein by reference, and other reports and filings made by Enterra contain forward-looking statements.  All statements other than statements of historical facts contained in this annual report, including statements regarding the 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 Enterra, are intended to identify forward-looking statements.  Enterra has based these forward-looking statements on the current expectations and projections about future events and financial trends that the management of Enterra believes may affect En terra’s financial condition, results of operations, business strategy and financial needs.  These forward-looking statements are subject to a number of risks, uncertainties and assumptions as described elsewhere in this document.

Other sections of this annual report may include additional factors that could adversely affect the business and financial performance.  Moreover, Enterra operates in a very competitive and rapidly changing business environment.  New risk factors emerge from time to time and it is not possible for management to predict all risk factors, nor can Enterra assess the impact of all factors on its 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.

Enterra undertakes no obligation, except as required by securities law, to update publicly or revise any forward-looking statements.  You should not rely upon forward-looking statements as predictions of future events or performance.  Enterra cannot provide assurance that the events and circumstances reflected in the forward-looking statements will be achieved or occur.  Although management of Enterra believes that the expectations reflected in the forward-looking statements are reasonable, Enterra cannot guarantee future results, levels of activity, performance or achievements.

Enterra continues to evolve and document its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.  Financial and operating results incorporate certain estimates including:

(a)

estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;

(b)

estimated capital expenditures on projects that are in progress;

(c)

estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves, which Enterra expects to recover in the future;

(d)

estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures;

(e)

estimated future recoverable value of property, plant and equipment and goodwill; and

(f)

estimated fair value of derivatives and investments.

CURRENCY

Unless otherwise indicated, all dollar amounts in this annual report are expressed in Canadian dollars. The exchange rate of Canadian dollars into United States dollars, based upon the noon rate of exchange as reported by the Bank of Canada, was US$1.00 to Cdn$1.0147 on March 27, 2008 and was US$1.00 to Cdn$1.1698 on March 28, 2006.  

CODE OF ETHICS

Enterra has adopted a code of ethics entitled “Code of Business Conduct” which applies to all directors, officers, employees and consultants. It is available on Enterra’s website at www.enterraenergy.com and in print to any unitholder who requests it. All amendments to the code, and all waivers of the code with respect to any of the individuals covered by it, will be posted on Enterra’s website, submitted on Form 6-K and provided in print to any unitholder who requests them.

OFF-BALANCE SHEET ARRANGEMENTS

Enterra has not entered into any off-balance sheet arrangements other than operating leases.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

The required disclosure is included in the section entitled “Contractual Obligations” contained in Enterra’s Management’s Discussion and Analysis for the fiscal year ended December 31, 2007, filed as part of this annual report.

ADDITIONAL DISCLOSURE

Certain disclosure regarding Enterra’s corporate governance practices, disclosure of Enterra’s principal accountant fees and services and disclosure of pre-approved policies and procedures, is included in pages 70 through 79 of the Annual Information Form filed as part of this annual report.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Board has a separately-designated standing audit committee. The members of the audit committee are:  Vick Dusik, Roger Giovanetto, and Michael Doyle.

AUDIT COMMITTEE FINANCIAL EXPERT

The board of directors of Enterra’s administrator (the “Board”) has determined that it has at least one audit committee financial expert serving on its Audit Committee.  Mr. Vick Dusik has been designated an audit committee financial expert and is independent, as that term is defined by the New York Stock Exchange’s listing standards applicable to Enterra.  The Securities and Exchange Commission has indicated that the designation of a person as an audit committee financial expert does not make that person an “expert” for any purpose, impose any duties, obligations or liability on that person that are greater than those imposed on members of an audit committee and board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of the audit committee.

CORPORATE GOVERNANCE LISTING STANDARDS

Enterra’s corporate governance practices are subject to guidelines for effective corporate governance established by National Instrument 58-101 and National Policy 58-201 (collectively, the "CSA Rules"). Enterra satisfies all of the NYSE corporate governance listing standards applicable to non-U.S. companies.   According to Section 303A.11 of the Listed Company Manual, listed foreign private issuers must disclose any significant ways in which their governance practices differ from those followed by domestic companies under NYSE listing standards.

Approval of Equity Compensation Plans

Section 303A.08 of the NYSE Listed Company Manual requires shareholder approval of all equity compensation plans and material revisions to such plans.  The definition of “equity compensation plans” covers plans that provide for the delivery of newly issued and treasury securities as well as plans that rely on securities re-acquired in the open market by the issuing company for the purpose of redistribution to employees and directors.  The TSX rules provide that only the creation of or material amendments to equity compensation plans, which provide for new issuances of securities, are subject to shareholder approval.  Enterra follows the TSX rules with respect to the requirements for unitholder approval of equity compensation plans and material revisions to such plans.

Corporate Governance Guidelines

According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines and make these and the charters of its most important committees available on its website.  Enterra has adopted corporate governance guidelines that comply in many respects with those set out in Section 303A.09; however the guidelines and charters of its most important committees are not yet available on Enterra’s website.  Any unitholder may request a copy of these documents by contacting Enterra at info@enterraenergy.com.

Internal Audit Function

Section 303A.07(d) of the NYSE’s Listed Company Manual requires a listed company to have an internal audit.  Enterra does not currently have such a function.

INDEPENDENCE STANDARDS

The Board is responsible for determining whether or not each director is independent.  In making this determination, the Board has adopted the definition of “independence” as set out in Section 1.4 of Multilateral Instrument 52-110 Audit Committees (“MI 51-110”).  In applying this definition, the Board considers all relationships of the directors with Enterra, including business, family and other relationships.  The Board also determines whether each member of the Audit Committee is independent pursuant to Sections 1.4 and 1.5 of MI 52-110 and Rule 10A-3 of the Exchange Act.  The Board has not formally adopted the director independence standards contained in Section 303A.02 of the NYSE’s Listed Company Manual.

DISCLOSURE OF RESERVES DATA

As a Canadian issuer, Enterra is required under Canadian law to comply with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") issued by the Canadian Securities Administrators, in all of its reserves related disclosures.  

In the United States however, registrants, including foreign private issuers like Enterra, are generally required to disclose proved reserves using the standards contained in the Securities and Exchange Commission Regulation S-X. Under certain circumstances, applicable U.S. law permits Enterra to comply with Canadian law if the requirements vary.  The primary difference between the two standards is the additional requirement under NI 51-101 to disclose both proved and proved plus probable reserves as well as related future net revenues using forecast prices and costs.  Another difference lies in the definition of proved reserves.  As discussed in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"), the standards which NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material.

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UNDERTAKING

Undertaking

Enterra undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to:  the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

SIGNATURES

Pursuant to the requirements of the Exchange Act, Enterra certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this to annual report on Form 40-F to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated:  March 31, 2008

Enterra Energy Trust,

by its administrator, Enterra Energy Corp.

Signed “Peter Carpenter”

Peter Carpenter, Chairman and Acting CEO

Signed “Blaine Boerchers”

Blaine Boerchers, Chief Financial Officer

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EXHIBIT INDEX

 The following documents have been filed as part of this annual report on Form 40-F:

Exhibit No.	Description
Annual Information
99.1	Enterra Energy Trust Annual Information Form for the year ended December 31, 2007.
99.2	Management’s Discussion and Analysis for year ended December 31, 2007.
99.3	Audited Consolidated Financial Statements of Enterra Energy Trust, including Management’s Report, the Auditors’ Reports.
99.4	Comments by Auditors for U.S. Readers on Canada – U.S. Reporting Differences.
99.5	Reconciliation to Accounting Principles Generally Accepted in the United States of the Consolidated Financial Statements as at and for the years ended December 31, 2007 and 2006, including the Auditors’ Report thereon.
Certifications
99.6	Certification of the Acting Chief Executive Officer pursuant to section 906 of the Sarbanes-Oxley Act of 2002
99.7	Certification of the Chief Financial Officer pursuant to section 906 of the Sarbanes-Oxley Act of 2002
99.8	Certification of the Acting Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002
99.9	Certification of the Chief Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002
Consents
99.10	Consent of KPMG LLP Chartered Accountants
99.11	Consent of McDaniel & Associates Consultants Ltd.
99.12	Consent of Haas Petroleum Engineering Services, Inc.
99.13	Consent of MHA Petroleum Consultants, Inc.

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EX-99.1

Enterra Energy Trust

Annual Information Form

For the year ended December 31, 2007

March 31, 2008

TABLE OF CONTENTS

GENERAL INFORMATION

Glossary

Abbreviations, Conventions and Conversions

Note Regarding Forward-Looking Statements

STRUCTURE AND ORGANIZATION OF ENTERRA ENERGY TRUST

Enterra Energy Trust

Enterra Energy Commercial Trust

Enterra Energy Corp.

Enterra Production Partnership

Enterra Energy Partner Corp.

Trigger Resources Ltd.

Enterra US Acquisitions Inc.

Enterra Acquisitions Corp.

Altex Energy Corporation

Rocky Mountain Gas, Inc.

RMG I, LLC

Organizational Chart

GENERAL DEVELOPMENTS OF OUR BUSINESS

History and Significant Acquisitions

Equity Offerings

Anticipated Developments

DESCRIPTION OF OUR BUSINESS AND PROPERTIES

Who We Are

Current Focus of the Trust

Business Strategy During 2007

Competitive Strengths

RISK FACTORS

Risks Related to Our Business

Risks Related to the Trust Structure and the Ownership of Trust Units and Debentures

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Disclosure of Reserves Data

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

Reserves Data – Constant Prices and Costs

Reserves Reconciliation

Undeveloped Reserves

Significant Factors or Uncertainties Affecting Reserves Data

Future Development Costs

Common Infrastructure Costs

Oil and Gas Properties

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Northeast British Columbia

Western Alberta

Eastern Alberta

Saskatchewan

Powder River Basin, Montana and Wyoming

Oklahoma

Oil and Gas Wells

Land Holdings

Abandonment and Reclamation Costs

Tax Horizon

Costs Incurred

Exploration and Development Activities

Production Volume by Field

Production Estimates

Quarterly Data

RESERVE DATA CHANGES SINCE DECEMBER 31, 2007

CAPITAL STRUCTURE

The Trust Indenture

Trust Units and Other Securities

Income Streams

Unitholder Limited Liability

Issuance of Trust Units

Trustee

Liability of the Trustee

Special Voting Rights

Redemption Right

Meetings of Unitholders

Exercise of Voting Rights

Amendments to the Trust Indenture

Takeover Bid

Termination of the Trust

Reporting to Unitholders

Description of Debentures

Exchangeable Shares

MARKET FOR SECURITIES

DISTRIBUTIONS

CORPORATE GOVERNANCE

Delegation of Authority, Administration and Trust Governance

Directors and Officers

Committees

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

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LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

Regulatory Actions

CONFLICTS OF INTEREST AND  INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS  

Relationship with JED Oil Inc. and JMG Exploration, Inc.

Relationship with Petroflow Energy Ltd.

Relationship with Macon Resources Ltd.

Relationship with Trigger Projects Ltd.

Other Management and Director Interests

TRANSFER AGENT AND REGISTRAR

MATERIAL CONTRACTS

INTERESTS OF EXPERTS

AUDIT COMMITTEE

General

Mandate of the Audit Committee

Relevant Education and Experience of Audit Committee Members

Audit Committee Oversight

ADDITIONAL INFORMATION

Appendix A – Audit Committee Mandate

Appendix B – Report on Reserves Data by Independent Qualified Reserves Evaluator on Form 51-102F2

Appendix C – Report of Management and Directors on Reserve Data on Form 51-101F3

Appendix D – Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2007.

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GENERAL INFORMATION

Glossary

The following are defined terms used in this annual information form (“AIF”):

“Administration Agreement” means an administration agreement dated November 25, 2003 between the Trust and EEC;

“CT Notes” means the unsecured promissory notes issued by EECT to the Trust;

“Debentures” means the 8% and the 8.25% convertible unsecured subordinated debentures of the Trust issued under the Debenture Indenture;

“EAC” means Enterra Acquisitions Corp., a Delaware corporation and an indirect subsidiary of the Trust;

“EEC” means Enterra Energy Corp., an Alberta corporation, a wholly-owned subsidiary of the Trust, and administrator of the Trust pursuant to the Administration Agreement;

“EEC Exchangeable Shares” means shares of EEC that were exchangeable for Trust Units;

“EECT” means Enterra Energy Commercial Trust, an unincorporated trust governed by the laws of Alberta and a wholly owned subsidiary of the Trust;

“EECT Units” means trust units of EECT;

“EEPC” means Enterra Energy Partner Corp., an Alberta corporation.  EEPC is a holding company wholly owned by EEC which holds an interest in EPP;

“Enterra Arrangement” means the plan of arrangement completed on November 25, 2003 involving the Trust, EECT, Old Enterra and its subsidiaries, and Enterra Acquisition Corp.;

“Enterra US Acqco” means Enterra US Acquisitions Inc., a Delaware corporation and an indirect subsidiary of the Trust;

“EPC” means Enterra Production Corp., an Alberta corporation and was a wholly-owned subsidiary of the Trust prior to January 31, 2007;

“EPP” means the Enterra Production Partnership, a partnership organized pursuant to the laws of Alberta;

“Exchangeco” means Enterra Exchangeco Ltd., an Alberta corporation and a wholly-owned subsidiary of EECT;

“GAAP” means generally accepted accounting and principles in Canada;

“Haas” means Haas Petroleum Engineering Services, Inc., independent petroleum engineering consultants;

“Haas Report” means the independent engineering evaluation of certain oil, NGL and natural gas interests of the Trust prepared by Haas dated February 14, 2008 and effective December 31, 2007;

“High Point” means High Point Resources Inc., an Alberta corporation;

“JED” means JED Oil Inc., an Alberta corporation;

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“JED Swap” means the exchange, completed on September 28, 2006 with an effective date of July 1, 2006, of our interests in certain properties for interests held by JED and the settlement of certain indebtedness we owed to JED;

“JMG” means JMG Exploration, Inc., a Nevada corporation;

“US Farmout Partner” means Petroflow Energy Ltd.;

“McDaniel” means McDaniel & Associates Consultants Ltd., independent petroleum engineering consultants;

“McDaniel Report” means the independent engineering evaluation of certain oil, NGL and natural gas interests of the Trust prepared by McDaniel dated February 1, 2008 and effective December 31, 2007;

“MHA” means MHA Petroleum Consultants, independent petroleum engineering consultants;

“MHA Report” means the independent engineering evaluation of certain oil, NGL and natural gas interests of the Trust prepared by MHA dated February 13, 2008 and effective January 1, 2008;

“Non-Resident” means (a) a person who is not a resident of Canada for the purposes of the Tax Act and any applicable income tax convention; or (b) a partnership that is not a Canadian partnership for the purposes of the Tax Act;

“Old Enterra” means EEC prior to the Enterra Arrangement;

“Operating Subsidiaries” means collectively, the direct and indirect subsidiaries of the Trust that own and operate assets for the benefit of the Trust (with the material Operating Subsidiaries being EEC, EPP, EAC, and Enterra US Acqco);

“Reserve Reports” means, collectively, the McDaniel Report, Haas Report and the MHA Report;

“Revolving and Operating Credit Facilities” means

(i) a $129.5 million revolving credit facility with a syndicate of lenders, and

(ii) a $18.5 million operating facility with Bank of Nova Scotia as lender,

provided pursuant to a credit agreement dated November 21, 2006, as amended and restated on February 1, 2007 with 6 additional amendments of the revolving credit facility and 3 amendments of the operating credit facility up to and including the last amendments effective December 18, 2007;

“RMAC Exchangeable Shares” means shares of RMAC that were exchangeable for Trust Units;

“RMEC” means Rocky Mountain Energy Corp., a corporation created by amalgamation under the laws of Alberta;

“RMG Exchangeable Shares” means exchangeable shares issued by Enterra US Acqco that were exchangeable for Trust Units;

“Second-Lien Credit Facility” means a second-lien non-revolving credit facility with a syndicate of lenders provided pursuant to a credit agreement dated November 21, 2006, as amended and restated on February 1, 2007 with 6 additional amendments of the revolving credit facility and 3 amendments of the operating credit facility up to and including the last amendments effective December 18, 2007;

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“Series Notes” means interest bearing subordinated promissory notes issued by certain Operating Subsidiaries and currently held by the Trust;

“Special Resolution” means a resolution 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;

“Special Voting Right” means the special voting right of the Trust issued by the Trust to and deposited with the Trustee, which entitled the holders of the exchangeable shares to a number of votes at meetings of the Unitholders;

“Tax Act” means the Income Tax Act (Canada) and the Regulations thereunder, as amended from time to time;

“Technical Services Agreement” means the Technical Services Agreement between the Trust and JED dated effective January 1, 2004 and terminated on January 1, 2006;

“Trust”, “we”, “us”, or “our” means Enterra Energy Trust, an unincorporated trust governed by the laws of Alberta, and where the context requires, includes the Trust and all of the Trust Subsidiaries as a consolidated entity;

“Trust Indenture” means the amended and restated trust indenture dated November 25, 2003 among Olympia Trust Company, as trustee, Luc Chartrand as settler, and EEC, as may be amended, supplemented, and restated from time to time;

“Trust Subsidiaries” means the Operating Subsidiaries, EECT, and any other subsidiaries of the Trust;

“Trust Units” mean units of the Trust;

“Trustee” means the trustee of the Trust, presently Olympia Trust Company;

“Unitholders” mean 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; and

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

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Abbreviations, Conventions and Conversions

Abbreviations

Bbl	barrel	Mcf	thousand cubic feet
Bbls	barrels	Mmcf	million cubic feet
Mbbl	thousand barrels	Bcf	billion cubic feet
bbl/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

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 (Disclosure provided herein  in respect to BOE may be misleading, particularly if used in isolation.  A BOE conversion ratio of 6 mcf:1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.)
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
Mwh	Megawatt hours

Conventions

Unless otherwise indicated, all dollar amounts are in Canadian dollars and references herein to “$” or “dollars” are to Canadian dollars or “M$” are to a thousand Canadian dollars or “MM$” are to a million Canadian dollars.

The information set out in this AIF is stated as at December 31, 2007 unless otherwise indicated.  Capitalized terms used but not defined in the text are defined in the Glossary.

Conversions

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

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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	0.4047
Hectares	Acres	2.471

Exchange Rate Information

Except where otherwise indicated, all dollar amounts in this AIF are stated in Canadian dollars.  The following table sets forth the US/Canada exchange rates on the last trading day of the years indicated as well as the high, low and average rates for such years.  The high, low and average exchange rates for each year were identified or calculated from spot rates in effect on each trading day during the relevant year.  The exchange rates shown are expressed as the number of US dollars required to purchase one Canadian dollar.  These exchange rates are based on those published on the Bank of Canada’s website as being in effect at approximately noon on each trading day (the “Bank of Canada noon rate”).

	Year Ended December 31
	2007	2006	2005
Year End	1.0120	0.8581	0.8577
High	1.0905	0.9134	0.8609
Low	0.8506	0.8479	0.7872
Average	0.9309	0.8818	0.8258

Note Regarding Forward-Looking Statements

Certain statements contained in this AIF and in documents incorporated by reference 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 o nly as of the date hereof.

In particular, this AIF 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;

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•

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 AIF:

•

volatility in market prices for oil and natural gas;

•

potential 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 beyond what is required by applicable securities legislation.

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STRUCTURE AND ORGANIZATION OF ENTERRA ENERGY TRUST

Enterra Energy Trust

Enterra Energy Trust is an oil and gas trust established under the laws of the Province of Alberta pursuant to the Trust Indenture.  The Trust’s assets consist of the securities of the Trust Subsidiaries and indirect interests in crude oil and natural gas properties through the Operating Subsidiaries.  Our principal and head office is located at Suite 2700, 500 - 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6.  The Trustee’s head office is located at Suite 2300, 125 - 9th Avenue S.E., Calgary, Alberta, Canada T2G 0P6.  

Enterra Energy Commercial Trust

EECT is an unincorporated commercial trust established under the laws of the Province of Alberta.  The Trust owns all of the issued and outstanding EECT Units.  EECT holds, directly or indirectly, all of the outstanding shares and interests of the Operating Subsidiaries.

Enterra Energy Corp.

EEC is an Alberta corporation.  EEC is one of the Operating Subsidiaries and acts as administrator of the Trust pursuant to the Administration Agreement.  EECT owns all of the issued and outstanding shares of EEC.  On January 31, 2007, EEC amalgamated with EPC to form EEC.

Enterra Production Partnership

EPP was formed as a general partnership under the laws of the Province of Alberta on August 16, 2001.  The partners of the Partnership are EEC and Enterra Energy Partner Corp.  EEC manages the operations of EPP.

Enterra Energy Partner Corp.

EEPC is an Alberta corporation.  EEPC is a holding company wholly owned by EEC which holds an interest in EPP.

Trigger Resources Ltd.

Trigger Resources is an Alberta corporation which primarily operates oil and gas assets in Saskatchewan.  It is a wholly owned subsidiary of EEC.

Enterra US Acquisitions Inc.

Enterra US Acqco is a Delaware corporation.  All of our United States assets and operations are held and conducted indirectly through Enterra US Acqco.

Enterra Acquisitions Corp.

EAC is a Delaware corporation.  Enterra US Acqco owns all of the issued and outstanding shares of EAC.

Altex Energy Corporation

Altex is a Delaware corporation.  Altex is a wholly owned subsidiary of EAC.

Rocky Mountain Gas, Inc.

RMG is a Wyoming corporation and is a wholly owned subsidiary of Enterra US Acqco.  It operates natural gas properties in Wyoming and Montana.

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RMG I, LLC

RMGI is a Wyoming Limited Liability Company and is a wholly owned subsidiary of RMG.

Organizational Chart

The following chart illustrates our structure as at December 31, 2007.

All of the entities shown above that are below “Enterra Energy Trust” are, direct or indirect, wholly-owned subsidiaries of the Trust.

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GENERAL DEVELOPMENTS OF OUR BUSINESS

History and Significant Acquisitions

The Enterra Arrangement

The Enterra Arrangement became effective on November 25, 2003.  Pursuant to the Enterra Arrangement, the outstanding common shares of Old Enterra were exchanged by the shareholders thereof for an aggregate of 18,951,556 Trust Units.  In addition, as part of the Enterra Arrangement, EEC issued an aggregate of 2,000,000 EEC Exchangeable Shares to former holders of Old Enterra common shares in accordance with elections made by such holders under the Enterra Arrangement.  Each EEC Exchangeable Share was exchangeable into Trust Units at any time.  On January 31, 2007, all of the then-outstanding EEC Exchangeable Shares were redeemed in exchange for Trust Units.

2004 Acquisition of Rocky Mountain Energy Corp.

On September 29, 2004 Enterra completed the acquisition of Rocky Mountain Energy Corp. by way of a plan of arrangement whereby Enterra’s wholly-owned subsidiary, Rocky Mountain Acquisition Corp. (“RMAC”), acquired all the issued and outstanding common shares of RMEC.  The transaction was valued at approximately $50.3 million.  RMEC shareholders received approximately 86% of the consideration in the form of Trust Units and RMAC Exchangeable Shares and 14% in cash.  The Trust and RMAC issued 1,946,576 Trust Units and 341,882 RMAC Exchangeable Shares, respectively.  The acquisition of RMEC added approximately 1,000 BOE/d of production together with the potential to drill over 22 additional wells.  RMAC was subsequently renamed to Enterra Production Corp. (“EPC”) on January 1, 2007.  On January 19, 2007 all of the then-outstanding RMAC Exchangeable S hares were redeemed in exchange for Trust Units and EPC was amalgamated with Enterra Energy Corp. (“EEC”) January 31, 2007.

2005 Acquisition of Rocky Mountain Gas, Inc.

On June 1, 2005, Enterra acquired 100% of the issued and outstanding shares of Rocky Mountain Gas, Inc. (“RMG”), an entity with natural gas properties in Montana and Wyoming.  The transaction was valued at approximately $24.0 million and was financed with 736,842 RMG Exchangeable Shares valued at $16.7 million, 275,474 Trust Units valued at $6.3 million and cash of $1.0 million. On June 1, 2006, all of the then-outstanding RMG Exchangeable Shares were redeemed for Trust Units.

2005 Acquisition of High Point Resources Inc.

On August 17, 2005 Enterra completed the acquisition of 100% of the common shares of High Point Resources Inc. through our wholly-owned subsidiary, RMAC, in exchange for 7,490,898 Trust Units and 1,407,177 RMAC Exchangeable Shares.  High Point’s oil and natural gas properties were predominantly in Alberta and British Columbia.  The acquisition increased Enterra’s natural gas production and development portfolio in addition to contributing significant tax pools to the Trust.

2006 Acquisition of Oklahoma Assets

During the first six months of 2006, Enterra acquired oil and natural gas producing assets located in Oklahoma (“Oklahoma Assets”).  The acquisition was completed through four closings.  The first closing occurred on January 18, 2006 and represented approximately 1,300 BOE/d of production capacity.  The second closing occurred on March 21, 2006 and represented approximately 3,700 BOE/d of production capacity.  The final two closings occurred on April 4, 2006 and April 18, 2006 and represented approximately 1,300 BOE/d of production capacity.  The assets consisted of approximately 80% natural gas and 20% light oil production and included approximately 53,000 net acres of land of which over 25,000 net acres were undeveloped.  The purchase price of US$307.6 million was paid for through the issuance of 5,685,028 Trust Units valued at $116.5 million, $181.0 million of ca sh and closing costs of $10.0 million.  Enterra filed a business acquisition report dated June 29, 2006 on SEDAR with respect to this acquisition.

The current and anticipated production from the Oklahoma Assets is primarily from the Hunton Group carbonate formations and is derived through a de-pressuring of the formation via water production followed by hydrocarbon production.  The Hunton Group is exploited at depths of approximately 1,500 metres using long, multi-leg horizontal wells.  Enterra operates all of its related production, gathering and water disposal facilities.  On June 27, 2006, a farm-out agreement was entered into with our US Farmout Partner to exploit the undeveloped Hunton Group prospects.  Additionally, all of the developed and undeveloped lands are overlain by the Woodford Shale, which is speculated to be a prospective shale gas target similar to the Barnett Shale in Texas.  Enterra’s long term plans include testing of this concept.

2006 Property Swap with JED Oil Inc.

On September 28, 2006, Enterra closed a property swap agreement with JED Oil Inc. whereby Enterra swapped certain of its interests in properties in the Ferrier area of Alberta for interests of JED in common with Enterra’s in East Central Alberta, the Desan area of Northeast British Columbia and the Ricinus area of Alberta.  The swap was based on independent third party engineering evaluations and was effective July 1, 2006.  The transaction also resulted in the termination of an Agreement of Business Principles between the Trust and JED whereby the Trust had a right of first refusal on properties that JED owned and JED had the ability to farm-in on the Trust’s undeveloped lands.  Concurrent with the swap, the Trust settled all amounts owing to JED.

2007 Acquisition of Trigger Resources Ltd.

On April 30, 2007, Enterra acquired all of the issued and outstanding shares of Trigger Resources Ltd. (“Trigger Resources”).  Trigger Resources shareholders received cash consideration of $63.3 million which was funded by the issuance of $40.0 million of 8.25% convertible debentures that mature on June 30, 2012 and $29.2 million of Trust Units (4,945,000 trust units).  Trigger Resources’ oil and natural gas properties are located in west central and southwest Saskatchewan and, at the time of acquisition, added approximately 2,400 BOE/d (58% oil, 42% gas) to Enterra’s production portfolio.  The properties generally have 100% working interest with year round access and relatively low operating costs.

2007 Disposition of Non-core Assets

Enterra regularly evaluates asset acquisition and divestiture candidates.  This practice, in conjunction with Enterra’s debt reduction strategy, led the Trust in 2007 to review and identify assets deemed to be “non-core” to its ongoing operations.  Certain of these assets were then publicly marketed in the fall of 2007.  Enterra received numerous proposals for the assets marketed in addition to several unsolicited offers for non-core assets that had not been actively marketed.  During 2007 certain Princess non-operated, Willesden Green and Little Bow properties were sold.  At December 31, 2007, Enterra had entered into purchase and sale agreements for three other asset packages with gross proceeds totalling $45.9 million.  Subsequent to year end, all of these outstanding purchase and sale agreements have been closed.  Substantially all net proceeds have been appl ied to debt reduction of the Trust.  The Trust currently has another purchase and sale agreement for another asset package with gross proceeds of $1.6 million that is expected to close in Q2 2008.

Enterra continues to evaluate asset acquisition and divestiture opportunities as part of the ongoing management of its asset portfolio.

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Equity Offerings

2005 Financings

On March 4, 2005 Enterra completed a private placement of 500,000 Trust Units at a price of US$19.00 for gross proceeds of US$9.5 million.  The funds received from this financing were used to reduce outstanding debt and for general corporate purposes.

On April 22, 2005 Enterra entered into an equity line of credit arrangement with Kingsbridge Capital Limited (“Kingsbridge”) whereby Kingsbridge committed to purchase up to US$100.0 million of Trust Units in various tranches at the option of the Trust.  Under the arrangement, the Trust issued 695,141 Trust Units for proceeds of $15.8 million.  The proceeds from the issuances were used to reduce outstanding debt and general corporate purposes.

On December 20, 2005 Enterra filed a prospectus supplement for the issuance of up to 950,000 Trust Units at US$16.00 per unit.  The issuances under the prospectus supplement were completed by January 13, 2006.  Enterra issued 950,000 Trust Units for proceeds of $17.8 million under this prospectus supplement.  The proceeds from this financing were used to fund capital expenditures and for general corporate purposes.

2006 Financings

On March 3, 2006 Enterra filed a prospectus supplement for the issuance of up to 1,500,000 Trust Units at US$17.25 per unit.  275,000 Trust Units were issued under this prospectus supplement for proceeds of $5.4 million.  Funds received from this financing were used for capital expenditures and for general corporate purposes.

On November 10, 2006 Enterra filed a short form prospectus for the issuance of 4,979,500 Trust Units at $8.10 per unit for proceeds of $40.3 million.  Funds received from this financing were used to partially repay Enterra’s then-existing bridge credit facilities.

On November 10, 2006 Enterra filed a short form prospectus for the issuance of $138,000,000 of 8% debentures convertible into Trust Units at $9.25 per unit.  The funds received from this financing were used to partially repay Enterra’s then-existing bridge credit facilities.  As at December 31, 2006 $57,669,000 of the convertible debentures had been converted into 6,234,483 Trust Units.

2007 Financings

On April 11, 2007 Enterra filed a preliminary short form prospectus for the issuance of up to 4,945,000 Trust Units, inclusive of the underwriter’s over-allotment option of 645,000 Trust Units, at a price of $5.90 per Trust Unit for gross proceeds of $29.2 million and $40.0 million of 8.25% debentures convertible into Trust Units at a price of $6.80 per Trust Unit.  The net proceeds of this issuance were used to finance the acquisition of Trigger Resources.

Anticipated Developments

For a discussion of anticipated developments for 2008, please see the subsequent events and proposed transactions section of the Management’s Discussion and Analysis for the year ending December 31, 2007 (the “MD&A”) which may be found on SEDAR at www.sedar.com.

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Implications of Tax Proposals by the Canadian Minister of Finance

On October 31, 2006, the Minister of Finance (Canada) (“Finance”) announced tax measures which will materially reduce the amount of cash available for distributions to the Unitholders.  It is expected that the Trust will be subject to these new rules beginning on January 1, 2011.  

As noted above, the Trust could become subject to these changes before 2011 if it experiences growth, other than “normal growth”, before that time.  Under the December 15, 2006 guidelines, the Trust will be considered to have experienced only “normal growth” if its issuances of new equity (which for this purpose includes Trust Units and debt that is convertible into Trust Units, but does not include non-convertible debt) do not exceed, for each of the intervening periods set forth below, a safe harbour measured by reference to the Trust's market capitalization as of the end of trading on October 31, 2006 (measured solely by the market value of the issued and outstanding Trust Units as of that date).  The Trust's market capitalization as of October 31, 2006 was approximately $408,000,000.  The intervening periods and their respective safe h arbour amounts are as follows:

(a)

November 1, 2006 to December 31, 2007 – 40% of the Trust's market capitalization as of October 31, 2006;

(b)

January 1, 2008 to December 31, 2008 – 20% of the Trust's market capitalization as of October 31, 2006;

(c)

January 1, 2009 to December 31, 2009 – 20% of the Trust's market capitalization as of October 31, 2006;

(d)

January 1, 2010 to December 31, 2010 – 20% of the Trust's market capitalization as of October 31, 2006.

The December 15, 2006 guidelines provide that these annual safe harbour amounts are cumulative, and that replacing debt that was outstanding as of October 31, 2006 with new equity, whether through a debenture conversion or otherwise, will not be considered growth for these purposes.  In addition, an issuance of new equity will not be considered growth to the extent that the issuance is made in satisfaction of the exercise by another person of a right in place on October 31, 2006 to exchange an interest in a partnership, or a share of a corporation (such as exchangeable shares), for Trust Units.

On November 21, 2006 Enterra issued Trust Units and convertible Debentures for total gross proceeds of $178.3 million.  The net proceeds from the issue combined with drawings under our Revolving and Operating Credit Facilities were used to repay in full bridge loans that had been outstanding on October 31, 2006.  The issuances will not be considered new equity for purposes of the safe harbour amounts.

On April 30, 2007 Enterra issued Trust Units and convertible debentures for total gross proceeds of $69.2 million.  The net proceeds of this issuance were used to fund the acquisition of Trigger Resources.  This issuance of new equity is within the prescribed safe harbour amounts and is not expected to be deemed as “undue expansion” of the Trust.

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Implication of Recent Royalty Proposals by the Alberta Provincial Government

On October 25, 2007 the Alberta Provincial Government (the “Province”) announced revisions to its existing royalty regime for non-renewable energy resources that would be effective, if enacted, as of January 1, 2009 (the “New Regime”).  Specific details of the New Regime are still under review as the Province continues to consult with stakeholders including the oil and gas industry.  If the New Regime is enacted as currently written, however, Enterra’s initial assessment is that the royalty rates for its Alberta oil and gas production will, in aggregate, be impacted in a direct manner dependent upon commodity prices.  Asset dispositions closed in December 2007 and subsequent to year end consisted exclusively of Alberta based production and will reduce the Trust’s exposure to changes in the royalty structure contemplated under the New Regime.  Royalt y rates for production of the Trust from British Columbia, Saskatchewan and the United States are not impacted by the New Regime.

See also “Risk Factors – Changes in tax and other legislation that may adversely affect Unitholders”.

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DESCRIPTION OF OUR BUSINESS AND PROPERTIES

Who We Are

Our portfolio of crude oil, natural gas liquids and natural gas interests is geographically diversified and split between natural gas and liquids production.  Our properties are located principally in Alberta, British Columbia, Saskatchewan and Oklahoma.  Our average production for 2007 was 12,428 BOE/d, which was comprised of 62% natural gas and 38% crude oil and natural gas liquids.  

Current Focus of the Trust

Circumstances in 2007 that have resulted in the current suspension of Trust distributions are also causing a review of the key strategies of Enterra.  A primary goal for 2008 is the reduction of debt with the long term goal to improve the balance sheet.  At the same time, select capital reinvestment projects thought to have the best performance on a near term basis are being pursued and to the extent possible, production rates and reserve values are being preserved.  It is not anticipated that production and reserves values can be held flat with the current capital budget of $30.0 million for 2008.  Cost reduction at operating and overhead levels will be important to achieving both debt reduction and capital reinvestment goals.

Business Strategy During 2007

The goal of Enterra has been to generate returns for its unitholders from steady and consistent increases in reserves, production and funds from operations per trust unit.  To achieve that goal the Trust has pursued a three-point strategy as follows:

Organic Growth

The Trust currently targets investment in the large portfolio of lower-risk development opportunities it has identified within its existing asset base.  The individual nature and number of opportunities varies across the properties, but in aggregate the Trust believes they offer a means of adding reserves and production on a basis that will be accretive to unitholders and at a pace that is generally within the control of the Trust.  As a method of countering natural production declines and potentially growing reserve values, the Trust believes that investing in such projects is in the long-term interest of unitholders.  

Accretive Acquisitions

Corporate and property acquisitions can be an effective means of consolidating assets, improving efficiencies in existing core areas or adding new core areas.  The ability to make material, accretive acquisitions is subject to the business environment prevailing at any particular time and the availability of capital beyond the internally generated cash flow of the Trust.   

Strategic Partnerships

The Trust has actively sought to align itself with industry partners that provide access to projects that otherwise may not be available due to the nature or degree of risk involved or due to the expertise required to properly capitalize on the opportunity.  

In pursuing the strategies, Enterra has sought to manage the risk to unitholders by a geographically diversified production base, by maintaining a reasonable balance between liquids and gas production, seeking high working interests, operatorship and ownership of associated infrastructure, and maintaining a multi-year inventory of lower-risk development projects.

Competitive Strengths

We believe we have identified a number of competitive strengths which will enhance the execution of our business strategy and assist us in meeting our goal of generating strong returns.  Our competitive strengths include:

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Diversified Production Base

Our assets are concentrated in four areas: north east British Columbia, Alberta, Saskatchewan and Oklahoma.  While each area has different geological, production and infrastructure characteristics, in aggregate they have historically provided a stable source of production.  See “Statement of Reserves and other Oil and Gas Information”.

Large Portfolio of Development Projects

Our properties contain a number of potential development projects, which we believe supports our strategy of reserving a portion of funds from operations to invest in organic growth opportunities.  Currently, we estimate that there are a significant number of drilling opportunities on our approximately 277,000 net acres of undeveloped land.  See “Statement of Reserves and other Oil and Gas Information”.

U.S. Platform Distinguishes Us From Other Canadian Oil & Gas Trusts

Based on average production in December 2007, approximately 41% of our production is in the United States.  We believe that our presence in both countries, in terms of people and assets, provides us with a broader range of opportunity, improves our perspective when evaluating projects or acquisitions, and reduces our dependence on the highly competitive Canadian market.

Attractive Commodity Price Hedges

As part of our active risk management program where we hedge up to 50% of our projected gross production up to 24 months in advance, we have entered into a series of collars to reduce the impact of short-term fluctuations in crude oil and natural gas prices.  The terms of the transactions are detailed in the notes to our 2007 consolidated annual financial statements and in the associated “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

New Experienced Management Team

Over the past year, we have made several changes to our management team which we believe has resulted in the formation of a strong, experienced and committed management team that has demonstrated its ability to identify and successfully execute our business plans.  See “Corporate Governance – Directors and Officers”.

Personnel

At December 31, 2007, we employed or contracted 55 office personnel and 42 field operations personnel in our Canadian operations and 25 office personnel and 25 field operations personnel in our U.S. operations for a total of 147 employees.

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RISK FACTORS

Risks Related to Our Business

Volatility in oil and natural gas prices could have a material adverse effect on results of operations and financial condition, which, in turn, could affect the market price of our Trust Units or Debentures and the amount of distributions to Unitholders.

Our business, results of operations, financial condition and future growth are substantially dependent on the prevailing prices for our production.  Historically, the markets for oil and natural gas have been volatile and such markets are likely to continue to be volatile in the future.  Prices for oil and natural gas are based on world supply and demand and are subject to large fluctuations in response to relatively minor changes in supply or demand, whether the result of uncertainty or a variety of additional factors beyond our control including, without limitation, actions taken by OPEC and its adherence to agreed production quotas, war, terrorism, government regulation, social and political conditions, economic conditions, prevailing weather patterns and the availability of alternative sources of energy.  Any substantial decline in the price of oil or natural gas could have a material adverse effect on our revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of our properties, planned level of spending for exploration and development and level of reserves.  No assurance can be given that prices for oil or natural gas will be sustained at levels that will enable us to operate profitably or make distributions.

We use financial derivative instruments and other hedging mechanisms to try to limit a portion of the adverse effects resulting from changes in oil and natural gas 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, it is unlikely that such hedging transactions will fully offset the risks of changes in commodity prices.

Our Revolving and Operating Credit Facilities may not provide sufficient liquidity.

Our Revolving and Operating Credit Facilities may not provide us with sufficient liquidity.  Currently, the amounts available under our Revolving and Operating Credit Facilities are not sufficient to repay our Second-Lien Credit Facility by its maturity date on November 20, 2008, and we may not be able to obtain additional financing on economic terms attractive to us, if at all.

Under the current terms of our Revolving and Operating Credit Facilities the Trust cannot use cash flow from operations to fund the required Second–Lien debt repayments and convertible debenture interest repayments.  The Trust is required under the Second-Lien Credit Facility to reduce the debt to $28.0 by June 30, 2008 from its current level of $29.1 million.  Furthermore, the Trust must make interest payments on its convertible debentures of approximately $4.9 million on June 30, 2008.  There is a risk that the Trust will not be able to renegotiate these restrictions on cash under its current credit agreements, receive proceeds from asset dispositions or the issuance of new equity or new borrowings to make these required payments.  

Our obligations to our lenders may have a material adverse affect on our ability to pay distributions to Unitholders.

The payment of interest and principal, and other costs, expenses and disbursements to our lenders reduces the amounts available for potential distribution to Unitholders.  Variations in interest rates and required principal repayments could result in significant changes to the amount of the funds from operations required to be applied to the debt before payment of any amounts to Unitholders.  The agreement governing our Revolving and Operating Credit Facilities provides that if we are in default of its terms, or if amounts outstanding exceed the amount of the borrowing base, our ability to make distributions to Unitholders may be restricted.  

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On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

Our assets are leveraged.  Any material change in our liquidity could impair our ability to make potential distributions to Unitholders and could adversely affect the market price of our Trust Units or Debentures.

We carry debt that is secured by our assets.  A decrease in the amount of production or the price received for it could make it difficult for us to service our debt or may cause our lenders to determine that our assets are insufficient security for the debt.  Repayment of all or a portion of outstanding amounts under our Revolving and Operating Credit Facilities may be demanded on relatively short notice.  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, or adversely affect the market price of our Trust Units or Debentures.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

An inability to add additional reserves through development or acquisition could have a material adverse effect on the market price of our Trust Units or Debentures.

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 success in developing and exploiting existing properties and acquiring additional reserves.  Accordingly, if external sources of capital, including the issuance of additional Trust Units or other securities, become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand oil and natural gas reserves will be impaired. To the extent that we are required to use funds from operations to finance capital expenditures or property acquisitions, the level of funds from operations available for distribution to Unitholders will be reduced.  Additionally, we cannot guarantee that we w ill be successful in developing or exploiting 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 potential distributions to Unitholders.

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 received for production, which, in turn, could have a material adverse effect on the market price of our Trust Units or Debentures.

Our business depends in part upon the availability, proximity and capacity of oil and 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 potential distributions to Unitholders.

Fluctuations in foreign currency exchange rates could have a material adverse effect on our business.

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.

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Distributions, if any, may be reduced during periods in which we make capital expenditures or debt repayments using cash flow.

To the extent that we use cash flow to finance acquisitions, development costs and other significant expenditures, the portion of funds from operations that is available for distribution to Unitholders will be reduced.  As a result, the timing and amount of capital expenditures may affect the amount of cash available to distribute to Unitholders.  Distributions may be reduced, or even eliminated, at times when we make significant capital or other expenditures.

The board of EEC, the administrator and principal operating subsidiary of the Trust, has the discretion to determine the extent to which funds from operations will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under our Revolving and Operating Credit Facilities.  As a consequence, the amount of funds EEC retains 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.

Actual reserves will vary from reserve estimates, and those variations could have a material adverse effect on the market price of the Trust Units or Debentures and distributions to Unitholders.

The reserve and recovery information contained in the Reserve Reports relating to our reserves are only estimates and the actual production and ultimate reserves from its properties may be greater or less than the estimates prepared by such firms.

The value of our Trust Units and Debentures 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.

As much of our production is from geological formations with relatively limited long term production history (including the Jean Marie trend in northeast British Columbia and the Hunton formation in Oklahoma), actual results are more likely to vary from estimates.

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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.

In addition, 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 production could result in materially lower revenues and cash flow and, therefore, could reduce the amount available for distributions to Unitholders.

As we expand our operations beyond conventional oil and natural gas production in Western Canada, we face new challenges and risks.

Our operations and expertise were previously focused on the production of conventional oil and gas production and development in the Western Canadian Sedimentary Basin.  In the second quarter of 2005, we acquired coal-bed methane properties in Wyoming and Montana and in the first quarter of 2006, we acquired properties in Oklahoma.  We have gained significant experience operating in these jurisdictions but we still will face operating and business challenges that we cannot at present foresee and will need to rely on local management.

Our Trust Indenture does not limit our activities to oil and gas production and development, and we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines.  Expansion of our activities into new areas presents challenges and risks that we may not have faced in the past.  If we do not manage these challenges and risks successfully, results of operations and financial condition could be adversely affected.

Incorrect assessments of value at the time of acquisitions could have a material adverse effect on the market price of our Trust Units or Debentures and distributions to Unitholders.

The price we are willing to pay for reserve acquisitions is based largely on estimates of the reserves to be acquired.  Actual reserves could vary materially from these estimates.  Consequently, the reserves we acquire may be less than expected, which could adversely impact cash flows and distributions to Unitholders.  An initial assessment of an acquisition may be based on a report by engineers or firms of engineers that have different evaluation methods and approaches than those of our engineers, and these initial assessments may differ significantly from our subsequent assessments.

We may undertake acquisitions that could limit our ability to manage and maintain our business, result in adverse accounting treatment or be difficult to integrate into our business.  Any of these events could result in a material change in our liquidity, impair our ability to make distributions to Unitholders and could adversely affect the market price of the Trust Units or Debentures.

A component of our future growth depends on our ability to identify, negotiate, and acquire additional entities and assets that complement or expand our existing operations.  However we may be unable to complete any acquisitions or any acquisitions that may be completed may not enhance our business.  Any acquisitions could subject us to a number of risks, including:

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•

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.

The exploration, development and operation of a portion of our properties is dependent on third-parties, and their failure to perform or harm to their business could adversely affect our revenues and ultimately our distributions to Unitholders.

The exploration and development of a portion of our properties may be undertaken by industry partners and a lack of success or an inability to perform by such partners would affect our future prospects, revenues and distributions.

We still have limited experience operating properties in the United States and are reliant on the local employees and on our US Farmout partner for technical and operational support.  It is our expectation that we will gain more insight into the technical and operational characteristics of each of these properties through these relationships.  Any early termination or deterioration of the relationship with a partner, or any inability to rapidly understand the geology and production characteristics of the properties, could have a material adverse effect on the market price of our Trust Units or Debentures.

On properties where we are not the operator, we are reliant on the operator for continuing production from the property, and to some extent, the marketing of that production.  During 2007, approximately 23% of 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 makes estimating 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 workman like” manner.  These operating agreements generally provide, however, that the operator has no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except for liabilities that may result from gross negligence or wilful misconduct.

The exploration, development and exploitation of a portion of our properties is dependent on technological advancements becoming available on a timely basis.  Any failure to obtain or delay in achieving the advancements could adversely affect the market price of our Trust Units or Debentures and distributions to Unitholders.

The exploration, development and exploitation of certain of our properties on a basis that will maximize their contribution to the market value of our Trust Units or Debentures and to funds available for distribution requires that we be able to access on a timely basis technological advancements.  The effective realization of value from the Woodford shale formation in Oklahoma and coal bed methane potential in Wyoming are examples of such properties.  We may not be able to achieve those technological advancements or acquire the benefit of them from third-parties.

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Delays in business operations could adversely affect our distributions to Unitholders.

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.

Changes in market-based factors may adversely affect the trading price of our Trust Units or Debentures.

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 or Debentures is therefore sensitive to a variety of market-based factors, including, but not limited to, interest rates and the comparability of the Trust Units or Debentures to other similar securities.  Any changes in these market-based factors may adversely affect the trading price of the Trust Units or Debentures.

Our operations are entirely dependent on our management and the loss of key management and other personnel could negatively impact our business.

Unitholders are entirely dependent on our management 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 us.  

Management of the Trust may have conflicts of interest.

There are conflicts of interest to which several of our directors and officers are subject in connection with our operations.  In particular, certain of our directors and officers are involved in managerial or directorial positions with other oil and gas companies whose operations, from time to time, are in direct competition with our operations.  Additionally, certain of our directors and officers may become involved with entities which may, from time to time, provide financing to, or make equity investments in, our competitors.  See “Conflicts of Interest and Interests of Management and Others in Material Transactions”.

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We may be unable to successfully compete for resources with other organizations in our industry.

We compete for capital, reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in 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. In addition, to the extent our Trust Units receive a lower market valuation relative to competing entities; we will be at a disadvantage in acquiring properties in competition with such entities.  Given the highly competitive natu re of the oil and natural gas industry, any competitive disadvantage could adversely affect the market price of our Trust Units or Debentures 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.

We may incur material costs and liabilities to comply with or as a result of health, safety and environmental laws and regulations.

The oil and natural gas industry is subject to extensive environmental regulation pursuant to local, state, provincial and federal legislation in Canada and the United States.  A breach of that legislation by us may result in the imposition of administrative, civil or criminal penalties, damages, fines, the issuance of “clean up” orders or the issuance of injunctions limiting or prohibiting some or all of its operations.  Strict liability may be incurred under these environmental regulations and legislation in connection with discharges or releases of petroleum hydrocarbons and wastes into the environment as a result of our operations.  In addition, legislation regulating the oil and natural gas industry may be changed to impose higher standards and potentially more costly obligations.  The 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as th e Kyoto Protocol, was ratified by the Canadian government in December 2002 and would 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 for our operations.  Although we record a provision in our financial statements relating to estimated future environmental and reclamation obligations, we cannot guarantee that we will be able to satisfy our actual future environmental and reclamation obligations.

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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 funds from operations and therefore, will reduce the amount of funds 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.

Climate change impact

Enterra faces a variety of uncertainties related to climate change. These range from potential impacts from emissions restrictions, carbon taxes and other government policy initiatives to changes in weather patterns that may affect operations. Both the Alberta provincial government and the Canadian federal government have introduced planned legislative concepts that are intended, among other things, to drive industry towards CO2 emissions reduction and CO2 capture and sequestration in below ground geologic formations. In early 2008, the British Columbia provincial government announced its intention to introduce a carbon tax on fuels.

Although Enterra is not a large emitter of greenhouse gases, these forms of legislation may have an impact on both revenues and cost structures at a future undetermined time.

Another potential climate change impact on the Trust may result from the direct consequences of weather events. These may range from extreme cold events, to early break up in winter-only areas and unusual storms. In 2007, the Trust’s Oklahoma operations suffered from all-time record rainfall amounts and later from a severe ice storm in December. Whether these conditions relate to a specific climate change trend or are just statistical anomalies is unknown.

Lower oil and gas prices increase the risk of impairment of our oil and gas property investments.

All costs related to the exploration for and the development of our oil and gas reserves are capitalized into one of two cost centers, Canada and the United States.  Costs capitalized include land acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling productive and non-productive wells and production equipment.  General and administrative costs are capitalized if they are directly related to development or exploration projects.  Proceeds from the disposal of oil and natural gas properties are applied as a reduction of cost without recognition of a gain or loss except where such disposals would result in a 20% change in the depletion rate.

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.  The amounts recorded for depletion, depreciation and the asset retirement obligation are based on estimates.  We place a limit on the carrying value of our petroleum and natural gas properties, which may be depleted against revenues of future periods (the “ceiling test”).  The ceiling test is conducted separately for each cost center.  The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects ex ceeds the carrying value of the cost center.  When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of petroleum and natural gas properties exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects.  The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.  The ceiling test calculation is based on estimates of reserves, production rates, oil and natural gas prices, future costs (including asset retirement costs) and other relevant assumptions.  By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.  The risk that we will be required to write down the carrying value of crude oil and natural gas properties increa ses when crude oil and natural gas prices are low or volatile.

At December 31, 2007 a provision of $26.2 million was recorded due to ceiling test impairment on the property, plant and equipment of Enterra which was the result of the fair value of the assets sold subsequent to year end being less than the book value of those properties.  

While a write down does not directly affect funds from operations, the charge to earnings could be viewed unfavourably in the market or could limit our ability to borrow funds or comply with covenants contained in current or future credit agreements or other debt instruments.

Unforeseen title defects may result in a loss of entitlement to our 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.

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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.

Electricity costs and water production may have an impact on operating costs.

Our Oklahoma and Alberta properties consume significant quantities of electricity to drive motors and pumps for the production of hydrocarbons and the lifting and re-injection of formation water.  The cost of electricity is a major component of lifting expense.  While we establish term purchases of electrical power at competitive rates, we cannot guarantee that changes in market conditions and contract renewals will continue to allow operating costs to remain competitive and certain of our key fields profitable.  Under these circumstances we would attempt to seek alternatives including self-generation of our own power requirements.  However, we cannot guarantee that self-generation of power using our own product as fuel as an alternative to grid power will be either profitable or acceptable to landowners or regulators.  A significant loss in profitability of key fields as a result of hig her costs of electricity or lack of availability of electricity could affect future funds from operations and distributions.

The disposal of water associated with coal-bed methane production in Wyoming and Montana has been a significant concern of certain environmental groups.  Opposition by various environmental interests has resulted in significant delays to the permitting of coal-bed methane projects, particularly those on federal lands.  While we believe our projects will be developed successfully, we cannot guarantee that these will not be delayed or subject to restrictions that render them unprofitable.

Prospectivity of the Woodford shale for shale gas is not firmly established.

We believe the Woodford shale that underlies our lands in Oklahoma is prospective for shale gas.  However, while there is some minor production from the Woodford shale, a number of industry players have commented favourably on expectations for the Woodford shale and tests are currently being drilled in various locations in Oklahoma and Texas, the prospectivity of the Woodford shale for shale gas is not sufficiently established.  The play is technically complex and we cannot guarantee that the technical challenges will be overcome, or that the Woodford shale under our lands will prove economically successful.

Risks Related to the Trust Structure and the Ownership of Trust Units and Debentures

There would be material adverse tax consequences if we lost our status as a mutual fund trust under Canadian tax laws.

Generally speaking, the Income Tax Act (Canada) (the “Tax Act”) provides that a trust will permanently lose its “mutual fund trust” status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of Unitholders must not be non-residents of Canada), unless at all times “all or substantially all” of the trust’s property consisted of property other than certain taxable Canadian property (the “TCP Exception”). Based on the most recent information obtained through our transfer agent and financial intermediaries, in February 2008 an estimated 91% of our issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Tax Act).  We are currently able to take advantage of the TCP Excepti on, and as a result, we do not currently have a specific limit on the percentage of Trust Units that may be owned by non-residents. We intend to continue to take the necessary measures in order to ensure that we continue to qualify as a mutual fund trust under the Tax Act.  However, we may not be able to take steps necessary to ensure that we maintain our mutual fund trust status.  Even if we are successful in taking such measures, these measures could be adverse to certain holders of Trust Units, particularly non-residents of Canada. The board of EEC could impose a specific limit on the number of Trust Units that could be beneficially owned by non-residents of Canada, similar to the non-resident ownership restrictions in place for other income funds in Canada, or could implement a dual-class unit structure which would effectively limit the aggregate number of Trust Units that could be owned by non-residents of Canada. Steps could be taken to ensure that no additional Trust Units are issued or tran sferred to non-residents, including limiting or suspending the trading of our Trust Units.

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Should our status as a mutual fund trust be lost or successfully challenged by the Canada Revenue Agency, certain adverse consequences may arise for us and our Unitholders.  Some of the significant consequences of losing mutual fund trust status are as follows:

•

we would be subject to a special tax under Part XII.2 of the Tax Act of 36% of our “designated income” (which would not include interest on the Series Notes or the CT Notes). Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are non-residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax;

•

Trust Units and Debentures held by non-residents of Canada would become “taxable Canadian property”. Non-resident holders would then be subject to Canadian tax reporting and payment requirements on any gains realized on a disposition of Trust Units or Debentures held by them;

•

the Trust Units and Debentures may no longer constitute qualified investments under the Tax Act for registered retirement savings plans (“RRSPs”), registered retirement income funds (“RRIFs”), registered education savings plans (“RESPs”), or deferred profit sharing plans (“DPSPs”) (collectively, “Exempt Plans”). If, at the end of any month, one of these Exempt Plans holds Trust Units or Debentures that are not a qualified investment, the plan must pay a tax equal to 1% of the fair market value of the Trust Units or Debentures at the time the Trust Units or Debentures were acquired by the Exempt Plan. An RRSP or RRIF holding Trust Units or Debentures that are not a qualified investment would be subject to taxation on income attributable to the Trust Units or Debentures, including the full amount of any capital gain from a disposition of the Trust Units or Debentures. If an RESP holds Trust Units or Debentures that are not a qualified investment, it may have its registration revoked by the Canada Revenue Agency; and

•

we would cease to be eligible for the capital gains refund mechanism available under the Tax Act.

Changes in tax and other legislation may adversely affect Unitholders.

Income tax laws, other legislation 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 us and our Unitholders.  Tax authorities having jurisdiction over us or our 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 our Unitholders.

On March 23, 2004, the Canadian federal government announced proposed changes to the Tax Act, which would have effectively eliminated, over a period of time, the TCP Exception currently relied on by most oil and gas trusts to maintain their mutual fund trust status. However, as the proposed changes only affected mutual fund trusts that held contractual oil and gas royalties, the proposals would not have had a direct impact on us. In response to submissions from and discussions with stakeholders, the Canadian federal government suspended the implementation of those proposed amendments.

On October 31, 2006, the Minister of Finance (Canada) (“Finance”) announced tax measures which will materially reduce the amount of cash available for distributions to the Unitholders.  It is expected that the Trust will be subject to these new rules beginning on January 1, 2011.  

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As noted above, the Trust could become subject to these changes before 2011 if it experiences growth, other than “normal growth”, before that time.  Under the December 15, 2006 guidelines, the Trust will be considered to have experienced only “normal growth” if its issuances of new equity (which for this purpose includes Trust Units and debt that is convertible into Trust Units, but does not include non-convertible debt) do not exceed, for each of the intervening periods set forth below, a safe harbour measured by reference to the Trust's market capitalization as of the end of trading on October 31, 2006 (measured solely by the market value of the issued and outstanding Trust Units as of that date).  The Trust's market capitalization as of October 31, 2006 was approximately $408,000,000.  The intervening periods and their respective safe harbour amounts are as follows:

(a)

November 1, 2006 to December 31, 2007 – 40% of the Trust's market capitalization as of October 31, 2006;

(b)

January 1, 2008 to December 31, 2008 – 20% of the Trust's market capitalization as of October 31, 2006;

(c)

January 1, 2009 to December 31, 2009 – 20% of the Trust's market capitalization as of October 31, 2006;

(d)

January 1, 2010 to December 31, 2010 – 20% of the Trust's market capitalization as of October 31, 2006.

The December 15, 2006 guidelines provide that these annual safe harbour amounts are cumulative, and that replacing debt that was outstanding as of October 31, 2006 with new equity, whether through a debenture conversion or otherwise, will not be considered growth for these purposes.  In addition, an issuance of new equity will not be considered growth to the extent that the issuance is made in satisfaction of the exercise by another person of a right in place on October 31, 2006 to exchange an interest in a partnership, or a share of a corporation (such as exchangeable shares), for Trust Units.

While these guidelines are such that it is unlikely they would affect the Trust's ability to raise the capital required to maintain and grow its existing operations in the ordinary course during the transition period, they could adversely affect the cost of raising capital and the Trust's ability to undertake more significant acquisitions.

It is not known at this time if or when the October 31 Proposals will be enacted by Parliament or whether the October 31 Proposals will be enacted in the form currently proposed.

There is no assurance that the Canadian federal government will not introduce other changes to the Tax Act directed at non-resident ownership which, given our level of non-resident ownership, may result in us losing our mutual fund trust status or could otherwise detrimentally affect us and the market price of our Trust Units.

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The incurrence of tax by the Operating Subsidiaries could have a material adverse effect on our ability to pay distributions to Unitholders.

Our Operating Subsidiaries are subject to taxation in their respective taxation years on their respective taxable incomes for the year.  Our Operating Subsidiaries intend to deduct, in computing their income for tax purposes, the full amount available for deduction in each year associated with their income tax resource pools, undepreciated capital costs (“UCC”) and non-capital losses, if any.  If there are not sufficient resource pools, UCC, non-capital losses carried forward, and interest to shelter the income of our Operating Subsidiaries, then cash taxes would be payable.  In addition, there can be no assurance that taxation authorities will not seek to challenge the amount of resource pools, non-capital losses or interest expense relating to the Series Notes.  If such a challenge were to succeed, it could materially adversely affect the amount of cash available for distri bution to Unitholders and the market value of our Trust Units.

The cash available for distribution to Unitholders is ultimately sourced from our Operating Subsidiaries, some of which are in the United States and, as a result, subject to U.S. taxation.  The Operating Subsidiaries that are subject to income taxation in the United States intend to deduct the full amount available in respect of depletion, depreciation, interest or other allowances under applicable law to reduce taxable income of such Operating Subsidiaries. There can be no assurances, however, that the taxation authorities of the United States will not challenge the amount of such deductions.  If such a challenge were to succeed it could materially adversely affect the amount of cash available for distribution to Unitholders.  Changes to the income tax law in the United States, changes to tax regulations in the United States, or changes in the interpretation or application of such law or regulati ons may result in increased taxation of funds generated in the United States and may adversely affect distributions to Unitholders and the market value of the Trust Units.

Interest and dividends that we receive from our Operating Subsidiaries in the United States will be subject to United States withholding taxes the amount of which will be determined under applicable law, income tax treaties and regulations.  In this regard, the United States Treasury Department has announced its intention to renegotiate one of the income tax treaties upon which we rely for a reduction in withholding taxes on distributions from our Operating Subsidiaries in the United States.  Changes in the applicable law, income tax treaties or regulations or in the application or interpretation thereof may increase such withholding taxes and may adversely affect distributions to Unitholders.

Unitholders may be required to pay taxes even if they do not receive any cash distributions.

Interest on the Series Notes and the CT Notes accrues at the Trust level for income tax purposes whether or not actually paid.  Our 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.  Our Trust Indenture provides that where, in a particular year, the Trust does not have sufficient available cash to distribute such an amount to the Unitholders, additional Trust Units will 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.

United States Unitholders may be limited in their ability to use the Canadian withholding tax as a credit against United States federal income tax and in their ability to claim the effect of certain other favourable United States income tax provisions.

We expect that the Trust will be classified for United States federal income tax purposes as a partnership and not as a corporation. As a result, a citizen of the United States and each other person who is subject to United States federal income tax on a net income basis with respect to the Trust Units (each such person is referred to herein as a U.S. Holder) will generally include its share of the income, gain, loss, deduction and credit of the Trust on its United States federal income tax return in determining its liability for the United States federal income tax.

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The Canadian income taxes that are withheld (currently at a 15 percent rate) from a distribution to a U.S. Holder on a Trust Unit may be deducted or, subject to limitations, used as a credit for United States federal income tax purposes. The limitation under United States law on foreign taxes that may be used as credits is calculated separately with respect to specific classes of income or “baskets”. That is, the use of foreign taxes that are paid with respect to income in any such basket as a credit is limited to a percentage of the foreign source income in that basket. Special rules apply in determining the foreign tax credit limitation with respect to dividends that are subject to the 15 percent rate (discussed below).  Under rules of general application, a portion of a U.S. Holder’s interest expense and other expenses can be allocated to, and thereby reduce, the foreign source income in an y basket. Any gain that is recognized by a U.S. Holder on the sale of a Trust Unit that is recognized because a distribution thereon is in excess of basis in that security will generally constitute income from sources within the United States for U.S. foreign tax credit purposes and will therefore not increase the ability to use foreign taxes as credits.

For a U.S. Holder who is a non-corporate Unitholder, its share of the Trust’s dividend income from its Canadian subsidiaries received before January 1, 2011 should be subject to United States federal income tax at a maximum rate of 15 percent provided that, among other things, (a) that the payor of the dividend is not classified as a PFIC during the taxable year in which such distribution is paid or the preceding taxable year, (b) that the U.S. Holder has satisfied certain holding period requirements, and (c) that the U.S. Holder has not made an election to treat the dividend as “investment income” for purposes of the investment interest deduction rules. In addition, the rate reduction will not apply to dividends if the recipient of a dividend is obligated to make related payments with respect to positions in substantially similar or related property. This disallowance applies even if the minimum holding period has been met. If the rate reduction is not applicable, the dividends would be subject to United States federal income taxation at ordinary income tax rates.

Each such U.S. Holder should discuss the effect of the limitations on the use of such Canadian taxes as a credit (including the effect of any ability to obtain a refund of such Canadian withholding tax in certain circumstances) and the limitations on obtaining the favourable United States federal rate reduction with its own advisers.

United States Unitholders who are generally tax exempt under United States law may recognize unrelated business taxable income (which is subject to United States federal income tax) in respect of their Trust Units.

Individual retirement accounts, other employee benefit plans and certain organizations that are generally exempt from United States federal income tax are subject to United States federal income tax on unrelated business taxable income, such as certain income from debt financed property, to the extent that such unrelated business taxable income for a taxable year is in excess of $1,000. The Trust has in the past and may in the further incur debt the proceeds of which are invested in stock of EEC or another corporation. In that event, the dividends that the Trust receives from such corporation (which flow through to the holders of Trust Units while the Trust is a treated as a partnership for United States federal income tax purposes) will be unrelated business taxable income.

Such an individual retirement account or other tax exempt organization will generally also be subject to Canadian withholding tax on distributions that the Trust makes and will as a general matter be able to use all or a portion of that Canadian withholding tax as a credit against the United States federal income tax for which it is liable on any unrelated business taxable income in accordance with applicable law and with due regard to the applicable restrictions thereon. Such Canadian income tax will not as a general matter reduce or otherwise affect the Untied States federal income taxation of distributions that an individual retirement account or other employee benefit plans makes to its beneficiary or beneficiaries.

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United States Unitholders may be subject to passive foreign investment company rules.

Although we do not expect that any of the Trust’s subsidiaries that are corporations for United States federal income tax purposes (or the Trust if it were to be a corporation for such purposes) is or has been a passive foreign investment company, or PFIC, there is no assurance in that regard.

A foreign corporation is, as a general matter, a PFIC if either (a) 75 percent or more of its gross income in a taxable year, including the pro rata share of the gross income of certain partially owned (whether directly or indirectly) corporations, is passive income (as defined in the pertinent provisions of the Code) or (b) 50 percent or more of its assets (including the pro rata share of the assets of any such partially owned subsidiary) are held for the production of, or to produce, passive income.

If the Trust or any of its subsidiaries were a PFIC, then a U.S. Holder who did not make an election to treat such corporation as a qualified electing fund (there is no assurance that it will be able to make such an election) would pay United States federal income tax on any “excess distributions” in respect of  the PFIC stock (even if such U.S. Holder did not own stock in the PFIC directly) is allocated rateably over the U.S. Holder’s holding period. The amounts allocated to the taxable year of the excess distribution and to any year before the relevant stock interest became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to United States federal income taxation at the highest rate in effect for individuals or corporations in such taxable year, as appropriate, and an interest charge would be imposed on the amount allocated to that ta xable year. Distributions made in respect of the relevant PFIC stock interest during a taxable year (including any gain realized on the sale or other disposition of the PFIC stock, even if the cash proceeds thereof were not received) will be an excess distribution to the extent they exceed 125 percent of the average of the annual distributions in respect of said stock interest received by the U.S. Holder during the preceding three taxable years or the U.S. Holder’s holding period, whichever is shorter. Moreover, any non-corporate Unitholder who is a U.S. Holder would not be entitled to the 15 percent maximum rate of Untied States federal income tax on any dividend that is received in respect of the stock in any such PFIC.

U.S. Holders are urged to consult their own tax advisors regarding the United States federal income tax consequences of classification as a PFIC of any corporation in which the Trust owns an interest (or the Trust) and of the consequences of such classification.

United States and other non-resident Unitholders may be subject to additional taxation.

The Tax Act and the tax treaties between Canada and other countries may impose additional withholding or other taxes on the cash distributions or other property paid by the Trust to Unitholders who are not residents of Canada, and these taxes may change from time to time.  For instance, since January 1, 2005, a 15 percent withholding tax is applied to return of capital portion of distributions made to non-resident Unitholders.

The ability of United States and other non-resident investors to enforce civil remedies may be limited.

The Trust is a trust organized under the laws of Alberta, Canada, and EEC’s principal offices are in Canada.  Most of our directors and officers are residents of Canada and most of the experts who provide services to us (such as its auditors and some of its independent reserve engineers) are residents of Canada, and all or a substantial portion of their assets and the assets of the Trust are located within Canada.  As a result, it may be difficult for investors in the United States or other non-Canadian jurisdictions (a “Foreign Jurisdiction”) to effect service of process within such Foreign Jurisdiction upon such directors, officers and representatives of experts who are not residents of the Foreign Jurisdiction or to enforce against them judgement of courts of the applicable Foreign Jurisdiction based upon civil liability under the securities laws of such Foreign Jurisdiction, i ncluding United States federal securities laws or the securities laws of any state within the United States.  In particular, there is doubt as to the enforceability in Canada against EEC or any of its directors, officers or representatives of experts who are not residents of the Untied States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the Untied States federal securities laws or the securities laws of any state within the United States.  

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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 the Trust Subsidiaries. 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 the Trust’s 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.

The limited liability of Unitholders of the Trust is uncertain.

Notwithstanding the fact that Alberta (the Trust’s governing jurisdiction) has adopted legislation purporting to limit Unitholder liability, because of uncertainties in the law relating to investment trusts, there is a risk that a Unitholder could be held 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 shareh older 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.  There can be no assurance that the Alberta legislation purporting to limit Unitholder liability eliminates the risk that a Unitholder could be held liable for obligations of the Trust, and the legislation does not affect liability with respect to any act, default, obligation or liability that arose prior to July 1, 2004.

The cash redemption rights of Unitholders are limited.

Unitholders have a 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 obligation to pay cash in connection with 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.

- 29 -

There may be future dilution.

One of our objectives is to continually add to our reserves through acquisitions and through development. Since at present we do not reinvest the majority 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.

Unitholders will also suffer dilution as a result of the conversion of any of the Trust’s Debentures, or if the Trust redeems outstanding Debentures for Trust Units or satisfies the obligation to pay interest on the Debentures by issuing additional Trust Units.  See “Capital Structure – Description of Debentures”.

Prior distributions are not reflective of future distributions.

Our historical distributions are not reflective of future distributions.  Future distributions will be subject to review by, and are in the discretion of, the board of EEC. On July 18, 2006, the board of EEC determined to reduce the Trust’s target payout ratio range to 60% to 70% of funds from operations. On January 19, 2007, the board of EEC announced a cash distribution of US$0.06 per Trust Unit in respect of January 2007 production, a reduction from the distribution of US $0.12 per Trust Unit paid in each of the prior six months, as a result of significantly weaker commodity prices, capital market uncertainty resulting from the tax changes proposed by the Canadian government, and early conversion of Debentures to Trust Units.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

The actual amounts distributed, if any, will be based on the circumstances as they exist at the time and will be subject to a number of factors, many of which are beyond our control including, without limitation, the outlook for commodity prices and other macro-economic factors, the availability and cost of equity and debt financing, the size and nature of the prospects and opportunities available to us, and our financial position and commitments.

There may not always be an active trading market for the Trust Units and Debentures.

While there is currently an active trading market for the Trust Units in the United States and Canada and for the Debentures in Canada, there are no assurances that an active trading market will be sustained.

- 30 -

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Disclosure of Reserves Data

The reserves data set forth below (the “Reserves Data”) is based upon evaluations conducted by McDaniel with an effective date of December 31, 2007 contained in the McDaniel Report, by Haas with an effective date of December 31, 2007 contained in the Haas Report and by MHA with an effective date of January 1, 2008 contained in the MHA Report.  The Reserves Data summarizes our oil, NGL and natural gas reserves and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs.  The McDaniel, Haas and MHA Reports have been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101.  Information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important.  We engaged McDaniel, Haa s and MHA to provide an evaluation of our proved and proved plus probable reserves.

At December 31, 2007 our reserves were in Canada, specifically, in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba, and in the United States, specifically in the states of Wyoming and Oklahoma.  McDaniel reviewed the reserves in Canada, Haas reviewed the reserves in Oklahoma and MHA reviewed the reserves in Wyoming.

All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimate future capital expenditures for wells to which reserves have been assigned.  It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of our properties.  There is no assurance that such price and cost assumptions will be attained, and variances could be material.  The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

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

The tables below are summaries of our oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated by McDaniel, Haas and MHA based on constant and forecast price and cost assumptions.  The tables summarize the data contained in the McDaniel, Haas and MHA Reports.  Gross reserves include royalty interests.  The data may contain slightly different numbers than the reports due to rounding.  Additionally, the numbers in the tables may not add exactly due to rounding.

The McDaniel, Haas and MHA Reports are based on certain factual data supplied by us and on McDaniel’s, Haas’ and MHA’s opinions of reasonable practice in the industry.  The extent and character of ownership and all factual data pertaining to our petroleum properties and contracts (except for certain information residing in the public domain) were supplied by us to McDaniel, Haas and MHA and were accepted without any further investigation.

- 31 -

Reserves Data – Forecast Prices and Costs

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue
Forecast Prices and Costs as of December 31, 2007

		Remaining Reserves
		Light and Medium Crude Oil		Heavy Oil		Natural Gas Liquids		Natural Gas		Total
Reserves Category		Gross (5) (mbbls)	Net(6) (mbbls)	Gross (5) (mbbls)	Net(6) (mbbls)	Gross (5) (mbbls)	Net(6) (mbbls)	Gross (5) (mmcf)	Net(6) (mmcf)	Gross (5) (mboe)	Net(6) (mboe)
CANADA(1)
	Producing	2,100	2,056	1,444	1,169	526	377	33,748	24,777	9,694	7,731
	Non-Producing	26	23	13	13	38	26	1,995	1,543	409	318
	Proved Undeveloped	182	154	120	80	18	13	2,454	1,756	730	540
Proved		2,308	2,232	1,577	1,261	582	416	38,196	28,076	10,833	8,589
Probable		1,155	1,056	662	495	246	177	24,083	17,591	6,076	4,660
Total Proved plus Probable		3,463	3,288	2,239	1,756	828	593	62,279	45,667	16,909	13,249
OKLAHOMA(2) (4)
	Producing	975	785	-	-	-	-	45,150	36,206	8,500	6,820
	Non-Producing	29	23	-	-	-	-	2,558	2,116	455	376
	Proved Underdeveloped	127	101	-	-	-	-	8,245	6,596	1,501	1,201
Proved		1,131	910	-	-	-	-	55,954	44,918	10,457	8,396
Probable		303	244	-	-	-	-	13,108	10,490	2,488	1,992
Total Proved plus Probable		1,434	1,154	-	-	-	-	69,062	55,408	12,944	10,388
WYOMING(3) (4)
	Producing	-	-	-	-	-	-	1,100	869	183	145
	Non-Producing	-	-	-	-	-	-	102	82	17	14
	Proved Underdeveloped	-	-	-	-	-	-	-	-	-	-
Proved		-	-	-	-	-	-	1,202	951	200	158
Probable		-	-	-	-	-	-	1,236	979	206	163
Total Proved plus Probable		-	-	-	-	-	-	2,438	1,930	406	322
AGGREGATE
	Producing	3,075	2,841	1,444	1,169	526	377	79,998	61,852	18,377	14,695
	Non-Producing	55	46	13	13	38	26	4,655	3,740	882	708
	Proved Underdeveloped	309	255	120	80	18	13	10,700	8,352	2,231	1,741
Proved		3,439	3,142	1,577	1,261	582	416	95,352	73,944	21,490	17,143
Probable		1,458	1,300	662	495	246	177	38,427	29,060	8,770	6,815
Total Proved plus Probable		4,897	4,442	2,239	1,756	828	593	133,779	103,004	30,260	23,959

Note:

(1)

Canada - from McDaniel Report.

(2)

Oklahoma – from Haas Report.

(3)

Wyoming – from MHA Report.

(4)

Oklahoma and Wyoming net present values have been converted to Cdn $ at 1.00 exchange rate

(5)

Gross refers to our working interest before royalties

(6)

Net refers to our working interest after royalties plus royalty interest reserves

- 32 -

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue
Forecast Prices and Costs as of December 31, 2007

		Before Income Taxes Discounted at (%/year)					After Income Taxes Discounted at (%/year)
		0	5	10	15	20	0	5	10	15	20
Reserves Category		MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
	Producing	233	206	185	169	156	212	187	168	154	142
	Non-Producing	(2)	(1)	(1)	(1)	(1)	(1)	(1)	(1)	(1)	(1)
	Proved Underdeveloped	10	8	7	5	4	7	6	4	3	2
Proved		242	213	191	174	160	218	191	172	156	144
Probable		149	107	81	64	52	111	78	58	45	36
Total Proved plus Probable		391	319	272	237	211	329	269	230	202	180
OKLAHOMA(2) (4)
	Producing	203	168	144	126	112	196	159	133	115	101
	Non-Producing	9	8	7	6	6	9	8	7	6	5
	Proved Underdeveloped	35	25	18	13	9	22	15	9	5	2
Proved		247	202	170	145	127	227	182	149	126	108
Probable		69	53	42	34	28	45	34	27	22	18
Total Proved plus Probable		316	255	212	180	155	273	216	176	147	126
WYOMING(3) (4)
	Producing	1	1	1	1	1	-	-	-	-	1
	Non-Producing	-	-	-	-	-	-	-	-	-	-
	Proved Underdeveloped	-	-	-	-	-	-	-	-	-	-
Proved		1	1	1	1	1	1	1	1	1	1
Probable		3	3	2	2	2	3	3	3	3	2
Total Proved plus Probable		4	3	3	3	3	4	3	3	3	3
AGGREGATE
	Producing	437	375	330	296	269	408	346	302	269	243
	Non-Producing	8	7	6	6	5	8	7	6	6	5
	Proved Underdeveloped	45	34	25	18	13	30	20	13	8	4
Proved		490	416	361	320	287	446	374	322	283	253
Probable		221	162	125	100	82	159	115	88	69	57
Total Proved plus Probable		711	578	486	420	370	605	488	409	352	309

Note:

(1)

Canada - from McDaniel Report.

(2)

Oklahoma – from Haas Report.

(3)

Wyoming – from MHA Report.

(4)

Oklahoma and Wyoming net present values have been converted to Cdn$ at 1.00 exchange rate

- 33 -

Undiscounted Future Net Revenue

Forecast Prices as of December 31, 2007
Total Revenues

	Revenue	Royalties	Operating Costs	Capital Development Costs	Abandonment Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
Reserves Category	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
Total Proved	589	114	196	12	25	242	24	218
Total Proved plus Probable	926	187	294	27	27	391	62	329
OKLAHOMA(2) (4)
Total Proved	556	137	146	25	1	247	20	227
Total Proved Plus Probable	681	166	169	26	2	316	44	273
WYOMING(3) (4)
Total Proved	8	2	5	-	1	1	-	-
Total Proved plus Probable	18	4	9	-	1	4	1	2
AGGREGATE
Total Proved	1,154	253	347	37	27	490	44	446
Total Proved Plus Probable	1,625	357	472	53	29	711	107	604

Note:

(1)

Canada - from McDaniel Report.

(2)

Oklahoma – from Haas Report.

(3)

Wyoming – from MHA Report.

(4)

Oklahoma and Wyoming net present values have been converted to Cdn$ at 1.00 exchange rate

- 34 -

Oil and Gas Reserves and Net Present Values by Production Group
Forecast Prices as of December 31, 2007
Total Reserves

		Discounted at 10%
		Canada	Oklahoma	Wyoming	Total
						Unit Value (2)
Reserves Category		MM$	MM$	MM$	MM$	$/bbl or $/mcf
Proved
	Light and Medium Crude Oil (1)	66.6	32.0	0.0	98.6	31.89
	Heavy Oil	22.7	-	0.0	22.7	18.02
	Natural Gas	101.5	137.6	0.9	240.0	3.32
Total		190.9	169.6	0.9	361.3
Proved Plus Probable
	Light and Medium Crude Oil (1)	95.5	40.5	0.0	136.0	31.11
	Heavy Oil	30.9	-	0.0	30.9	17.60
	Natural Gas	145.1	171.0	3.3	319.4	3.17
Total		271.5	211.5	3.3	486.3

Note:

(1)

Including by-products

(2)

Unit values are based on net reserve volumes

- 35 -

Oil and Gas Reserves and Net Present Values by Production Group
Forecast Prices as of December 31, 2007
Total Reserves

Reserves Group by Category
		Oil Gross Mbbl	Net Mbbl	Gas Gross Mmcf	Net Mmcf	NGL Gross Mbbl	Net Mbbl	Net Present Value Before Income Tax @ 10% M$	Unit Values(5) $/bbl or $/mcf
CANADA(1)
Light and Medium Oil (including Associated Gas and Byproducts)
	Proved Producing	2,047	2,007	1,107	824	38	27	66,227	33.00
	Proved Non-Producing	26	22	98	69	-	-	(3,611)	(160.65)
	Proved Undeveloped	182	154	167	121	1	1	4,011	26.06
	Total Proved	2,255	2,183	1,372	1,014	39	28	66,627	30.52
	Probable	1,135	1,038	689	495	18	13	28,911	27.85
	Total Proved & Probable	3,390	3,221	2,061	1,509	57	41	95,538	29.66
Heavy Oil (including Associated Gas and Byproducts)
	Proved Producing	1,444	1,169	707	524	36	26	22,035	18.85
	Proved Non-Producing	13	13	-	-	-	-	(52)	(4.12)
	Proved Undeveloped	120	80	16	15	-	-	754	9.41
	Total Proved	1,577	1,262	723	539	36	26	22,737	18.03
	Probable	662	495	199	156	8	6	8,189	16.54
	Total Proved & Probable	2,239	1,757	922	695	44	32	30,926	17.60
Non-Associated Gas (including Byproducts)
	Proved Producing	53	49	31,934	23,430	452	324	96,908	4.14
	Proved Non-Producing	-	-	1,897	1,474	38	26	2,713	1.84
	Proved Undeveloped	-	-	2,271	1,619	17	12	1,881	1.16
	Total Proved	53	49	36,102	26,523	507	362	101,502	3.83
	Probable	20	18	23,195	16,940	220	159	43,600	2.57
	Total Proved & Probable	73	67	59,297	43,463	727	521	145,102	3.34
OKLAHOMA(2) (4)
Light and Medium Oil (including Associated Gas and Byproducts)
	Proved Producing	975	785	-	-	-	-	28,356	35.12
	Proved Non-Producing	29	23	-	-	-	-	827	35.95
	Proved Undeveloped	127	101	-	-	-	-	2,804	27.76
	Total Proved	1,131	909	-	-	-	-	31,987	35.19
	Probable	303	244	-	-	-	-	8,542	35.01
	Total Proved & Probable	1,434	1,153	-	-	-	-	40,528	35.15
Heavy Oil (including Associated Gas and Byproducts)
	Proved Producing	-	-	-	-	-	-	-	-
	Proved Non-Producing	-	-	-	-	-	-	-	-
	Proved Undeveloped	-	-	-	-	-	-	-	-
	Total Proved	-	-	-	-	-	-	-	-
	Probable	-	-	-	-	-	-	-	-
	Total Proved & Probable	-	-	-	-	-	-	-	-
Non-Associated Gas (including Byproducts)
	Proved Producing	-	-	45,150	36,206	-	-	115,665	3.19
	Proved Non-Producing	-	-	2,558	2,116	-	-	6,375	3.01
	Proved Undeveloped	-	-	8,245	6,596	-	-	15,607	2.37
	Total Proved	-	-	55,953	44,918	-	-	137,647	3.06
	Probable	-	-	13,108	10,490	-	-	33,401	3.18
	Total Proved & Probable	-	-	69,061	55,408	-	-	171,049	3.09
WYOMING(3) (4)
Light and Medium Oil (including Associated Gas and Byproducts)
	Proved Producing	-	-	-	-	-	-	-	-
	Proved Non-Producing	-	-	-	-	-	-	-	-
	Proved Undeveloped	-	-	-	-	-	-	-	-
	Total Proved	-	-	-	-	-	-	-	-
	Probable	-	-	-	-	-	-	-	-
	Total Proved & Probable	-	-	-	-	-	-	-	-
Heavy Oil (including Associated Gas and Byproducts)
	Proved Producing	-	-	-	-	-	-	-	-
	Proved Non-Producing	-	-	-	-	-	-	-	-
	Proved Undeveloped	-	-	-	-	-	-	-	-
	Total Proved	-	-	-	-	-	-	-	-
	Probable	-	-	-	-	-	-	-	-
	Total Proved & Probable	-	-	-	-	-	-	-	-
Non-Associated Gas (including Byproducts)
	Proved Producing	-	-	1,100	869	-	-	763	0.88
	Proved Non-Producing	-	-	102	82	-	-	149	1.62
	Proved Undeveloped	-	-	-	-	-	-	-	-
	Total Proved	-	-	1,202	951	-	-	912	0.98
	Probable	-	-	1,236	979	-	-	2,398	2.45
	Total Proved & Probable	-	-	2,438	1,930	-	-	3,310	1.72
AGGREGATE
Light and Medium Oil (including Associated Gas and Byproducts)
	Proved Producing	3,022	2,792	1,107	824	38	27	94,583	33.88
	Proved Non-Producing	55	45	98	69	-	-	(2,784)	(61.87)
	Proved Undeveloped	309	255	107	121	1	1	6,815	26.72
	Total Proved	3,386	3,092	1,372	1,014	39	28	98,614	31.89
	Probable	1,438	1,282	669	495	18	13	37,453	29.21
	Total Proved & Probable	4,824	4,374	2,061	1,509	57	41	136,066	31.11
Heavy Oil (including Associated Gas and Byproducts)
	Proved Producing	1,444	1,169	707	524	36	26	22,035	18.85
	Proved Non-Producing	13	13	-	-	-	-	(52)	(4.00)
	Proved Undeveloped	120	80	16	15	-	-	754	9.43
	Total Proved	1,577	1,262	723	539	36	26	22,737	18.02
	Probable	662	495	199	156	8	6	8,189	16.54
	Total Proved & Probable	2,239	1,757	922	695	44	32	30,928	17.60
Non-Associated Gas (including Byproducts)
	Proved Producing	53	49	78,184	60,505	452	324	213,336	3.53
	Proved Non-Producing	-	-	4,557	3,672	38	28	9,237	2.52
	Proved Undeveloped	-	-	10,516	8,215	17	12	17,488	2.13
	Total Proved	53	49	93,257	72,392	507	362	240,061	3.32
	Probable	20	18	37,530	28,400	220	150	79,399	2.79
	Total Proved & Probable	73	67	130,795	100,801	727	521	319,461	3.17

Note:

(1)

Canada - from McDaniel Report.

(2)

Oklahoma – from Haas Report.

(3)

Wyoming – from MHA Report.

(4)

Oklahoma and Wyoming net present values have been converted to Cdn$ at 1.00 exchange rate

(5)

Unit values are based on net reserve volumes

- 36 -

Pricing Assumptions ⁽¹⁾
Forecast Prices and Costs
Summary of Price Forecasts
December 31, 2007

Year	WTI Crude Oil $US/bbl	Edmonton Light Crude Oil $/bbl	Alberta Bow River Hardisty Crude Oil $/bbl	Alberta Heavy Crude Oil $/bbl	Sask Cromer Medium Crude Oil $/bbl	Edmonton NGL Mix $/bbl	U.S. Henry Hub Gas Price $US/Mmbtu	Alberta Average Plantgate $/Mmbtu	British Columbia Average Plantgate $/Mmbtu	Inflation %	US/CAN Exchange Rate  $US/$
	(2)	(3)	(4)	(5)	(6)	(7)
2007(8)	72.30	76.35	53.25	44.90	65.40	54.80	6.95	6.25	6.25	2.0	1.000
2008	90.00	89.00	64.70	55.30	78.20	61.60	7.75	6.60	6.60	2.0	1.000
2009	86.70	85.70	62.30	53.20	75.30	60.20	8.40	7.20	7.20	2.0	1.000
2010	83.20	82.20	59.70	50.50	72.20	58.00	8.40	7.20	7.20	2.0	1.000
2011	79.60	78.50	57.00	48.70	69.00	55.80	8.40	7.20	7.20	2.0	1.000
2012	78.50	77.40	56.20	48.00	68.00	55.20	8.55	7.30	7.30	2.0	1.000
2013	77.30	76.20	55.30	47.20	66.90	54.70	8.75	7.50	7.50	2.0	1.000
2014	78.80	77.70	56.40	48.10	68.20	55.80	9.05	7.70	7.70	2.0	1.000
2015	80.40	79.30	57.50	49.10	69.60	57.10	9.30	7.95	7.95	2.0	1.000
2016	82.00	80.80	58.70	50.10	71.00	58.20	9.55	8.20	8.20	2.0	1.000
2017	83.70	82.50	59.90	51.10	72.50	59.50	9.80	8.45	8.45	2.0	1.000
2018	85.30	84.10	61.10	52.10	73.80	60.70	10.05	8.65	8.65	2.0	1.000
2019	87.00	85.80	62.30	53.10	75.30	62.00	10.35	8.90	8.90	2.0	1.000
2020	88.80	87.50	63.60	54.20	76.90	63.30	10.65	9.20	9.20	2.0	1.000
2021	90.60	89.30	64.80	55.30	78.40	64.70	10.95	9.45	9.45	2.0	1.000
2022	92.40	91.10	66.10	56.40	80.00	66.00	11.15	9.65	9.65	2.0	1.000
Thereafter	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	2.0	1.000

Note:

(1)

Pricing assumptions are from McDaniel December 31, 2007 forecast and are the same for the MHA, Haas and McDaniel reports

(2)

West Texas Intermediate at Cushing Oklahoma 40 degrees API/0.5% sulphur

(3)

Edmonton Light Sweet 40 degrees API/0.3% sulphur

(4)

Bow River at Hardisty, Alberta (Heavy stream)

(5)

Heavy crude oil 12 degrees API at Hardisty, Alberta (after deduction of blending costs to reach pipeline quality)

(6)

Midale Cromer crude oil 29 degrees API/2.0% sulphur

(7)

NGL mix based on 45 percent propane, 35 percent butane and 20 percent natural gasolines

(8)

Historical average prices for 2007

- 37 -

Reserves Data – Constant Prices and Costs

Summary of Oil and Gas Reserves and Net Present Value of Future Net Revenue
Constant Prices as of December 31, 2007
Total of All Areas

		Light and Medium Crude Oil		Heavy Oil		Natural Gas Liquids		Natural Gas		Total
Reserves Category		Gross (5) (mbbls)	Net(6) (mbbls)	Gross (5) (mbbls)	Net(6) (mbbls)	Gross (5)  (mbbls)	Net(6) (mbbls)	Gross (5)  (mmcf)	Net(6) (mmcf)	Gross (5)  (mboe)	Net(6)  (mboe)
CANADA(1)
	Producing	2,096	2,053	1,393	1,145	526	377	33,776	24,855	9,645	7,717
	Non-Producing	26	23	13	13	38	26	1,995	1,544	409	318
	Proved Undeveloped	182	154	120	82	18	13	2,454	1,756	730	542
Total Proved		2,304	2,229	1,526	1,240	583	416	38,224	28,154	10,784	8,577
Probable		1,156	1,057	713	537	245	177	24,031	17,622	6,119	4,708
Total Proved plus Probable		3,460	3,286	2,239	1,777	828	593	62,255	45,776	16,902	13,285
OKLAHOMA(2) (4)
	Producing	959	774	-	-	-	-	42,791	34,578	8,091	6,537
	Non-Producing	28	23	-	-	-	-	2,458	2,053	438	365
	Proved Undeveloped	125	100	-	-	-	-	7,940	6,392	1,449	1,166
Total Proved		1,112	897	-	-	-	-	53,190	43,024	9,977	8,068
Probable		300	241	-	-	-	-	12,571	10,115	2,395	1,927
Total Proved plus Probable		1,412	1,138	-	-	-	-	65,761	53,139	12,372	9,995
WYOMING(3) (4)
	Producing	-	-	-	-	-	-	956	755	159	126
	Non-Producing	-	-	-	-	-	-	84	68	14	11
	Proved Undeveloped	-	-	-	-	-	-	-	-	-	-
Total Proved		-	-	-	-	-	-	1,040	823	173	137
Probable		-	-	-	-	-	-	1,041	824	174	137
Total Proved plus Probable		-	-	-	-	-	-	2,081	1,647	347	275
AGGREGATE
	Producing	3,055	2,827	1,393	1,145	526	377	77,522	60,188	17,894	14,380
	Non-Producing	55	45	13	13	38	26	4,537	3,665	862	695
	Proved Undeveloped	307	254	120	82	18	13	10,395	8,148	2,178	1,707
Total Proved		3,417	3,126	1,526	1,240	583	416	92,454	72,000	20,934	16,782
Probable		1,455	1,298	713	537	245	177	37,643	28,562	8,687	6,772
Total Proved plus Probable		4,872	4,424	2,239	1,777	828	593	130,097	100,562	29,621	23,555

Note:

(1)

Canada - from McDaniel Report.

(2)

Oklahoma – from Haas Report.

(3)

Wyoming – from MHA Report.

(4)

Oklahoma and Wyoming net present values have been converted to Cdn$ at 1.00 exchange rate.

(5)

Gross refers to our working interest before royalties.

(6)

Net refers to our working interest after royalties plus royalty interest reserve.

- 38 -

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue
Constant Prices Case as of December 31, 2007
Total of All Areas

		Before Income Taxes Discounted at (%/year)					After Income Taxes Discounted at (%/year)
Reserves Category		0	5	10	15	20	0	5	10	15	20
		MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
	Producing	213	188	169	154	142	197	174	156	143	132
	Non-Producing	(2)	(1)	(1)	(1)	(1)	(1)	(1)	(1)	(1)	(1)
	Proved Undeveloped	8	6	5	4	3	6	4	3	2	1
Total Proved		219	192	172	157	144	201	177	158	144	132
Probable		127	93	72	57	46	95	69	52	41	33
Total Proved plus Probable		347	286	244	213	190	297	245	210	185	165
OKLAHOMA(2) (4)
	Producing	193	164	143	126	113	190	157	133	116	102
	Non-Producing	9	8	7	6	6	9	8	7	6	6
	Proved Undeveloped	33	24	18	13	9	21	14	9	5	2
Total Proved		236	197	168	145	127	220	179	149	127	110
Probable		64	51	41	34	28	42	33	26	21	18
Total Proved plus Probable		300	247	209	179	156	263	212	176	148	128
WYOMING(3) (4)
	Producing	-	-	-	-	-	-	-	-	-	-
	Non-Producing	-	-	-	-	-	-	-	-	-	-
	Proved Undeveloped	-	-	-	-	-	-	-	-	-	-
Total Proved		-	-	-	-	-	-	-	-	-	-
Probable		1	1	1	1	1	1	1	1	1	1
Total Proved plus Probable		1	1	1	1	1	1	1	1	1	1
AGGREGATE
	Producing	406	352	311	280	255	387	331	290	259	234
	Non-Producing	7	7	6	6	5	8	7	6	5	5
	Proved Undeveloped	41	31	23	16	11	27	18	12	7	3
Total Proved		455	389	340	302	271	422	356	308	271	242
Probable		193	145	114	92	76	139	102	79	63	51
Total Proved plus Probable		648	534	454	394	347	560	458	387	334	294

Note:

(1)

Canada - from McDaniel Report.

(2)

Oklahoma – from Haas Report.

(3)

Wyoming – from MHA Report.

(4)

Oklahoma and Wyoming net present values have been converted to CDN$ at 1.00 exchange rate.

- 39 -

Total Future Net Revenue (Undiscounted)
Constant Prices as of December 31, 2007
Total Reserves

	Revenue	Royalties	Operating Costs	Capital Development Costs	Abandonment Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Revenue After Income Taxes
Reserves Category	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
Total Proved	531	99	179	12	21	219	18	201
Total Proved plus Probable	818	159	263	27	22	347	50	297
OKLAHOMA(2) (4)
Total Proved	508	124	122	25	1	236	15	220
Total Proved plus Probable	620	152	140	26	2	300	37	263
WYOMING(3) (4)
Total Proved	6	1	3	-	1	-	-	-
Total Proved plus Probable	11	2	6	-	1	1	-	1
AGGREGATE
Total Proved	1,045	224	305	37	23	455	33	422
Total Proved plus Probable	1,448	314	409	53	25	648	88	560

Note:

(1)

Canada - from McDaniel Report.

(2)

Oklahoma – from Haas Report.

(3)

Wyoming – from MHA Report.

(4)

Oklahoma and Wyoming net present values have been converted to CDN$ at 1.00 exchange rate.

- 40 -

Oil and Gas Reserves and Net Present Values by Production Group
Constant Prices as of December 31, 2007
Total Reserves

		Discounted at 10%
		Canada	Oklahoma	Wyoming	Total
						Unit Value (2)
Reserves Category		MM$	MM$	MM$	MM$	$/bbl or $/mcf
Proved
	Light and Medium Crude Oil (1)	65.2	38.5	0.0	103.7	33.17
	Heavy Oil	16.6		0.0	16.6	13.40
	Natural Gas	90.6	129.0	0.2	219.8	3.09
Total		172.4	167.5	0.2	340.1
Proved Plus Probable
	Light and Medium Crude Oil (1)	94.7	49.3	0.0	144.0	32.55
	Heavy Oil	23.9		0.0	23.9	13.44
	Natural Gas	125.3	159.3	1.3	285.8	2.89
Total		243.9	208.6	1.3	453.7

Note:

(1)

Including by-products

(2)

The unit values are based on net reserve volumes

Pricing Assumptions ⁽¹⁾
Constant Prices and Costs

Year	WTI @ Cushing ($US/bbl)	Edmonton Par Price 40° API ($/bbl)	Bow River Medium 25° API ($/bbl)	Cromer Medium ($/bbl)	US Henry Hub Gas Price ($US/Mmbtu)	Alberta Average Plant gate Price ($/Mmbtu)	Natural Gas Liquids FOB Edmonton ($/bbl)	Exchange Rate ($US/$)
31-Dec-07	95.98	93.76	53.87	73.73	7.83	6.32	64.40	1.00

Note:

(1)

Pricing assumptions are the same for the Haas Report, the MHA Report and the McDaniel Report

- 41 -

Reserves Reconciliation

Reconciliation of Gross Reserves by Product Type
Forecast Prices and Costs

	Light and Medium Crude Oil			Natural Gas Liquids
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]
CANADA (1)
Opening balance – December 31, 2006	3,065.9	1,091.5	4,157.4	742.0	269.2	1,011.2
Extensions and Improved Recovery	98.4	370.8	469.2	14.3	9.5	23.8
Technical Revisions	430.6	(191.4)	239.2	(40.2)	(30.0)	(70.2)
Acquisitions	-	-	-	-	-	-
Dispositions	(332.6)	(116.4)	(449.0)	(6.7)	(3.2)	(9.9)
Production	(954.4)	-	(954.4)	(127.2)	-	(127.2)
Closing balance – December 31, 2007	2,307.9	1,154.5	3,462.4	582.2	245.5	827.7
UNITED STATES (2)
Opening balance – December 31, 2006	1,796.2	202.3	1,998.5	-	-	-
Extensions and Improved Recovery	79.6	31.4	110.9	-	-	-
Technical Revisions	(513.5)	69.3	(444.2)	-	-	-
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Production	(231.3)	-	(231.3)	-	-	-
Closing balance – December 31, 2007	1,131.0	303.0	1,434.0	-	-	-
AGGREGATE
Opening balance – December 31, 2006	4,862.1	1,293.8	6,155.9	742.0	269.2	1,011.2
Extensions and Improved Recovery	178.0	402.2	580.1	14.3	9.5	23.8
Technical Revisions	(82.9)	(122.1)	(205.0)	(40.2)	(30.0)	(70.2)
Acquisitions	-	-	-	-	-	-
Dispositions	(332.6)	(116.4)	(449.0)	(6.7)	(3.2)	(9.9)
Production	(1,185.7)	-	(1,185.7)	(127.2)	-	(127.2)
Closing balance – December 31, 2007	3,438.9	1,457.5	4,896.4	582.2	245.5	827.7

Note:

(1)

Canada - from McDaniel Report.

(2)

United States – from Haas and MHA Report.

- 42 -

Reconciliation of Company Gross Reserves by Product Type
Forecast Prices and Costs

	Associated and Non-Associated Gas			Heavy Oil
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mmcf]	[mmcf]	[mmcf]	[mbbl]	[mbbl]	[mbbl]
CANADA (1)
Opening balance – December 31, 2006	31,956.1	14,113.7	46,069.8	1,070.3	312.8	1,383.1
Extensions and Improved Recovery	2,760.4	2,472.1	5,232.5	-	-	-
Technical Revisions	707.6	652.6	1,360.2	(20.6)	(311.5)	(332.1)
Acquisitions	10,814.0	7,174.0	17,988.0	928.7	661.0	1,589.7
Dispositions	(766.1)	(329.5)	(1,095.6)	-	-	-
Production	(7,275.7)	-	(7,275.7)	(401.9)	-	(401.9)
Closing balance – December 31, 2007	38,196.3	24,082.9	62,279.2	1,576.5	662.3	2,238.8
UNITED STATES (2)
Opening balance – December 31, 2006	55,303.1	11,470.2	66,773.4	-	-	-
Extensions and Improved Recovery	4,599.9	1,903.0	6,502.9	-	-	-
Technical Revisions	6,904.3	970.6	7,874.9	-	-	-
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Production	(9,652.2)	-	(9,652.2)	-	-	-
Closing balance – December 31, 2007	57,155.2	14,343.8	71,499.0	-	-	-
AGGREGATE
Opening balance – December 31, 2006	87,259.2	25,583.9	112,843.2	1,070.3	312.8	1,383.1
Extensions and Improved Recovery	7,360.3	4,375.1	11,735.4	-	-	-
Technical Revisions	7,611.9	1,623.2	9,235.1	(20.6)	(311.5)	(332.1)
Acquisitions	10,814.0	7,174.0	17,988.0	928.7	661.0	1,589.7
Dispositions	(766.1)	(329.5)	(1,095.6)	-	-	-
Production	(16,927.9)	-	(16,927.9)	(401.9)	-	(401.9)
Closing balance – December 31, 2007	95,351.5	38,426.7	133,778.2	1,576.5	662.3	2,238.8

Note:

(1)

Canada - from McDaniel Report.

(2)

United States – from Haas and MHA Report

Undeveloped Reserves

Our undeveloped reserves were estimated by McDaniel and Haas in accordance with standards and procedures in the COGE Handbook and reserve definitions in NI 51-101. In general, undeveloped reserves are reserves scheduled to be developed within the next couple of years.

We have proved and probable undeveloped reserves in Canada and Oklahoma.  In Canada there are proved undeveloped reserves assigned to the Primate, Princess, Ricinus, Halkirk, Desan and the Cummings Y Unit assets.  Canadian proved undeveloped reserves of 2.5 Bcf of natural gas and 18.42 Mbbl of NGL and 302.3 Mbbl of oil (737 mboe) represent 7% of the total Canadian proved reserves on a boe basis. In 2007 we developed 332.2 mboe of proved plus probable reserves with drilling. In Desan, 6 development wells are planned for 2008/2009 to develop proved plus probable reserves of 5.6 Bcf and 29.9 Mbbl of NGL’s.  In the Cummings Y Unit, continued development and optimization of the water flood will develop 83.9 Mbbl with an additional 83.9 Mbbl of probable reserves.  Four undeveloped locations have been identified in the Princess asset with proved plus probable undeveloped reserves of 224.1 mbbl of oil.  The Halkirk asset has one proved undeveloped location and one probable undeveloped location, both follow up locations to the successful well drilled in 2007.  These Halkirk and Princess locations are to drilled in the 2008 and 2009. A deep gas proved undeveloped location has been identified in our Ricinus Leduc asset with proved plus probable reserves of 4.0 BCF.  We plan to drill this well in 2008. The finalization of the new Alberta royalty regime may impact the timing of drilling this well and the reserve classification.

- 43 -

In Oklahoma, there are proved undeveloped reserves of 8.2 Bcf of natural gas and 127 Mbbl of oil representing 14% of the total Oklahoma proved reserves and probable undeveloped reserves of 5.9 Bcf of natural gas and 145.5 Mbbl of oil representing 45% of the total probable reserves.  The planned development well drilling program of 25 to 35 wells per year for the next couple of years is anticipated to develop these reserves. The 2007 19 well drilling program added 6.5 BCF and 110.9 mbbl of oil of proved plus probable reserves

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, royalty rates and economic conditions. McDaniel, Haas and MHA, independent engineering firms, evaluate our reserves.

The Alberta government has proposed a new royalty regime but due to the uncertainties and lack of sufficient details to determine royalties for some product types the 2007 year end reserve report was prepared using the existing royalty regime.  The Canadian independent evaluation firms developed common high and low sensitivity cases to reflect the potential range of impact of the new royalty regime. The estimated impact to Enterra’s proved plus probable future net present value at 10 % is estimated at less than 3% reduction in net present value based on those sensitivity cases.

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.

- 44 -

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).  Note: all future development costs are associated with Canadian assets; there are no future development costs associated with our U.S. assets.

	Canada	Oklahoma	Wyoming	Total
	M$	M$	M$	M$
Constant Prices and Costs – Proved Reserves
Remaining 2008	11,121			11,121
2009	200			200
2010				0
2011				0
2012				0
Remaining Years	200			200
Total Undiscounted	11,521	0	0	11,521
Total Discounted at 10% per Year	10,895	0	0	10,895
Forecast Prices and Costs – Proved Reserves
Remaining 2008	11,343			11,343
2009	208			208
2010				0
2011				0
2012				0
Remaining Years	225			225
Total Undiscounted	11,777	0	0	11,777
Total Discounted at 10% per Year	11,129	0	0	11,129
Forecast Prices and Costs – Proved Plus Probable Reserves
Remaining 2008	25,839			25,839
2009	988			988
2010				0
2011				0
2012				0
Remaining Years	586			586
Total Undiscounted	27,414	0	0	27,414
Total Discounted at 10% per Year	25,782	0	0	25,782

Common Infrastructure Costs

Under the farm-in arrangement our US Farmout Partner will enter into a 3-year take or pay arrangement where the full cost of common infrastructure plus a 12% return on the investment will be recovered.

	Canada	Oklahoma(1)	Wyoming(1)	Total
	M$	M$	M$	M$
Constant Prices and Costs – Proved Reserves
Remaining 2008		25,404		25,404
Remaining Years		0		0
Total Undiscounted		25,404		25,404
Total Discounted at 10% per Year		23,095		23,095
Forecast Prices and Costs – Proved Reserves
Remaining 2008		25,404		25,404
Remaining Years		0		0
Total Undiscounted		25,404		25,404
Total Discounted at 10% per Year		23,095		23,095
Forecast Prices and Costs – Proved Plus Probable Reserves
Remaining 2008		25,835		25,835
Remaining Years		0		0
Total Undiscounted		25,835		25,835
Total Discounted at 10% per Year		23,486		23,486

Note:

(1)

Oklahoma and Wyoming net present values have been converted to CDN$ at 1.00 exchange rate.

- 45 -

We estimate that our internally generated cash flow will be sufficient to fund the future development costs disclosed above.  We typically have available three sources of funding to finance our capital expenditure program: internally generated cash flow from operations, debt financing when appropriate and new equity issues, if available on favourable terms.  

We expect to fund our total 2008 capital program with internally generated cash flow.

Oil and Gas Properties

Our core areas include a variety of assets in Western Canada in the provinces of British Columbia, Alberta and Saskatchewan.  In Alberta, the major producing fields are: Clair, Sylvan Lake, Provost-Alliance-Wainwright, Princess, Ricinus, Ferrier and Lochend.  In northeast British Columbia we have a significant producing area at Desan and in west-central Saskatchewan we have production in the Primate and Liebenthal pools.  In the United States our significant producing assets are located in Grant, Lincoln and Logan counties in Oklahoma.  We also have an inventory of minor producing assets, minor royalty interests, and various prospects of an exploitation and exploration nature on undeveloped lands in Alberta, British Columbia, Saskatchewan, Wyoming, Montana and Oklahoma, the development of which could significantly increase the size of our existing production and reserve base.

In late 2007 Enterra divested its interest in its non operated properties in the Princess area and in the first quarter of 2008 we divested our interest in the Sylvan Lake, Lochend, Ferrier, and Ricinus operated properties to reduce bank debt.

Northeast British Columbia

Our northeast British Columbia assets consist of our producing property in Desan and our undeveloped properties at Kotcho and Peggo-Pesh.

Desan

The Desan property is located 75 miles northeast of Fort Nelson, British Columbia in the gas producing greater Sierra area.  The primary producing zone is the Jean Marie formation.  This regional carbonate has historically been the target for sweet dry gas and provides very good initial production and a long life of slow decline ideally suited to predictable cash flow.  Although the Jean Marie is regionally gas charged the best reserves are discovered through detailed geological and geophysical analysis, pinpointing areas of secondary porosity associated with structures.  The Jean Marie, at 1,300 m (4,250 feet), is best exploited using under-balanced drilling technology in horizontal wells.

Enterra has acquired 45 square kilometres (17 square miles) of 3D seismic and 61 kilometres (38 miles) of trade 2D seismic.  Based upon our technical review of this information we re-entered a poorly performing well and turned it into a successful gas producer by drilling to a new target zone.  We plan to exploit this knowledge by pursuing a multi-well drilling program during the 2008/2009 winter drilling season.

In late 2007 Enterra’s undeveloped Sierra property was divested to a third party in exchange for their Gross Overriding Riding Royalty on our Desan production plus cash consideration. This transaction will enhance the long term value of the property and provide additional development opportunities.  The average production for December 2007 was 3.3 mmcf/d natural gas and 27 bbls/d of crude oil and NGL from a total of 23 wells.

McDaniel assigned total proved plus probable reserves of 20.6 Bcf of natural gas and 109 Mbbl of NGL to the Desan property, as of December 31, 2007.

- 46 -

Western Alberta  

In western Alberta, Enterra’s properties range from deep, high-rate foothills sour gas wells in Ricinus to mid-depth oil wells at Clair, Sylvan Lake, Lochend and Ferrier.  In late 2007 Enterra divested its interest in its non operated properties in the Princess area and in the first quarter of 2008 we divested our interest in our  Sylvan Lake, Lochend, Ferrier,  and  Ricinus operated  properties to reduce bank debt.

Clair

The Clair property is located 7 miles north of Grande Prairie, Alberta.  Our assets include a 100% working interest in 3,040 acres of land, 19 producing oil wells, 7 injection wells and an oil treating facility.  Gas is conserved and processed at the Tusk Energy Sexsmith gas plant and the oil is delivered into the Pembina Peace Pipeline System.

Production is primarily from the Doe Creek (Dunvegan) formation with a small amount of gas production from the Charlie Lake and Halfway formations. Production is light, 41°API gravity crude oil and solution gas from the Doe Creek oil pool.  This pool is being water flooded to maximize recovery. There is also gas production from one Charlie Lake gas well.  At December 31, 2007 there were 19 oil wells and one gas well producing a combined 765 bbl/d of oil and 850Mcf/d of raw solution gas on a working interest basis before royalties.  Enterra’s technical team has initiated several studies to optimize the efficiency of the water flood and to extend the pool boundaries.  The recommendations from this study will be implemented in 2008 and 2009.

McDaniel assigned proved plus probable reserves to the Doe Creek ‘A’ (Dunvegan) pool of 692 Mbbl of crude oil, 831 Mmcf of gas and 54 Mbbl of NGL, as of December 31, 2007.  Included in the total net proved reserves of Clair are reserves assigned to the 13-07-073-5W6 Charlie Lake/ Halfway gas well of 159 Mmcf of gas and 10 Mbbl of NGL.

Ricinus

Ricinus is located in the Rocky Mountain foothills, 80 miles northwest of Calgary. At Ricinus, Enterra is 50% owner of a deep (2,800 m 9,200 feet) high-rate Leduc reef sour gas well that has steady gross production of 10 mmcf/d.  This well has the capability to produce at higher rates but has been limited to maximize the value of the asset. After evaluating our 3D seismic information over the reef, Enterra has entered into discussions with our partner to further develop the pool.  Timing of this development is dependent on the Alberta Government final Alberta Deep Gas Royalty Regime and results of the partner discussions.

McDaniel assigned proved plus probable gas reserves of 6.1 Bcf of natural gas to the producing well.

Eastern Alberta

Provost-Alliance-Wainwright, Alberta

The Provost-Alliance-Wainwright producing area is located near Provost, Alberta. Major areas within the package are Alliance, Sounding Lake, Halkirk, Monitor, Provost Cummings Y Unit and Wainwright. We currently have 371 producing oil and gas wells in this area.

Production is obtained primarily from the Dina, Cummings and Belly River formations. Average production for December, 2007 was 1,010 bbl/d of oil and NGL and 1,000 Mcf/d of gas on a working interest basis before royalties.  In order to increase production and lower operating costs, we have and continue to optimize the well pumping systems and upgrade or consolidate oil batteries to handle higher volumes of total fluid and injection water.  Solution gas is currently conserved at most of the oil batteries.

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While these pools are mature, detailed geologic and engineering studies have identified significant potential for increases in both production and reserves through more efficient secondary recovery and exploitation of bypassed pay zones.  These studies are ongoing and will be put into practice in 2008.

McDaniel assigned proved plus probable reserves in the Provost-Alliance-Wainwright area of 2,368 Mbbl of oil 2,027 Mmcf of natural gas and 33 Mbbl of NGL, as of December 31, 2007.

Princess

Princess is located 100 miles southeast of Calgary.  The primary production is crude oil (27º API) from the Pekisko formation, a porous carbonate.  Much of Enterra’s land is covered by 3D seismic, and detailed geological and geophysical studies have outlined new development drilling opportunities which we plan to drill during 2008 and 2009.  In addition, significant potential lies in the Glauconite and Sunburst formations.  At year end 2007, Enterra had 20 wells in the Princess area and produced 293 bbl/d of crude oil and NGL and 0.52 mmcf/d of natural gas.

In late 2007 Enterra divested its non-operated Princess holdings to its partner.

McDaniel assigned total proved plus probable reserves in the Princess area of 556 Mbbl of crude oil, 924  Mmcf of natural gas and 12 Mbbl of NGL as of December 31, 2007.

Saskatchewan

In May 2007, Enterra purchased Trigger Resources. Included in the purchase were several pools in west central Saskatchewan, including Primate and Liebenthal.  In addition, there were several minor non-core pools scattered geographically.  McDaniel assigned total proved plus probable reserves of 15.5 Bcf of natural gas and 1,280 Mbbls of heavy oil to the Trigger Resources fields, as of December 31, 2007.

Primate

The Primate pool was the main producing asset of the Trigger Resources purchase and is 100% owned by Enterra. Production is from the McLaren formation and although the oil is a relatively heavy (11° API), its gasified nature allows high initial production rates of up to 250 bbls/day per well of oil under primary recovery.

The pool is covered by 3D seismic and three successful wells were drilled in 2007 to further delineate the pool edges. Plans for 2008 include drilling infill wells and completing a study of secondary recovery opportunities in the pool which potentially could double the ultimate recoverable reserves.

At year end 2007 the Primate area was producing nearly 1,000 bbls/day of crude oil and over 1,500 mcf/day of gas before royalties, and the Trust had over 22,000 net undeveloped acres of land.

Liebenthal

The gas production from the Liebenthal pool comes from the Viking formation. The three highly productive wells in the pool are 100% owned by Enterra. Seismic indicates that the pool is structurally controlled and future opportunities include infill drilling of the main pool and exploiting up-hole potential in the Belly River formation. At year end 2007, Liebenthal production was over 3,100 mcf/day of natural gas on a working interest basis before royalties, with more than 18,000 net undeveloped acres of land.

Powder River Basin, Montana and Wyoming

We have a variety of coal-bed methane assets in the Powder River Basin of Wyoming and southern Montana.  Average production for 2007 was approximately 143 BOE/d from the property near Gillette, Wyoming.  Several developing exploitation and exploration plays are located in various parts of the basin.  

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We also hold a significant acreage position in the Oyster Ridge area of southwest Wyoming.  Wet coal dewatering projects are currently underway with promising early indications while other areas are in the planning and evaluation stages with the emphasis on longer term potential.

Oklahoma

In Oklahoma, we have approximately 94,300 gross developed and undeveloped acres of land, with an average working interest of 80.4% at year end 2007, centered in Grant, Lincoln and Logan Counties.  We generally have 20-25% working interest in producing wells drilled by our US Farmout Partner, depending on the participation of other parties in the wells.  The key producing horizon is the Hunton formation.  The Hunton formation is a carbonate rock formation which has been largely ignored by the industry in areas with high water/hydrocarbon production ratios.  Over the last decade, new drilling and production techniques have enabled the profitable development of hydrocarbon production from these areas of the Hunton formation.  Extensive dewatering lowers pressure allowing the liberation and mobilization of oil and gas from smaller ro ck pores.  In our experience, total gross peak hydrocarbon production rates average 150 BOE/d per horizontal well within six months after drilling and tie-in.  The average gross proved plus probable reserves are approximately 280,000 boe per horizontal well.

Our average production for 2007 in Oklahoma was 25.6 Mmcf/d of natural gas and 630 bbl/d of crude oil and NGL.  Haas attributed total proved and probable reserves of 1,432 Mbbl of crude oil and 69.1 Bcf of natural gas to this area as of December 31, 2007, resulting in a RLI of 7.3 years. December 2007 rates were 23.2 Mmcf/d and 383 bbl/d oil.  These rates reflect the effects of the severe ice storm in early December that damaged the electrical infrastructure supplying power to our producing wells and water disposal systems.  Operating costs on our properties averaged $10.45/boe during 2007.  We maintain a fully staffed field office in Carney, Oklahoma about 50 miles northeast of Oklahoma City.  Our staff complement as of December 31, 2007 is 44 people including our Chief Operating Officer, US Operations.

We have approximately 46,100 net undeveloped acres in the Alfalfa, Grant, Lincoln and Logan Counties in Oklahoma. To date, we have identified more than 100 drilling locations on our properties.

Under a farmout agreement, the US Farmout Partner pays 100% of the costs of drilling and completing each well on Trust lands to earn a 70% working interest.  The farmout agreement requires the US Farmout Partner to drill not less than 30 wells during rolling twenty-month periods.  By the end of 2007, 30 producing wells had been drilled and completed, another well had been drilled and was awaiting completion, and three wells were drilling. In addition, two saltwater disposal wells had been drilled.   Enterra pays 100% of the costs of drilling the required water disposal wells and associated infrastructure, but recovers 100% of those costs plus interest over a 3-year period through a capital recovery agreement with the US Farmout Partner.

Oil and Gas Wells

The following table summarizes our interest as at December 31, 2007 in wells that are producing and non-producing:

	Producing				Non-Producing
	Oil		Gas		Oil		Gas		Grand Total
State/Province	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	339.0	238.1	132.0	49.1	250.0	197.1	41.0	25.1	762.0	509.5
British Columbia			26.0	26.0			9.0	9.0	35.0	35.0
Saskatchewan	15.0	14.2	15.0	15.0	4.0	4.0	23.0	22.0	57.0	55.2
Total	354.0	252.3	173.0	90.1	254.0	210.1	73.0	56.1	854.0	599.6
Oklahoma			129.0	91.0			44.0	33.7	173.0	124.7
Wyoming			66.0	59.4			194.0	119.6	260.0	179.0
Total			195.0	150.4			238.0	153.3	433.0	303.7
Grand Total	354.0	252.3	368.0	240.5	254.0	210.1	311.0	200.4	1,287.0	903.3

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Land Holdings

The following table summarizes land holdings in which Enterra has an interest at December 31, 2007.  The expiring acreage is being evaluated and attempts will be made to continue the acreage based on current activity which is focused on exploitation of up-hole potential in existing wells.

Area	Gross Acres	Net Acres
Canada	412,373	259,058
U.S.	226,506	160,585
Total	638,879	419,643

The following table summarizes land holdings in which Enterra has an interest after giving effect to the sale of assets in Alberta completed in Q1 2008.

Area	Gross Acres	Net Acres
Canada	360,643	244,532
U.S.	225,226	159,305
Total	585,869	403,837

Environmental Protection

Our operations in Canada and the United States are subject to stringent government laws and regulations regarding pollution, protection of the environment and the handling and transport of hazardous materials.  These laws and regulations may impose administrative, civil and criminal penalties as well as joint and several, strict liability for failure to comply, and generally require us to remove or remedy the effect of our activities on the environment and present and former operating sites, including dismantling production facilities and remediate damage caused by the use or release of specified substances.  The Board reviews our environment policy and our compliance with applicable laws and regulations.  Monitoring and reporting programs for environment, health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to pro vide assurance that environmental and regulatory standards are met.  Contingency plans are in place for a timely response to an environmental event and remediation/reclamation programs are in place and utilized to restore the environment.

We currently own or lease, and have in the past owned or leased, properties that have been used for oil and natural gas exploration and production activities for many years.  Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal.  In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes were not under our control, including when these properties were owned or leased by any previous owner(s).  These properties and the materials disposed or released on them may be subject to joint and several, strict liability laws at the federal, state and/or provincial levels.  Unde r such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.  We are currently involved in several remediation projects but we do not believe these costs to be material to our operations or financial position.

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We expect to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed.  Between late 2006 and mid-2007, the Trust experienced three pipeline failures in Canada.  As well, we experienced three spills that required clean-up beyond our facility lease in Oklahoma.  While the balance of the environmental reclamation work has been completed, there will be some work including vegetation and subsequent monitoring with the potential for further evaluation required for these areas.  Beyond these specific pipeline repair sites, we do not anticipate making any material expenditure for any reclamation work other than normal compliance with the environmental regulations in 2007.

Abandonment and Reclamation Costs

We estimate well abandonment costs on an area-by-area basis.  Such costs are included in the Reserve Reports as deductions in arriving at future net revenue.  The expected total abandonment costs included in the Reserve Reports under the proved reserves category is $27.0 million undiscounted, $13.6 million discounted at 10% to abandon 599.6 net wells. It is estimated the approximately $3.0 million of this total will be spent over the next 3 years.

Tax Horizon

Canadian

Under the current structure, cash is transferred to the Trust by way of interest and redemptions of securities from the operating subsidiaries to the Trust.  The Trust, in turn, allocates all of its taxable income to the unitholders.  With the exception of capital taxes in certain provinces, no Canadian income taxes are currently expected to be incurred by the Trust or its Canadian operating subsidiaries.

United States

U.S. income related cash taxes have not been paid by the Trust or its U.S. Operating Subsidiaries for the year ended December 31, 2007.  The income from our U.S. operations (reduced by any deductible interest expense on debt held by the Trust or its Canadian Operating Subsidiaries) is subject to United States income tax under U.S. income tax rules and regulations.  As a result, our U.S. operations may incur cash U.S. income taxes in the future.  In addition, as funds are repatriated to Canada, withholding taxes that are required by U.S. tax law may become payable.

Costs Incurred

The following table summarizes the expenditures made by Enterra for the year ended December 31, 2007:

		(millions)
	Canada		United States	Total
Property acquisition costs(1)
Proved	$63.3		$    -	$63.3
Unproved	-		5.3	5.3
Exploration costs	-		-	-
Development costs	16.0		10.4	26.4
Total costs incurred	$79.3		$15.7	$95.0

(1) Includes costs related to corporate acquisitions.

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Exploration and Development Activities

The following table sets forth the gross and net development wells that we participated in during the year ended December 31, 2007.  We did not participate in any exploration wells during 2007.  In the farm-in arrangement with the US Farmout Partner in Oklahoma, we have had no interest in dry holes and have a carried interest in producing wells.  The carried interest in the producing wells is shown in this table for wells associated with this arrangement.

	Development Wells
	Canada		United States		Total
	Gross	Net	Gross	Net	Gross	Net
Light and Medium Oil	8	5.4	-	-	8	5.4
Natural Gas	4	1.1	19	4.3	23	5.4
Dry	1	1.0	-	-	1.0	1.0
Total	13	7.5	19	4.3	32	11.8

Production Volume by Field

The following table discloses for each major field, and in total, the Trust’s production volumes for the financial year ended December 31, 2007 for each product type.

	Crude oil (bbls)	NGL (bbls)	Natural Gas (Mcf)	Total (boe)
Clair	332,312	12,463	417,723	414,395
Provost	317,301	6,655	103,627	341,227
Brooks	151,822	4,038	371,909	217,844
Sylvan Lake	126,055	10,261	205,441	170,556
Desan	1,921	8,538	1,940,044	333,799
Saskatchewan	232,728	5	1,354,403	458,466
Ferrier/Ricinus	118,559	82,468	2,556,821	627,165
Other Canadian	75,578	2,772	320,414	131,754
Wyoming	-	-	314,158	52,360
Oklahoma	231,304	-	9,652,161	1,839,998
Total	1,587,580	127,200	17,236,701	4,587,555

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Production Estimates

The following table discloses, for each product type, the total volume of production estimated by McDaniel, Haas and MHA for 2008 in the estimates of future net revenue from proved reserves disclosed above under the heading “Summary of Oil and Natural Gas Reserves and Net Present Value of Future Net Revenue”.  The following estimates are applicable under both constant and forecast price scenarios.

Average 2008 Production Estimated
Forecast Prices and Costs

		Light and		Natural
		Medium		Gas	Natural
		Crude Oil	Heavy Oil	Liquids	Gas	Total
		Gross	Gross	Gross	Gross	Gross
	Reserve Category	[bbl/d]	[bbl/d]	[bbl/d]	[mcf/d]	[BOE/d]
CANADA (McDaniel Report)
Proved
	Producing	1,895	1,346	313	19,793	6,853
	Non-Producing	17	9	4	729	152
	Undeveloped	53	95	7	476	234
Total Proved		1,965	1,450	324	20,998	7,239
Probable		149	240	19	1,566	669
Total Proved plus Probable		2,114	1,690	343	22,564	7,908
OKLAHOMA (Haas Report)
Proved
	Producing	513			23,255	4,389
	Non-Producing	14			1,590	279
	Undeveloped	6			911	158
Total Proved		533	0	0	25,756	4,826
Probable		50			2,069	395
Total Proved plus Probable		583	0	0	27,825	5,221
WYOMING (MHA Report)
Proved
	Producing				1,341	224
	Non-Producing				74	12
	Undeveloped					0
Total Proved		0	0	0	1,415	236
Probable					352	59
Total Proved plus Probable		0	0	0	1,767	295
UNITED STATES
Proved
	Producing	513			24,596	4,612
	Non-Producing	14			1,664	291
	Undeveloped	6			911	158
Total Proved		533	0	0	27,171	5,062
Probable		50			2,421	454
Total Proved plus Probable		583	0	0	29,592	5,515
AGGREGATE
Proved
	Producing	2,408	1,346	313	44,389	11,465
	Non-Producing	31	9	4	2,393	443
	Undeveloped	59	95	7	1,387	392
Total Proved		2,498	1,450	324	48,169	12,300
Probable		199	240	19	3,987	1,123
Total Proved plus Probable		2,697	1,690	343	52,156	13,423

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Quarterly Data

The following table discloses, on a quarterly basis for the year ended December 31, 2007, our share of average daily production volumes, prior to royalties, average prices received, royalties paid, operating expenses incurred and netbacks on a per unit of volume basis.

	Quarter ended 2007
	March 31	June 30	September 30	December 31
Average Daily Production
Oil (bbl/d)	4,594	4,788	4,824	4,585
Natural Gas (Mcf/d)	43,573	48,514	47,846	45,538
Combined (BOE/d)	11,856	12,874	12,798	12,174
Average Prices Received
Oil ($/bbl)	57.66	60.29	63.56	64.23
Natural Gas ($/Mcf)	7.88	7.37	6.74	6.20
Netback
Revenues – combined ($/boe)(1)	51.04	50.06	48.99	47.36
Royalties – combined ($/boe)	11.24	11.18	8.00	9.70
Operating Expenses – combined ($/boe)	14.59	12.83	14.17	15.66
Operating Netback Received - combined ($/boe)	25.21	26.05	26.82	22.00

(1) Prior to unrealized mark-to-market.

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RESERVE DATA CHANGES SINCE DECEMBER 31, 2007

Since December 31, 2007 Enterra has completed the sale of the following assets; Sylvan Lake, Lochend, Ricinus Cardium, and Ferrier east and west. The reserves related to these properties based upon the McDaniel Report are in the table below.

The 2008 production estimated for these properties based upon the McDaniel Report is 332 bbl/d of oil, 4,169 mcf/d for natural gas and 228 bbl/d of natural gas liquids.  The undiscounted abandonment liability associated with these assets is $2.6 million and the undiscounted future development costs are $1.3 million.  There were 192 gross wells and 73.8 net wells in these assets.

Summary of Reserves and Net Present Value
Forecast Prices as of December 31, 2007
Total of Q1 2008 Divestitures

		Light and Medium Crude Oil		Heavy Oil				Natural Gas Liquids			Natural Gas				Total
Reserves Category		Gross (5) (mbbls)	Net(6) (mbbls)	Gross (5) (mbbls)		Net(6) (mbbls)		Gross (5)  (mbbls)	Net(6) (mbbls)		Gross (5)  (mmcf)		Net(6) (mmcf)		Gross (5)  (mboe)	Net(6)  (mboe)
CANADA (McDaniel Report)
	Producing	49	47	522		479		404	287		7,661		6,258		2,251	1,856
	Non-Producing	-	-	-		-		5	4		102		83		22	17
	Proved Undeveloped	-	-	-		-		15	11		291		234		64	50
Total Proved		49	47	522		479		424	302		8,054		6,575		2,337	1,923
Probable		19	17	115		105		165	115		3,183		2,590		829	669
Total Proved plus Probable		68	64	637		584		589	417		11,237		9,165		3,166	2,592
					Net Present Values of Future Net Revenue Before Tax
					0%		5%			10%		15%		20%
CANADA (McDaniel Report)					MM$		MM$			MM$		MM$		MM$
	Producing				57		49			42		37		33
	Non-Producing				-		-			-		-		-
	Undeveloped				1		1			1		-		-
Total Proved					58		50			43		37		34
Probable					26		16			12		9		7
Total Proved plus Probable					84		66			55		46		41

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CAPITAL STRUCTURE

The Trust Indenture

Our principal undertaking is to issue Trust Units and to acquire and hold debt instruments, securities, royalties and other interests.  The Operating Subsidiaries 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 the Trust Subsidiaries to the Trust primarily through (i) payments of interest and principal in respect of the Series Notes, (ii) payments of interest and principal in respect of the CT Notes, and (iii) dividends declared on the common shares of certain Operating Subsidiaries and/or redemptions of preferred shares of certain Operating Subsidiaries, which amounts are transferred from EECT to the Trust as payments of interest or principal on the CT Notes.  Cash flow received by the Trust is distributed to our Unitholders on a monthly basis.  

Trust Units and Other Securities

Trust Units

An unlimited number of Trust Units may be created and issued pursuant to our Trust Indenture.  See “Description of Trust Units”.

Series Notes

The Series Notes are unsecured debt obligations of the Operating Subsidiaries and are subordinated to all of our Senior Indebtedness.  They bear interest at various annual rates, expire at various dates up to 2033 and the principal amounts of the notes vary as additional funds are loaned by us to the Operating Subsidiaries or as principal repayments are made on the notes.  Interest for each month is payable monthly in arrears on the 15^th day of the month.

CT Notes

The CT Notes are subordinated, demand participating promissory notes.  The CT Notes were issued by EECT to the Trust. Redemptions and returns of capital on shares of EEC held by EECT may be made from time to time and applied as prepayments of the principal amount of the CT Notes.  The CT Notes bear interest at a rate that is reset from time to time to approximate the return on investments held by EECT.

Income Streams

A portion of the cash flows generated by the assets held, directly or indirectly, by the Trust is distributed to our Unitholders.  Our Trustee may, upon the recommendation of the board of EEC in respect of any period, declare payable to our Unitholders all or any part of the net income of the Trust.  The Trust’s primary sources of cash flow are payments of interest and repayments of principal from the Trust Subsidiaries in respect of indebtedness of each of those entities to and in favour of the Trust.

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Unitholder Limited Liability

Our Trust Indenture provides that no Unitholder, in its capacity as such, shall incur or be subject to any liability in contract or in tort or of any other kind whatsoever, including taxes payable, 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 our 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.

Our 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 our 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.

The activities of the Trust and the Trust Subsidiaries are conducted in such a way, upon advice of counsel, and in such jurisdictions as to avoid as far as possible any material risk of liability to our Unitholders for claims against the Trust including by obtaining appropriate insurance, where available, for the operations of the Operating Subsidiaries and by 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

Our 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 our Trustee may determine, including, without limitation, instalment or subscription receipts.  Our Trust Indenture also provides that our Trustee 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 our Trustee may determine.

Trustee

Olympia Trust Company is the Trustee of the Trust. The Trustee is responsible for, among other things, accepting subscriptions for Trust Units and issuing Trust Units pursuant thereto, maintaining the books and records of the Trust and providing timely reports to our Unitholders. 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 was until the third annual meeting of Unitholders in May, 2006.  At the June 2007 annual meeting the Unitholders re-appointed Olympia Trust Company as 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 Unitholders.  Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

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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 EEC, or any other person to whom the Trustee has, with the consent of EEC, delegated any of its duties hereunder, or any other action or failure to act (incl uding failure to compel in any way any former trustee to redress any breach of trust or any failure by EEC 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.

Special Voting Rights

The Trust Indenture allows for the creation and issuance of an unlimited number of Special Voting Rights which enable the Trust to provide voting rights to holders of securities issued by certain Trust Subsidiaries (such as exchangeable shares) that may be issued by subsidiaries of the Trust in connection with exchangeable share transactions.

Holders of Special Voting Rights are not entitled to any distributions of any nature whatsoever from the Trust.  Each holder is entitled to attend and vote at meetings of Unitholders according to the terms of the instrument pursuant to which the Special Voting Rights are issued.  Each holder of outstanding 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 Unitholders. 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.

Redemption Right

Our 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 and a duly completed and properly executed notice requiring redemption. Upon receipt of the notice to redeem Trust Units by our transfer agent, the holder thereof will only be entitled to receive a price per Trust Unit (the “Market Redemption Price”) equal to the lesser of: (iii) 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 (iv) 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 red emption. 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.

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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 Un its 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.

We will pay the aggregate Market Redemption Price in respect of any Trust Units surrendered for redemption during any calendar month by cheque 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 we may, in our 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 will be paid on the last day of the following month as follows: (i) secondly, to the extent that the Trust does not hold Series N otes having a sufficient principal amount outstanding to effect such payment, by the Trust issuing its own promissory notes to 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 Notes and the issuance of any Redemption Notes will 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 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 our Trust Indenture relating to such Series 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) trading of our outstanding Trust Units is suspended or halted on any stock exchange on which our 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 EEC 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 i n any calendar month will be paid on the last day of the third following month by, at the option of the Trust: (i) a distribution of Series Notes and/or Redemption Notes as described above.

It is anticipated that this redemption right will not be the primary mechanism for holders of our Trust Units to dispose of their Trust Units. Series 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 Notes or Redemption Notes. Series 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

Our Trust Indenture provides that meetings of our Unitholders must be called and held for, among other matters, the election or removal of our Trustee, the appointment or removal of our auditors, the approval of amendments to our 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.

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A meeting of our Unitholders may be convened at any time and for any purpose by our Trustee and must be convened, except in certain circumstances, if requisitioned in writing by: (i) 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 our Unitholders. A requisition must, among other things, state in reasonable detail the business purpose for which the meeting is to be called.

Unitholders and holders of Special Voting Rights may attend and vote at all meetings of Unitholders either in person or by proxy and a proxy holder need not be a Unitholder. Two persons present in person or represented by proxy and representing in the aggregate at least 5% of the votes attaching to all outstanding Trust Units shall constitute a quorum for the transaction of business at all such meetings. For 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.

Our Trust Indenture contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of our Unitholders in accordance with the requirements of applicable laws.

Exercise of Voting Rights

Our Trustee is prohibited from authorizing or approving:

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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;

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any merger, amalgamation, arrangement, reorganization, recapitalization, business combination or similar transaction as the case may be, of the Trust with any other person, except: (i) in conjunction with an internal reorganization as referred to in the bulleted paragraph above, or (ii) where immediately following completion of such transaction, the holders (or affiliates thereof) of equity interests in such other person (such holder being determined immediately prior to the entering into of such transaction) do not hold, directly or indirectly (on a fully diluted basis), more than 50% of, as applicable, (x) the issued and outstanding voting rights attributable to securities of the issuer which results from such transaction, or (y) the issued and outstanding Trust Units; or

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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 the first bulleted paragraph above;

without the prior approval of our Unitholders by Special Resolution at a meeting of Unitholders called for that purpose.

In addition, our Trustee is prohibited from authorizing EECT to vote any shares of EEC in respect of:

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any sale, lease or other disposition of, or any interest in, all or substantially all of the assets owned, directly or indirectly, by EEC, the Trust or EPP, except in conjunction with an internal reorganization of the direct or indirect assets of EEC, EECT or EPP, as the case may be, as a result of which EECT 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;

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any merger, amalgamation, arrangement, reorganization, recapitalization, business combination or similar transaction as the case may be, of the Trust with any other person, except: (i) in conjunction with any internal reorganization as referred to in the bulleted paragraph above, or (ii) where immediately following completion of such transaction, the holders (or affiliates thereof) of equity interests in such other person (such holders being determined immediately prior to the entering into of such transaction) do not hold, directly or indirectly (on a fully diluted basis), more than 50% of, as applicable, (x) the issued and outstanding voting rights attributable to securities of the issuer which results from such transaction, or (y) the issued and outstanding Trust Units;

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•

the winding up, liquidation or dissolution of EEC, EECT or EPP prior to the end of the term of EECT, except in conjunction with an internal reorganization as referred to in the first bulleted paragraph above;

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

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any material amendments to the articles of EEC to change the authorized share capital or amend the rights, privileges, restrictions and conditions attaching to any class of EEC’s shares in a manner which may be prejudicial to EECT; or

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any material amendment to the EECT indenture or the EPP partnership agreement which may be prejudicial to EECT;

without the prior approval of our Unitholders by Special Resolution at a meeting of Unitholders called for that purpose.

Finally, our Trustee is prohibited from authorizing EECT to vote any shares of EEC 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 EEC by ordinary resolution or special resolution, without the prior approval of our Unitholders by ordinary resolution or special resolution, as the case may be.

Amendments to the Trust Indenture

Our Trust Indenture may be amended or altered from time to time by Special Resolution of our Unitholders.  On May 18, 2006, the Unitholders by Special Resolution, approved an amendment to our Trust Indenture which somewhat broadens the ability of the Trust to undertake certain types of corporate transactions without the necessity of obtaining Unitholder approval, unless otherwise required by applicable law.  Our Trustee may, without the approval of our Unitholders, amend our Trust Indenture for the purpose of:

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

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ensuring that the Trust will satisfy the provisions of each of subsections 108(2) and 132(6) and paragraph 132(7)(a) of the Tax Act as from time to time amended or replaced;

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providing for and ensuring (i) the filing of income tax returns necessary or desirable for the purposes of United States federal income tax; or (ii)compliance by the Trust with any other applicable provisions of United States federal income tax law;

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removing or curing any conflicts or inconsistencies between the provisions of our 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, or any applicable law or regulation of any jurisdiction, provided that in the opinion of our Trustee the rights of our Trustee and of our Unitholders are not prejudiced thereby;

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curing, correcting or rectifying any ambiguities, defective or inconsistent provisions, errors, mistakes or omissions, provided that in the opinion of our Trustee the rights of our Trustee and of our Unitholders are not prejudiced thereby;

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changing the situs of or the laws governing the Trust, which, in the opinion of our Trustee, is desirable in order to provide Unitholders with the benefit of any legislation limiting their liability; and

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

Takeover Bid

Our Trust Indenture contains provisions to the effect that if a takeover bid is made for our 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 our Trust Units, any holder of a security exchangeable directly or 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: (i) a meeting may only be held for the purpose of such a vote if requested in writing by the holders of not less than 20% of our outstanding Trust Units and Special Voting Rights; (ii) a quorum of the holders of 50% of the issued and outstanding Trust Units and Special Voting Rights must be present in person or by proxy; and (iii) the termination must be approved by Special Resolution of our Unitholders.

Unless the Trust is earlier terminated or extended by vote of our Unitholders, the Trust will 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, our 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 our Unitholders in respect of the termination authorized pursuant to the Special Resolution of Unitholders authorizing the termination of the Trust. After paying, retiring or discharging or making provision for the payment, retire ment or discharge of all known liabilities and obligations of the Trust and providing for indemnity against any other outstanding liabilities and obligations, our Trustee shall distribute the remaining proceeds of the sale of the assets together with any cash forming part of the property of the Trust among our Unitholders in accordance with their pro rata interests.

Reporting to Unitholders

An independent recognized firm of chartered accountants audits the financial statements of the Trust annually.  The audited consolidated financial statements of the Trust, together with the report of such chartered accountants, will be mailed by our 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.

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The Trust is subject to the reporting requirements of the U.S. Exchange Act applicable to foreign private issuers, and in connection therewith will file or submit reports, including annual reports and other information with 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 are also available to the public on the SEC’s web site at www.sec.gov.

Description of Debentures

General

Our Debentures were issued under a debenture trust indenture (the “Debenture Indenture”) dated as of November 21, 2006 and April 26, 2007 among the Trust, EEC and Olympia Trust Company (the “Debenture Trustee”). An unlimited number of Debentures are authorized for issue.

Our Debentures are dated as of November 21, 2006 and April 26, 2007 respectively.  They were issuable only in denominations of $1,000 and integral multiples thereof. The maturity date for the Debentures is December 31, 2011 and June 30, 2012 respectively.

Our Debentures bear interest from the date of issue at 8.0% and 8.25% per annum, which is payable semi-annually in arrears on June 30 and December 31 in each year, commencing June 30, 2007 and December 31, 2007 respectively.

The principal amount of our Debentures is payable in lawful money of Canada or, at our option and subject to applicable regulatory approval, by payment of our Trust Units as further described under “Payment upon Redemption or Maturity” and “Redemption and Purchase”. The interest on our Debentures is payable in lawful money of Canada including, at our option and subject to applicable regulatory approval, in accordance with the Unit Interest Payment Election as described under “Interest Payment Option”.

Our Debentures are direct obligations of the Trust and are not secured by any mortgage, pledge, hypothec or other charge and are subordinated to other liabilities of the Trust as described under “Subordination”.  Other than as described herein, the Debenture Indenture do not restrict us from incurring additional indebtedness or liabilities or from mortgaging, pledging or charging our properties to secure any indebtedness.

Conversion Privilege

Our Debentures are convertible at the holder’s option into fully paid and non-assessable Trust Units at any time prior to the close of business on the earlier of the maturity date and the business day immediately preceding the date specified by us for redemption of our Debentures, at a conversion price of $9.25 and $6.80 per Trust Unit respectively, being a conversion rate of 108.1081 and 147.0588 Trust Units for each $1,000 principal amount of Debentures respectively. Holders converting their Debentures will receive all accrued and unpaid interest thereon in cash to the date of conversion.

Subject to the provisions thereof, the Debenture Indenture provides for the adjustment of the conversion price in certain events including: (a) the subdivision or consolidation of our outstanding Trust Units; (b) the distribution of our Trust Units to holders of Trust Units by way of distribution or otherwise other than an issue of securities to holders of our Trust Units who have elected to receive distributions in securities of the Trust in lieu of receiving cash distributions paid in the ordinary course; (c) the issuance of options, rights or warrants to all or substantially all of the holders of our Trust Units entitling them to acquire our Trust Units or other securities convertible into our Trust Units at less than 95% of the then current market price (as defined below) of our Trust Units; and (d) the distribution to all or substantially of the holders of our Trust Units of any securities or assets (other than cash distributions and equivalent distributions in securities paid in lieu of cash distributions in the ordinary course). There will be no adjustment of the conversion price in respect of any event described in (b), (c) or (d) above if the holders of our Debentures are allowed to participate as though they had converted their Debentures prior to the applicable record date or effective date.

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We are not required to make adjustments in the conversion price unless the cumulative effect of such adjustments would change the conversion price by at least 1%.

The term “current market price” is defined in the Debenture Indenture to mean the weighted average trading price of our Trust Units on the Toronto Stock Exchange for the 20 consecutive trading days ending on the fifth trading day preceding the date of the applicable event.

In the case of any reclassification or capital reorganization (other than a change resulting from consolidation or subdivision) of our Trust Units or in the case of any consolidation, amalgamation or merger of the Trust with or into any other entity, or in the case of any sale or conveyance of the properties and assets of the Trust as, or substantially as, an entirety to any other entity, or a liquidation, dissolution or winding-up of the Trust, the terms of the conversion privilege shall be adjusted so that each holder of a Debenture shall, after such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding-up, be entitled to receive the number of Trust Units such holder would be entitled to receive if on the effective date thereof, it had been the holder of the number of Trust Units into which the Debenture was convertible prior to the effective date of such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding-up.

No fractional Trust Units will be issued on any conversion but in lieu thereof we shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

Redemption and Purchase

Our Debentures are not redeemable on or before December 31, 2009 and June 30, 2010 respectively. On or after January 1, 2010 and July 1, 2010 respectively and prior to maturity, our Debentures may be redeemed in whole or in part from time to time at our option on not more than 60 days and not less than 30 days notice, at a Redemption Price of $1,050 per debenture after December 31, 2009 and June 30, 2010 respectively, on or before December 31, 2010 and June 30, 2011 respectively, at a Redemption Price of $1,050 per debenture and on or after January 1, 2011 and July 1, 2011 respectively and prior to maturity at a Redemption Price of $1,025 per debenture, in each case, plus accrued and unpaid interest thereon, if any.

In the case of redemption of less than all of our Debentures, the Debentures to be redeemed will be selected by the Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee deems equitable.

We have the right to purchase our Debentures in the market, by tender or by private contract.

Payment upon Redemption or Maturity

On redemption or at maturity, we will, subject to our option to make such repayment in Trust Units as described below, repay the indebtedness represented by our Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, together with accrued and unpaid interest thereon. We may, at our option, on not more than 60 and not less than 40 days prior notice and subject to applicable regulatory approval, elect to satisfy our obligation to pay the applicable Redemption Price of the Debentures which are to be redeemed or the principal amount of the Debentures which have matured, as the case may be, by issuing freely tradeable Trust Units to the holders of the Debentures. Any accrued and unpaid interest thereon will be paid in cash. T he number of Trust Units to be issued will be determined by dividing the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, by 95% of the weighted average trading price of our Trust Units for the 20 consecutive trading days ending on the fifth trading day preceding the date fixed for redemption or the maturity date, as the case may be. No fractional Trust Units will be issued on redemption or maturity but in lieu thereof we shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest.

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Subordination

The payment of the principal and premium, if any, of, and interest on, our Debentures is subordinated in right of payment, as set forth in the Debenture Indenture, to the prior payment in full of all of our Senior Indebtedness and indebtedness to our trade creditors. “Senior Indebtedness” is defined in the Debenture Indenture as the principal of and premium, if any, and interest on and other amounts in respect of all of our indebtedness (whether outstanding as at the date of the Debenture Indenture or thereafter incurred), other than indebtedness evidenced by our Debentures and all other existing and future debentures or other instruments of the Trust which, by the terms of the instrument creating or evidencing the indebtedness, is expressed to be pari passu with, or subordinate in right of payment to, our Debentures.  Subject to statutory or preferred exceptions or as may be specified by t he terms of any particular securities, each Debenture issued under the Debenture Indenture ranks pari passu with each other Debenture, and with all of our other present and future subordinated and unsecured indebtedness except for sinking provisions (if any) applicable to different series of Debentures or similar types of obligations.

The Debenture Indenture provides that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings relative to us, or to our property or assets, or in the event of any proceedings for our voluntary liquidation, dissolution or other winding-up, whether or not involving insolvency or bankruptcy, or any marshalling of our assets and liabilities, then those holders of Senior Indebtedness, including to our trade creditors, will receive payment in full before the holders of our Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of our Debentures or any unpaid interest accrued thereon. The Debenture Indenture also provides that we cannot make any payment, and the holders of our Debentures are not entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including without any limitation by set-off, combination of accounts or realization of security or otherwise in any manner whatsoever) on account of indebtedness represented by our Debentures (a) in a manner inconsistent with the terms (as they exist on the date of issue) of our Debentures or (b) at any time when an event of default has occurred under the Senior Indebtedness and is continuing and the notice of such event of default has been given by or on behalf of the holders of Senior Indebtedness to us, unless the Senior Indebtedness has been repaid in full.

Our Debentures are also effectively subordinate to claims of creditors of the Trust Subsidiaries except to the extent we are a creditor of such subsidiaries ranking at least pari passu with such other creditors. Specifically, our Debentures will be effectively subordinated in right of payment to the prior payment in full of all indebtedness under our Revolving and Operating Credit Facilities.

Priority over Trust Distributions

Our Trust Indenture provides that certain expenses of the Trust must be deducted in calculating the amount to be distributed to our Unitholders. Accordingly, the funds required to satisfy the interest payable on our Debentures, as well as the amount payable upon redemption or maturity of our Debentures or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to our Unitholders.

Change of Control of the Trust

Within 30 days following the occurrence of a change of control of the Trust involving the acquisition of voting control or direction over 66 2/3% or more of our Trust Units (a “Change of Control”), we are required to make an offer in writing to purchase all of our Debentures then outstanding (the “Offer”), at a price equal to 101% of the principal amount thereof plus accrued and unpaid interest (the “Offer Price”).

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The Debenture Indenture contains notification and repurchase provisions requiring us to give written notice to the Debenture Trustee of the occurrence of a Change of Control within 30 days of such event together with the Offer. The Debenture Trustee will thereafter promptly mail to each holder of Debentures a notice of the Change of Control together with a copy of the Offer to repurchase all the outstanding Debentures.

If 90% or more in aggregate principal amount of our Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to us pursuant to the Offer, we will have the right and obligation to redeem all the remaining Debentures at the Offer Price. Notice of such redemption must be given by us to the Debenture Trustee within 10 days following the expiry of the Offer, and as soon as possible thereafter, by the Debenture Trustee to the holders of our Debentures not tendered pursuant to the Offer.

Interest Payment Option

We may elect, from time to time, to satisfy our obligation to pay interest on our Debentures (the “Interest Obligation”), on the date it is payable under the Debenture Indenture (an “Interest Payment Date”), by delivering sufficient Trust Units to the Debenture Trustee to satisfy all or any part of the Interest Obligation in accordance with the Debenture Indenture (the “Unit Interest Payment Election”).  The Indenture provides that, upon such election, the Debenture Trustee shall (a) accept delivery from us of our Trust Units, (b) accept bids with respect to, and consummate sales of, such Trust Units, each as we shall direct in our absolute discretion, (c) invest the proceeds of such sales in short-term permitted government securities (as will be defined in the Debenture Indenture) which mature prior to the applicable Interest Payment Date, and use t he proceeds received from such permitted government securities, together with any proceeds from the sale of Trust Units not invested as aforesaid, to satisfy the Interest Obligation, and (d) perform any other action necessarily incidental thereto.

The Debenture Indenture sets forth the procedures to be followed by us and the Debenture Trustee in order to effect the Unit Interest Payment Election. If a Unit Interest Payment Election is made, the sole right of a holder of our Debentures in respect of interest is to receive cash from the Debenture Trustee out of the proceeds of the sale of Trust Units (plus any amount received by the Debenture Trustee from us attributable to any fractional Trust Units) in full satisfaction of the Interest Obligation, and the holder of such Debentures has no further recourse to us in respect of the Interest Obligation.

Neither our making of the Unit Interest Payment Election nor the consummation of sales of Trust Units will (a) result in the holders of our Debentures not being entitled to receive on the applicable Interest Payment Date cash in an aggregate amount equal to the interest payable on such Interest Payment Date, or (b) entitle such holders to receive any of our Trust Units in satisfaction of the Interest Obligation.

Events of Default

The Debenture Indenture provides that an event of default (“Event of Default”) in respect of our Debentures will occur if any one or more of the following described events has occurred and is continuing with respect to our Debentures: (a) failure for 10 days to pay interest on our Debentures when due; (b) failure to pay principal or premium, if any, when due on our Debentures, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of our bankruptcy, insolvency or reorganization under bankruptcy or insolvency laws; or (d) default in the observance or performance of any material covenant or condition of the Debenture Indenture and continuance of such default for a period of 30 days after notice in writing has been given by the Debenture Trustee to us specifying such default and requiring us to rectify the same. If an Event of Default has occurred and is continuing, t he Debenture Trustee may, in its discretion, and shall upon request of holders of not less than 25% in principal amount of the outstanding Debentures, declare the principal of and interest on all outstanding Debentures to be immediately due and payable. In certain cases, the holders of a majority of the principal amount of the Debentures then outstanding may, on behalf of the holders of all Debentures, waive any Event of Default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe.

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Offers for Debentures

The Debenture Indenture contains provisions to the effect that if an offer is made for our Debentures which is a take-over bid for our Debentures within the meaning of the Securities Act (Alberta) and not less than 90% of our Debentures (other than Debentures held at the date of the take-over 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 our Debentures held by the holders of Debentures who did not accept the offer on the terms offered by the offeror.

Modification

The rights of the holders of our Debentures as well as any other series of Debentures that may be issued under the Debenture Indenture may be modified in accordance with the terms of the Debenture Indenture. For that purpose, among others, the Debenture Indenture contains certain provisions which make binding on all Debenture holders resolutions passed at meetings of the holders of Debentures by votes cast thereat by holders of not less than 66 2/3% of the principal amount of the outstanding Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66 2/3% of the principal amount of the outstanding Debentures.  In certain cases, the modification will, instead or in addition, require assent by the holders of the required percentage of Debentures of each particularly affected series.

Limitation on Issuance of Additional Debentures

The Debenture Indenture provides that we shall not issue additional convertible Debentures of equal ranking if the principal amount of all of our issued and outstanding convertible Debentures exceeds 25% of the Total Market Capitalization of the Trust immediately after the issuance of such additional convertible Debentures. “Total Market Capitalization” is defined in the Debenture Indenture as the total principal amount of all of our issued and outstanding Debentures which are convertible at the option of the holder into our Trust Units plus the amount obtained by multiplying the number of issued and outstanding Trust Units by the current market price of our Trust Units on the relevant date.

Book-Entry System for Debentures

Our Debentures have been issued in “book-entry only” form and must be purchased or transferred through a participant (a “Participant”) in the depository service of The Canadian Depository of Securities Limited (“CDS”).  The Debentures are evidenced by a single book-entry only certificate. Registration of interests in and transfers of our Debentures are made only through the depository service of CDS.

Except as described below, a purchaser acquiring a beneficial interest in our Debentures (a “Beneficial Owner”) will not be entitled to a certificate or other instrument from the Debenture Trustee or CDS evidencing that purchaser’s interest therein, and such purchaser will not be shown on the records maintained by CDS, except through a Participant.  

We assume no liability for: (a) any aspect of the records relating to the beneficial ownership of our Debentures held by CDS or the payments relating thereto; (b) maintaining, supervising or reviewing any records relating to our Debentures; or (c) any advice or representation made by or with respect to CDS and relating to the rules governing CDS or any action to be taken by CDS or at the direction of its Participants. The rules governing CDS provide that it acts as the agent and depositary for the Participants. As a result, Participants must look solely to CDS and Beneficial Owners must look solely to Participants for the payment of the principal and interest on our Debentures paid by us or on our behalf to CDS.

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Our Debentures are issued to Beneficial Owners in fully registered and certificate form (the “Debenture Certificates”) only if: (a) we are required to do so by applicable law; (b) the book-entry only system ceases to exist; (c) we or CDS advises the Debenture Trustee that CDS is no longer willing or able to properly discharge its responsibilities as depositary with respect to our Debentures and we are unable to locate a qualified successor; (d) we, at our option, decide to terminate the book-entry only system through CDS; or (e) after the occurrence of an Event of Default, Participants acting on behalf of Beneficial Owners representing, in the aggregate, more than 25% of the aggregate principal amount of the Debentures then outstanding advise CDS in writing that the continuation of a book-entry only system through CDS is no longer in their best interest provided the Debenture Trustee has not wai ved the Event of Default in accordance with the terms of the Debenture Indenture.

Upon the occurrence of any of the events described in the immediately preceding paragraph, the Debenture Trustee will be required to notify CDS, for and on behalf of Participants and Beneficial Owners, of the availability through CDS of Debenture Certificates. Upon surrender by CDS of the single certificate representing our Debentures and receipt of instructions from CDS for the new registrations, the Debenture Trustee will deliver our Debentures in the form of Debenture Certificates and thereafter we will recognize the holders of such Debenture Certificates as Debenture holders under the Debenture Indenture.

Interest on our Debentures will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, interest will be paid by cheque drawn on the Trust and sent by prepaid mail to the registered holder or by such other means as may become customary for the payment of interest. Payment of principal, including payment in the form of our Trust Units if applicable, and the interest due, at maturity or on a redemption date, will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, payment of principal, including payment in the form of our Trust Units if applicable, and interest due, at maturity or on a redemption date, will be paid upon surrender thereof at any office of the Debenture Trustee or as otherwise specified in the Debenture Indenture.

Exchangeable Shares

EEC Exchangeable Shares

As of December 31, 2006, there were 16,337 EEC Exchangeable Shares outstanding.  On January 31, 2007, all EEC Exchangeable Shares then outstanding were automatically redeemed.  On and after January 31, 2007, the rights of former holders of EEC Exchangeable Shares are limited to receiving those Trust Units to which they are entitled as a result of the redemption.

RMAC Exchangeable Shares

As of December 31, 2006, there were 66,720 RMAC Exchangeable Shares outstanding.  On January 19, 2007, all RMAC Exchangeable Shares then outstanding were automatically redeemed. On and after January 19, 2007, the rights of former holders of RMAC Exchangeable Shares are limited to receiving those Trust Units to which they are entitled as a result of the redemption.

RMG Exchangeable Shares

On June 1, 2006, all RMG Exchangeable Shares then outstanding were automatically redeemed. On and after June 1, 2006, the rights of former holders of RMG Exchangeable Shares are limited to receiving those Trust Units to which they are entitled as a result of the redemption. As of December 31, 2006, there were zero RMG Exchangeable Shares outstanding.

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MARKET FOR SECURITIES

Our Trust Units are listed on the Toronto Stock Exchange (ENT.UN) and the New York Stock Exchange (ENT).  The following table sets forth the price range and trading volume of our Trust Units as reported by the TSX and the NYSE for the periods indicated:

	TSX			NYSE
	High ($)	Low ($)	Volume (000’s)	High (US$)	Low (US$)	Volume
2007
January	9.68	7.82	1,861,213	8.25	6.66	12,928,200
February	8.51	7.25	1,146,700	7.23	6.22	8,910,346
March	7.44	5.76	639,783	6.34	4.88	11,247,280
April	6.40	5.69	2,406,453	5.44	4.96	7,868,700
May	6.95	5.69	2,211,064	6.41	5.16	11,463,270
June	6.73	6.00	972,578	6.34	5.67	8,132,050
July	6.50	5.71	757,295	6.18	5.43	6,428,500
August	5.85	4.57	1,148,250	5.55	4.32	9,184,000
September	4.82	1.35	3,827,054	4.60	1.33	45,240,425
October	2.96	2.22	784,404	2.99	2.30	16,322,936
November	2.49	1.10	1,379,011	2.58	1.09	14,318,863
December	1.45	1.00	1,948,918	1.38	1.10	13,537,995
2008
January	1.74	1.14	980,534	1.77	1.16	8,244,009
February	2.62	1.33	902,381	2.66	1.34	8,923,000
March(1)	2.25	1.76	223,081	2.28	1.78	3,598,874

(1)

Information to March 19, 2008.

Our Debentures are listed on the Toronto Stock Exchange (ENT.DB, ENT.DB.A).  The following table sets forth the price range and trading volume of our Debentures as reported by the TSX for the periods indicated:

	TSX (ENT.DB)			TSX (ENT.DB.A)
	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
2007
January	104.25	98.00	59,790
February	101.00	93.00	78,890
March	99.00	94.50	61,260
April(1)	98.50	94.67	52,570	101.01	99.75	37,700
May	100.00	97.00	29,250	104.50	100.00	32,150
June	100.00	97.01	7,958	103.00	100.00	10,670
July	100.00	97.50	11,480	102.00	100.01	20,910
August	99.30	94.00	30,350	101.99	96.51	5,460
September	97.00	75.00	75,430	100.00	77.00	51,120
October	97.00	88.00	10,670	93.00	91.00	88,340
November	92.05	75.00	12,573	91.00	75.00	7,240
December	87.50	60.00	35,600	80.00	60.00	19,280
2008
January	94.70	68.01	6,000	90.00	78.00	11,250
February	88.00	78.01	9,240	85.00	75.05	31,750
March(2)	87.05	85.00	1,530	87.50	85.25	1,160

(1)

ENT.DB.A information from April 26, 2007.

(2)

Information to March 19, 2008.

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DISTRIBUTIONS

Cash distributions are made on the 15th day of each month or the first business day thereafter to Unitholders of record on the immediately preceding distribution record date (or such other payment and/or record date as may be determined by the Trustee on the recommendation of the board of EEC).  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

The following table sets forth the amount of monthly cash distributions per Trust Unit that we have paid since our inception.

Month of record (US$)	2007		2006		2005		2004		2003
January	$	0.12	$	0.18	$	0.14	$	0.10
February	$	0.06	$	0.18	$	0.14	$	0.10
March	$	0.06	$	0.18	$	0.15	$	0.11
April	$	0.06	$	0.18	$	0.15	$	0.11
May	$	0.06	$	0.18	$	0.15	$	0.11
June	$	0.06	$	0.18	$	0.16	$	0.12
July	$	0.06	$	0.18	$	0.16	$	0.12
August	$	0.06	$	0.12	$	0.16	$	0.12
September	$	0.06	$	0.12	$	0.17	$	0.13
October		-	$	0.12	$	0.17	$	0.13
November		-	$	0.12	$	0.17	$	0.13
December		-	$	0.12	$	0.18	$	0.14	$	0.10(1)

Note:

(1)

This distribution was the first cash distribution of the Trust following its creation.

The distributions were denominated in U.S. dollars.    

CORPORATE GOVERNANCE

Delegation of Authority, Administration and Trust Governance

The board of EEC has generally been delegated our significant management decisions. In particular, pursuant to our Trust Indenture, our Trustee has delegated to EEC responsibility for any and all matters relating to the following: (i) offering of our securities; (ii) ensuring compliance with all applicable laws, including in relation to an offering of our securities; (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 our material contracts; (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 investments held by us, other than the units of EECT.

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

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Directors and Officers

The board of directors of EEC currently consists of four individuals.  The directors are elected by EEC at the direction of Unitholders by ordinary resolution, and hold office until the next annual meeting of Unitholders, which is currently scheduled for June 10, 2008.

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

Name and Municipality of Residence	Position with Enterra	Principal Occupation	Trust Units Controlled or Beneficially Owned (6)
Peter Carpenter (3) (5) Toronto, Ontario	Director (since 2006) and Chairman	Senior Partner & Director Claridge House Partners, Inc.	1,041
Roger Giovanetto (1) (2) (3) (4) Calgary, Alberta	Director (since 2006)	Business Consultant	24,041
Michael Doyle (1) (2) (4) (5) Calgary, Alberta	Director (since 2007)	Principal CanPetro International Ltd.	0
Vick Dusik (1) (2) (3) (4) (5) Vancouver, British Columbia	Director (since 2008)	Chief Financial Officer Run of River Power Inc.	0
Blaine Boerchers Calgary, Alberta	Chief Financial Officer (since 2007)	Chief Financial Officer Enterra Energy Corp.	4,372
James (Jim) Tyndall Calgary, Alberta	Senior Vice President and Chief Operating Officer (since 2006)	Sr. VP and COO Enterra Energy Corp.	35,479
John F. Reader Calgary, Alberta	Senior Vice President Corporate Development (since 2005)	Sr. VP Corporate Development Enterra Energy Corp.	22,104

Notes:

(1)

Member of Audit Committee

(2)

Member of Compensation Committee

(3)

Member of Reserves Committee

(4)

Member of Corporate Governance Committee

(5)

Member of Special Committee

(6)

As at March 19, 2008 and excluding Trust Units issuable upon the exercise of outstanding options, rights or deferred entitlement units

The directors and officers of EEC, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 87,037 of our Trust Units, representing approximately 0.14% of our issued and outstanding Trust Units (as of March 19, 2008).  Profiles of EEC’s directors and officers and the particulars of their respective principal occupations during the last five years are set forth below.

Peter Carpenter, Director and Chairman

Peter Carpenter has been a Senior Partner (Oil and Gas) and Director of financial advisory firm Claridge House Partners, Inc. since 1996.  His duties include sourcing equity financing and providing advisory services for the energy clients of the firm, including American Electric Power, the Hunt family, the Lundin Group and numerous junior oil companies.  Mr. Carpenter is a Professional Engineer (Alberta) with a CFA designation and holds a B.Sc. in Chemical Engineering from the University of Alberta and an MBA from The University of Western Ontario. Mr. Carpenter joined EEC’s Board of Directors in May 2006.

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Roger Giovanetto, Director

Roger Giovanetto has been President of R&H Engineering, Ltd., a metallurgical, materials and corrosion engineering services company for more than five years. During his career, he has developed and managed oilfield chemical operations, corrosion consulting companies and started a publicly traded junior oil and gas company in Alberta.  Mr. Giovanetto has also been instrumental in developing business operations in Siberia, where he specialized in renovating existing oilfields, and has established several chemical manufacturing facilities in Siberia and Iran.  Mr. Giovanetto holds a B.Sc. in Metallurgical Engineering from the University of Alberta and is a member of APEGGA and other professional oil and gas organizations. Mr. Giovanetto joined EEC’s Board of Directors in May 2006.

Michael Doyle, Director

Michael Doyle is a Professional Geophysicist with more than 35 years of wide–ranging experience in finding, developing and producing hydrocarbons.  Mr. Doyle is a principal of privately held CanPetro International Ltd., and the Chairman of Madison Petrogas Ltd.  He was previously a principal and President of Petrel Robertson Ltd. where he was responsible for providing advice and project management to clients in Canada and numerous other parts of the world.  Prior to that, he held a variety of exploration positions at Dome Petroleum and Amoco Canada.  He has served as a director of a number of companies principally in the petroleum sector, and has served on professional and technical committees, including an Alberta Hazardous Waste Committee.  He also served as President of the Longview Rural Electrification Association through a period of growth that concluded with a sale to TransAl ta Utilities.  Mr. Doyle holds a Bachelor of Science (Math and Physics) from the University of Victoria where he has also served as a member of the Cooperative Education Advisory Council.  Mr. Doyle joined EEC’s Board of Directors in December 2007.

Vick Dusik, Director

Vick Dusik is a Chartered Accountant and Chartered Business Valuator with extensive experience including the areas of corporate finance, acquisitions and divestitures, risk management and public reporting and compliance.  He is Chief Financial Officer of Run of River Power Inc., a publicly traded developer of environmentally friendly energy based in Vancouver, British Columbia.  Previously, Mr. Dusik held the positions of Vice President Finance and Chief Financial Officer with Maxim Power Corp., and Chief Executive Officer of Monarch Capital Limited.  He spent more than 30 years in various progressive positions with Ernst & Young LLP providing public accounting and consulting services to a wide variety of companies and industry sectors.  He served as a director of Taylor NGL Limited Partnership as well as numerous other public companies.  Mr. Dusik holds a Master of Busi ness Administration from the Richard Ivey School of Business, the University of Western Ontario.  Mr. Dusik joined EEC's Board of Directors in February 2008.

James H. (Jim) Tyndall, Senior VP Operations & COO

Jim Tyndall is a Professional Engineer with more than 26 years of diverse technical and managerial experience in the oil and gas industry, both domestically and internationally.  Since 2002, Mr. Tyndall has held senior positions with three successful junior exploration companies involved in finding and developing properties in Western Canada.  Earlier, he was with EnCana Corporation and its predecessor, PanCanadian Petroleum Ltd. for a total of 11 years, working in technical and management positions, including a four-year stint in Siberia.  He was also with Hurricane Hydrocarbons in the Republic of Kazakhstan.  Mr. Tyndall holds a Bachelor of Science degree in Engineering from the University of Saskatchewan.  Mr. Tyndall joined EEC in June 2006.

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John F. Reader, Senior VP Corporate Development

John Reader is a Professional Geological Engineer with over 25 years of resource industry experience.  Recently he culminated an 18-year career with ChevronTexaco Corporation as Canadian Business Development Manager, with prior experience as Mergers and Acquisitions Manager, and various other supervisory roles.  Mr. Reader was appointed Vice President, Operations and Engineering of EEC in October 2005 and was promoted to Senior Vice President Corporate Development in June 2006.  Mr. Reader holds a Bachelor of Applied Science degree from the University of British Columbia and a Master of Business Administration from the University of Calgary.

Blaine Boerchers, Chief Financial Officer

Blaine Boerchers is a Chartered Accountant and a Certified Public Accountant (Texas) with over 20 years of experience in the energy industry, most recently as Vice President of Finance and Chief Financial Officer of Nabors Blue Sky Ltd.  Mr. Boerchers has previously been Vice President of Finance and Chief Financial Officer of Airborne Energy Solutions Ltd. and has held various senior finance positions with Halliburton.  During his 12 years of service with Halliburton, he also spent 4 years at Halliburton’s corporate offices in Dallas, Texas with Halliburton’s International Tax department in various roles.  He spent 7 years in public practice in various roles, providing public accounting and consulting services to a variety of companies in various industries, primarily with Ernst & Young LLP.  Mr. Boerchers holds a Bachelor of Commerce degree from the University of Calgary. &nbs p;He joined EEC in October 2007.

Committees

The board of EEC has constituted four committees for the purpose of discharging specific mandates in relation to the stewardship of EEC, including the administration and management of the Trust, being the Corporate Governance and Nominating Committee, the Audit Committee, the Compensation Committee and the Reserves Committee.  In addition, an independent committee (the “Special Committee”) has been constituted for the purpose of addressing issues related to Macon Resources Ltd. and Petroflow as detailed under “Special Committee” below.

Corporate Governance and Nominating Committee

EEC has established a Corporate Governance and Nominating Committee comprised of 3 non-management members of the board of EEC.  The mandate of the Corporate Governance and Nominating Committee is to recommend to the full board of EEC policies and specific matters respecting (i) policies and procedures of corporate governance; (ii) identifying nominees for the board of EEC, and (iii) conducting an annual performance review of the directors.

Audit

EEC has established an Audit Committee comprised of three non-management members. See “Audit Committee”.

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Compensation

EEC has established a Compensation Committee comprised of 3 non-management members of the board of ECC.  The mandate of the Compensation Committee is to review and recommend to the board of directors of EEC:

executive compensation policies, practices and overall compensation philosophy;

•

total compensation packages for all employees who receive aggregate annual compensation in excess of $100,000;

•

bonus and trust unit options;

•

major changes in benefit plans; and

•

the adequacy and form of directors’ compensation to ensure it realistically reflects the responsibilities and risks of membership on the board of EEC.

Reserves

EEC has established a Reserves Committee comprised of 3 non-management members of the board.  The mandate of the Reserves Committee is to:

•

review the selection of an independent engineer for undertaking each reserves evaluation as the same may be required from time to time;

•

consider and review the impact of changing independent engineering firms;

•

receive the engineering report and consider the principal assumptions upon which it is based; and

•

consider and review management’s input into independent engineering reports and the key assumptions used.

Special Committee

EEC has established an Independent Committee comprised of 3 non-management members of the board of directors.  The mandate of the Special Committee is to:

•

The Chairman of the Special Committee, acting as the Chief Executive Officer

•

Search for and negotiate terms of employment for a President and CEO candidate;

•

Formulate a CEO succession plan;

•

Review alternatives to strengthen the Balance Sheet;

•

Formulate a go forward strategy with the assistance of our financial advisors;

•

Review and resolve any conflicts of interest that exist; and

•

report its findings to the board of directors of EEC and make such recommendations as the Special Committee considers appropriate.

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Cease Trade Orders, Bankruptcies, Penalties or Sanctions

With the exception of the items listed in Appendix “D”, no director or executive officer of EEC 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 EEC 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.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

There are no outstanding legal proceedings material to us to which we are is a party or in respect of which any of our properties are subject, nor are there any such proceedings known to us to be contemplated other than a claim in the amount of approximately US$3.9 million has been filed against Enterra related to its U.S. operations.  The outcome of the claim is not determinable.  Enterra has also filed claims against the claimant.

Regulatory Actions

There are no outstanding regulatory actions material to us to which we are is a party nor are there any such proceedings known to us to be contemplated.  

CONFLICTS OF INTEREST AND
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

In accordance with Business Corporations Act (Alberta), a director or officer who is a party to a material contract or proposed material contract with the Trust or the Trust Subsidiaries 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 the Trust or the Trust Subsidiaries shall disclose to EEC 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.

Circumstances may arise where members of the board of directors or officers of EEC are directors or officers of corporations, which are in competition to the interests of the Trust or the Trust Subsidiaries.  No assurances can be given that opportunities identified by such board members or officers will be provided to the Trust or the Trust Subsidiaries.

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Relationship with JED Oil Inc. and JMG Exploration, Inc.

Under an Agreement of Business Principles first dated September 1, 2003, and amendments thereto, properties acquired by the Trust were contract operated and drilled by JMG, a publicly traded oil and gas

exploration company, if they were exploration properties, and contracted, operated and drilled by JED, a publicly traded oil and gas development company, if they were development projects.  Exploration of the properties was done by JMG, which paid 100% of the exploration costs to earn a 70% working interest in the properties. If JMG discovered commercially viable reserves on the exploration properties, the Trust had the right to purchase 80% of JMG’s working interest in the properties at a fair value as determined by independent engineers.  Had the Trust elected to develop the properties, development would have been done by JED, which would pay 100% of the development costs to earn 70% of the interests of both JMG and the Trust.  The Trust had a first right to purchase any assets developed by JED.  The Trust does not own any shares in either JMG or JED.  On September 28, 2006, the T rust terminated the Agreement of Business Principles and amendments thereto, and other related agreements with JED.  Concurrent with the termination of the agreements, the Trust settled all amounts owing to JED.

Effective January 1, 2004, the Trust and JED entered into the Technical Services Agreement, which provided for services required to manage the Trust’s field operations and governed the allocation of general and administrative expenses between the two entities. Under the Technical Services Agreement, the Trust and JED allocated costs of management, development, exploitation, operations and general and administrative activities on the basis of production and capital expenditures, or as otherwise agreed to between the Trust and JED.  On January 1, 2006, the Trust terminated the Technical Services Agreement with JED.  The Trust now manages its own management, development, exploitation, operations and general and administrative activities.

During the term of the Trust’s agreements with JED and JMG, the Chairman of the Trust until March 31, 2006, Reginald (Reg) J. Greenslade, was also the Chairman and Chief Executive Officer of JED and the Chairman of JMG, as well as an owner of securities in all three entities.  Mr. Greenslade also served as President and CEO of the Trust from January 15, 2005 to June 1, 2005.  In addition, H.S. (Scobey) Hartley, a director of Enterra until May 18, 2006, was the President and CEO and a director of JMG and an owner of securities in both entities.

Relationship with Petroflow Energy Ltd.

Petroflow is one of the Trust’s strategic partners and has farmed into the Trust’s properties in Oklahoma.  Mr. Conrad, the former President and Chief Executive Officer of EEC, as a founder of Petroflow, through his wholly-owned oil and gas company, Macon Resources Ltd., is considered a promoter of Petroflow.  During October 2005 the President of Petroflow contacted Mr. Conrad, who at the time was also the Chairman of Petroflow, concerning a possible acquisition of Oklahoma properties.  Mr. Conrad reviewed the acquisition in his capacities as Chairman of Petroflow and the President and Chief Executive Officer of EEC and determined that the acquisition had merit and that a partnership between the Trust and Petroflow would be advantageous for both parties.  On November 9, 2005, the acquisition and the farmout to Petroflow were brought to the board of EEC for consideration an d again on December 6, 2005 for approval.  On each occasion, Mr. Conrad abstained from voting on the matter.  On March 20, 2006, Mr. Conrad resigned as Chairman and as a director of Petroflow.  Mr. Conrad, through Macon Resources Ltd., remains a significant shareholder of Petroflow owning directly or indirectly 16% of the outstanding common shares.  The board of directors of EEC believes that any of the activities undertaken by Mr. Conrad did not interfere, in any material way, with his ability to act with a view to the best interest of either EEC or the Trust.  Mr. Conrad resigned as Chief Executive Officer and director of EEC on November 27, 2007 and February 20, 2008 respectively.

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A current director, Mr. Roger Giovanetto, on EEC’s board has reported that he owns directly or indirectly approximately 2% of the outstanding common shares of Petroflow.

However, the board of EEC is aware of the conflict of interest and has established a committee of directors independent of the Trust’s management and excluding Mr. Conrad, to review all material matters related to its business dealings with Petroflow and to approve any material decisions relating thereto.  In addition, at each meeting of the board of EEC, management is required to report on all material matters relating to the business relationship with Petroflow.  Day-to-day oversight of the Petroflow farm-in, including decisions related to the specific location and timing of wells, has been delegated to a five person committee consisting of two representatives of Petroflow and three senior managers of the Trust.

Relationship with Macon Resources Ltd.

Mr. Conrad was not an employee of Enterra.  He provided his services as President and Chief Executive Officer of EEC pursuant to a management agreement that we entered into with Macon Resources Ltd. which was terminated November 2007.  Pursuant to the management agreement, we paid fees to Macon Resources Ltd. in the amount of $33,000 per month and provided office space for approximately 12 employees of Macon Resources Ltd. during the term of that agreement.  Of the $0.7 million paid to Macon during 2007, an agreed amount of $0.3 million related to the termination of the contract that otherwise would have run to June 1, 2008.   

Macon Resources Ltd. also provided the services of the Vice President and Chief Financial Officer of the Trust from June 1, 2005 until June 15, 2006 in exchange for a fee of $17,000 per month.

Relationship with Trigger Projects Ltd.

On November 23, 2007, the Trust entered into a consulting agreement with Trigger Projects Ltd. for management services that would effectively be expected of the most senior manager of the Trust.  These services are performed by Don Klapko.  This contract has terms that require payment for services of $40,000 per month and a bonus of up to $0.5 million on termination.  The contract expires on May 31, 2008.  Payments of $50,000 were made to Trigger Projects Ltd. under this contract during 2007.

Other Management and Director Interests

Ms. Kim Booth, former Vice President and Chief Operating Officer, U.S. Operations, owns working interests ranging from 0.5% to 2.0% in approximately 45 wells on our Oklahoma properties.  Ms. Booth owned those interests prior to our acquisition of crude oil and natural gas properties located in Oklahoma.  Ms. Booth is not entitled to additional interests or new interests in any wells drilled on our Oklahoma properties.

Mr. W. Cobb (Chip) Hazelrig, a former director of EEC, has entered into a participation agreement dated March 1, 2006 (the “Participation Agreement”) with Enterra US Acqco whereby Mr. Hazelrig may, subsequent to March 1, 2006, elect to participate with Enterra US Acqco in the drilling of oil and gas wells on lands situated in Alfalfa, Garfield, Grant, Lincoln, Logan, Noble and Payne Counties, Oklahoma.  Upon the drilling of wells that Mr. Hazelrig has elected to participate in, assuming fulfillment by Mr. Hazelrig of his obligations pursuant to the Participation Agreement, including paying his proportionate share of all costs, expenses, responsibilities and liabilities in respect of the acquiring, maintaining and drilling such wells, Mr. Hazelrig will be entitled to an undivided 2.0% of the working interest owned by Enterra US Acqco in and to each of the oil, gas and mineral leases affected by or attributable to such wells.

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TRANSFER AGENT AND REGISTRAR

Olympia Trust Company, at its principal offices in Calgary, Alberta and at the principal offices of BNY Trust Company of Canada in Toronto, Ontario, is the transfer agent and registrar for the Trust Units.

MATERIAL CONTRACTS

Agreements that may be considered material are set out below:

•

Trust Indenture.  See “Capital Structure – The Trust Indenture”.

•

Note Indenture.  See “Capital Structure – Trust Units and Other Securities”.

•

Administration Agreement between the Trust and EEC.  See “Corporate Governance - Delegation of Authority, Administration and Trust Governance”.

•

Trust Indenture among EET and EAC and Olympia Trust Company providing for the issue of debentures dated November 9, 2006.  See “Trust Units and Other Securities – Debentures”.

•

Farmout Agreement between EAC and North American Petroleum Corporation USA dated January 13, 2006.  See “Oil and Gas Properties – Oklahoma”.

•

Amended and Restated Syndicated Credit Agreement dated February 1, 2007 among Enterra Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

•

Amendment to Amended and Restated Syndicated Credit Agreement dated March 15, 2007 among Enterra Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

•

Second Amendment to Amended and Restated Syndicated Credit Agreement dated May 11, 2007 among Enterra Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

•

Third Amendment to Amended and Restated Syndicated Credit Agreement dated July 17, 2007 among Enterra Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

•

Fourth Amendment to Amended and Restated Syndicated Credit Agreement dated November 20, 2007 among Enterra Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

•

Fifth Amendment to Amended and Restated Syndicated Credit Agreement dated December 11, 2007 among Enterra Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

•

Sixth Amendment to Amended and Restated Syndicated Credit Agreement dated December 18, 2007 among Enterra Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

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INTERESTS OF EXPERTS

Reserve estimates contained herein are derived from reserve reports prepared by McDaniel, Haas and MHA.  As of the date hereof, none of McDaniel, Haas or MHA or any of their designated professionals owns directly or indirectly, any Trust Units.  Our auditors, KPMG LLP, have confirmed that they are independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

AUDIT COMMITTEE

General

EEC has established an Audit Committee (the “Audit Committee”) comprised of three members:  Vick Dusik, Roger Giovanetto and Michael Doyle, 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 board of EEC in its oversight of the integrity of our financial and related information, 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.

The Audit Committee’s function is oversight.  Management of EEC is responsible for the preparation, presentation and integrity of the financial statements of the Trust.  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 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 in good faith.

The mandate of the Audit Committee is attached hereto as Appendix “A”.

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.

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Name of Audit Committee Member	Relevant Education and Experience
Vick Dusik	Mr. Dusik is a Chartered Accountant and Chartered Business Valuator with extensive experience including the areas of corporate finance, acquisitions and divestitures, public reporting and compliance. He spent more than 30 years in various progressive positions with Ernst & Young LLP providing public accounting and consulting services to a wide variety of companies and industry sectors.
Michael Doyle	Mr. Doyle is a Professional Geophysicist with more than 35 years of experience.  He has served as a director of a number of companies principally in the petroleum sector, and has served on professional and technical committees, including Audit Committees.  Mr. Doyle holds a Bachelor of Science (Math and Physics) from the University of Victoria.

Roger Giovanetto Mr. Giovanetto holds a B.Sc. in Metallurgical Engineering from the University of Alberta and is a member of APEGGA and other professional oil and gas organizations.  He has many years of business experience and has most recently been President of R&H Engineering Ltd. and has previously served on audit committees.

External Auditor Service Fees

KPMG LLP audited our annual financial statements for the 2007 and 2006 fiscal year.

(in $ thousands)	2007	2006
Audit fees (1)	701.0	884.6
Audit-related fees (2)	82.0	97.0
Tax fees (3)	-	-
All other fees (4)	84.0	10.0
Total	867.0	991.6

Notes:

(1)

Audit fees include professional services rendered by KPMG LLP for the audit of the annual consolidated financial statements as well as services provided in connection with statutory and regulatory filings and engagements.

(2)

Audit-related fees are fees charged by KPMG LLP for reviews of the Trust’s interim financial statements.

(3)

Tax fees include fee for tax compliance, tax advice and tax planning.  

(4)

All other fees related to advisory for SOX-404 compliance, document translation and other consulting services.  

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Audit Committee Oversight

Since the commencement of our most recently completed financial year, all recommendations of the Audit Committee to nominate or compensate an external auditor have been adopted by the board of directors of EEC.

ADDITIONAL INFORMATION

Additional information relating to the Trust may be found on SEDAR at www.sedar.com.  Additional information related to the remuneration and indebtedness of the directors and officers of EEC, the principal holders of Trust Units, the Trust Units authorized for issuance equity compensation plans and corporate governance disclosure, 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 management’s discussion and analysis of the Trust for the year ended December 31, 2007.

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APPENDIX “A”

AUDIT COMMITTEE MANDATE

1.

Role and Objective

The Audit Committee (the “Committee”) is a committee of the Board of Directors (the “Board”) of Enterra Energy Corp. (the “Company”), the administrator to Enterra Energy Trust (the “Trust”), to which the Board has delegated its responsibility for oversight of the financial reporting process and recommending, for Board approval, the financial statements and other mandatory disclosure releases containing financial information.

The objectives of the Committee, with respect to the Company and the Trust (collectively referred to as “Enterra”), are as follows:

(a)

To oversee the credibility, integrity and objectivity of the financial reporting process;

(b)

To assist the Board in meeting its responsibilities in respect of the preparation and disclosure of the financial statements of Enterra and related matters;

(c)

To monitor the independence and performance of the external auditors;

(d)

To provide better communication between directors and external auditors;

(e)

To strengthen the role of non-management directors by facilitating in-depth discussions among directors on the Committee, management and the external auditors.  

2.

Mandate and Responsibilities of the Committee

Review Procedures

(a)

It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to the Company’s internal control systems:

(i)

identification, monitoring and mitigating controlling, material business risks;

(ii)

ensuring compliance with legal, ethical and regulatory requirements;

(b)

It is a primary responsibility of the Committee to review the quarterly and annual financial statements of Enterra prior to their submission to the Board for approval.  The process should include but not be limited to:

(i)

reviewing changes in accounting principles, or in their application, which may have a material impact on the current or future years’ financial statements;

(ii)

reviewing significant accruals, reserves or other estimates such as the impairment calculation;

(iii)

reviewing the accounting treatment of unusual or non-recurring transactions;

(iv)

ascertaining compliance with covenants under loan agreements and the Trust Indenture;

(v)

reviewing the adequacy of the asset retirement obligations;

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(vi)

reviewing disclosure requirements for commitments and contingencies;

(vii)

obtaining reasonable explanations of significant variances with comparable reporting periods;

(viii)

determining through inquiry if there are any related party transactions and ensure the nature and extent of such transactions are properly disclosed;

(ix)

reviewing adjustments raised by external auditors, whether or not included in the financial statements; and

(x)

reviewing unresolved differences between management and the external auditors, if any.

(c)

The Committee is to review and recommend for Board approval of financial statements and related information included in prospectuses, management discussion and analysis, information circular-proxy statements and annual information forms, prior to filing or public disclosure.

(d)

The Committee is to discuss all public disclosure containing audited or unaudited financial information such as press releases, as well as financial information and earnings guidance provided to analysts and rating agencies, before release.

(e)

The Committee is to review with the external auditors (and internal auditors, if any) their assessment of the integrity of the Company’s financial reporting process and controls, their written reports containing recommendation for improvement, and management’s response and follow-up to any identified weaknesses.  

(f)

The Committee is responsible for satisfying itself that adequate procedures are in place for the review of the public disclosure of financial information of Enterra from its financial statements and periodically assess the adequacy of those procedures.  

Internal Auditors (if any)

(g)

Review the annual audit plans of the internal auditors.

(h)

Review the significant findings prepared by the internal auditors and recommendations issued by any external party relating to internal audit issues, together with management’s response thereto.

(i)

Review the adequacy of the resources of the internal auditors to ensure the objectivity and independence of the internal audit function.

(j)

Consult with management on management’s appointment, replacement, reassignment or dismissal of the internal auditors.

(k)

Ensure that the internal auditors have access to the Chair, the Chair of the Board and the CEO.

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External Auditors

(l)

With respect to the appointment of external auditors by the Board, the Committee shall:  

(i)

review management’s recommendation for the appointment of external auditors and recommend to the Board appointment of external auditors and their fee;

(ii)

review the terms of engagement of the external auditors, including the appropriateness and reasonableness of the auditors’ fee;

(iii)

be directly responsible for overseeing the work of the external auditors engaged for the purpose of issuing an auditors’ reports or performing other audit, review or attest services for the Company including the resolution of disagreements between management and the external auditor regarding financial reporting;

(iv)

review and pre-approve any non-audit services to be provided by external auditors’ firm and consider the impact to the independence of the auditors; and

(v)

when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change.

(m)

The Committee shall also review annually with the external auditor and their plan for the audit and, upon completion of the audit, their reports upon the financial statements of Enterra.  

Other

(n)

Establish procedures independent of management for:

(i)

The receipt, retention and treatment of complaints received by the Trust regarding accounting, internal accounting controls, or auditing matters; and

(ii)

The confidential, anonymous submission by employees of the Trust of concerns regarding questionable accounting or auditing matters.

(o)

Review and approve hiring policies regarding partners, employees and former partners and employees of the present and former external auditors.

(p)

Review and discuss with the CEO, CFO, and the external auditors, the matters required to be reviewed with those persons in connection with any certificates required by applicable laws, regulations or stock exchange requirements to be provided by the CEO and CFO.  

(q)

Review and discuss major issues regarding accounting principles and financial statement presentations, including any significant changes in the Trust’s selection or application of accounting principles.  

(r)

Review and discuss the type and presentation of information to be included in earnings press releases, paying particular attention to any use of “pro forma” or “adjusted” non-GAAP information.  

(s)

Review and discuss with management the minutes of all meetings with the Company’s Disclosure Committee upon request.  

(t)

Review any other matters required by law, regulation or stock exchange requirement, or that the Committee feels are important to its mandate or that the Board chooses to delegate to it.

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3.

Composition

(a)

This Committee shall be composed of at least three individuals as determined by the Board from amongst its members, each of whom will be independent (within the meaning of Multilateral Instrument 52-110 Audit Committee of the Canadian Securities Administrators) unless the Board determines to rely on an exemption in NI 52-110. )

(b)

The Secretary to the Board or another individual as selected by the Committee shall act as Secretary to the Committee;

(c)

A quorum shall be a majority of the members of the Committee;

(d)

All of the members must be financially literate within the meaning of NI 52-110 unless the Board has determined to rely on an exemption in NI 52-110.  Being “financially literate” means members have the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the financial statements of Enterra.  In addition, at least one member of the Committee must have accounting or related financial management expertise, as the Board interprets such qualification in its business judgment.  

4.

Meetings

(a)

The Committee shall meet at least four times per year and/or as deemed appropriate by the Committee Chair.  As part of its job to foster open communication, the Committee should meet at least annually with management, internal auditors (if any) and the external auditors in separate executive sessions to discuss any matters that the Committee or each of these groups believe should be discussed privately.  In addition, the Committee or at least its Chair should meet with the external auditors and management quarterly to review the financials.  The Committee should also meet with management and the external auditors on an annual basis to review and discuss the annual financial statements and the management’s discussion and analysis of the financial conditions and results of operations.

(b)

Agendas, with input from management, shall be circulated to Committee members and relevant management personnel along with background information on a timely basis prior to the Committee meetings.  

(c)

The Committee shall ensure that minutes are prepared for each meeting of the Committee.  

(d)

The CEO and CFO or their designate shall be available to attend at all meetings of the Committee upon invitation by the Committee.

(e)

The Controller & Treasurer and such other employees as appropriate shall be available to attend and/or to provide information to the Committee upon invitation by the Committee.  

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5.

Reporting Obligations and Authority

(a)

Periodically, the Committee will provide a report to the Board of the material matters discussed and material resolutions passed at the Committee meeting.  Minutes of the Committee meeting will be provided to all Board members upon request.

(b)

Supporting schedules and information reviewed by the Committee shall be available for examination by any Director upon request.

(c)

The Committee shall have the authority to investigate any financial activity of Enterra and to communicate directly with internal (if any) and external auditors.  All employees are to cooperate as requested by the Committee.  

(d)

The Committee may retain and set and pay the compensation for, persons having special expertise and/or obtain independent professional advice, including the engagement of independent counsel and other advisors, to assist in fulfilling its duties and responsibilities at the expense of the Company.  

Amended Audit Committee Mandate was approved by the Board on December 12, 2006.

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APPENDIX “B-1”

FORM 51-101F2

REPORT ON RESERVES DATA BY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

1.

We have evaluated the Company’s Canadian reserves data as at December 31, 2007.  The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using future prices and costs and proved reserves and related future revenue as at December 31, 2007, estimated using constant prices and costs.  

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 Company evaluated by us for the year ended December 31, 2007, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Company’s management.

Description and Preparation Date of  Evaluation 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, 2007	Canada	-	$271,561	-	$271,561

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 our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.  However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.  

Executed as to our report referred to above:

McDaniel & Associates Consultants Ltd., Calgary, Alberta, Canada, March 24, 2008

Signed “B.J. Wurster”

B.J. Wurster, P.Eng

Vice-President

APPENDIX “B-2”

FORM 51-101F2

REPORT ON RESERVES DATA BY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

1.

We have evaluated the Company’s U.S. Oklahoma reserves data as at December 31, 2007.  The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using future prices and costs and proved reserves and related future revenue as at December 31, 2007, estimated using constant prices and costs.  

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 Company evaluated by us for the year ended December 31, 2007, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Company’s management.

Description and Preparation Date of  Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate  US$M)
		Audited	Evaluated	Reviewed	Total
December 31, 2007	U.S. Oklahoma	-	$211,578	-	$211,578

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 our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.  However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.  

Executed as to our report referred to above:

Haas Petroleum Engineering Services, Inc., Dallas, Texas, U.S., March 24, 2008

Signed “Robert W. Haas”

Robert W. Haas, P.Eng

President

APPENDIX “B-3

FORM 51-101F2

REPORT ON RESERVES DATA BY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

1.

We have evaluated the Company’s U.S. Wyoming reserves data as at December 31, 2007.  The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using future prices and costs and proved reserves and related future revenue as at December 31, 2007, estimated using constant prices and costs.  

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 Company evaluated by us for the year ended December 31, 2007, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Company’s management.

Description and Preparation Date of  Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate  US$M)
		Audited	Evaluated	Reviewed	Total
January 1, 2008	U.S. Powder River Basin, Wyoming	-	$3,310	-	$3,310

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 our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.  However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.  

Executed as to our report referred to above:

MHA Petroleum Consultants, Lakewood, Colorado, U.S., March 24, 2008

Signed “John P. Seidle”

John Seidle, Ph.D., P.Eng

Vice-President

APPENDIX “C”

FORM 51-101F3
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVE DATA AND OTHER INFORMATION

Management of Enterra Energy Corp. (the “Company”), is responsible for the preparation and disclosure of information with respect to the oil and gas activities of the Company in accordance with securities regulatory requirements.  This information includes reserves data which are (a) estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2007, estimated using forecast prices and costs and (b) proved reserves and related future net revenues as at December 31, 2007, estimated using constant prices and costs.  

Independent qualified reserves evaluators have evaluated the reserves data of the Company.  The reports of the independent qualified reserves evaluators will be filed with the securities regulatory concurrently with this report.  

The Reserves Committee of the board of directors of the Company has:

(a)

reviewed the Company’s procedures for providing information to the independent qualified reserves evaluators;

(b)

met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators   to report without reservation;

(c)

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

The Reserves Committee of the board of directors has reviewed the Company’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 Form 51-101F containing reserves data and other oil and gas information;

(b)

the filing of Form 51-101F2  which is the report of the independent qualified reserves evaluators on the reserves data; 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.  However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

Signed “Peter Carpenter”

Peter Carpenter

Chairman

Enterra Energy Corp.

Signed “Blaine Boerchers”

Blaine Boerchers
Chief Financial Officer

Enterra Energy Corp.

Signed “Roger Giovanetto ”

Roger Giovanetto

Director

Enterra Energy Corp.

March 28, 2008

APPENDIX “D”

CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS

The following information is with respect to Mr. Conrad:

On March 20, 2000, Niaski Environmental Inc., which Mr. Conrad was then an insider and control person, made a proposal to its creditors under the Bankruptcy Act, which was approved by the creditors on April 13, 2000.  The trustee was discharged in May, 2001.  On April 12, 2002, Rimron Resources Inc. (then Niaski Environmental Inc.) was involuntarily delisted from the Canadian Venture Exchange.  The trustee was discharged in May, 2001.

In July 2000, cease trade orders were issued by the Alberta, B.C. and Saskatchewan Securities Commission against Niaski Environmental Inc., which Mr. Conrad was then an insider and control person, for failure to file financial statements.  The deficiencies were rectified and the cease trade orders lifted.

The following information is with respect to Mr. Doyle:

On February 23, 2007, Mr. Doyle became a Director and took on the role of Chairman of Vanquish Energy Corp, a private Canadian oil and gas company that was in financial crisis.  Shortly thereafter, he replaced the Chief Executive officer, and assumed that role in order to better assess and best mitigate damage to all the stakeholders of the company. After discussion and negotiation with the secured creditor, the company entered into receivership on March 27, 2007.

EX-99.2

ENTERRA ENERGY TRUST

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is Management’s Discussion and Analysis (“MD&A”) of Enterra Energy Trust (“the Trust” or “Enterra”) for the year ended December 31, 2007.  This MD&A should be read in conjunction with the consolidated financial statements, together with the accompanying notes, of the Trust for the year ended December 31, 2007.  All amounts are stated in Canadian dollars and are prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”) except where otherwise indicated.  This MD&A was written as of March 31, 2008.  

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This MD&A includes forward-looking statements.  All statements other than statements of historical facts contained in this MD&A, including statements regarding the 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 the Trust, are intended to identify forward-looking statements.  The Trust has based these forward-looking statements on the current expectations and projections about future events and financial trends that the Trust believes may affect its financial condition, results of operations, business strategy and financial needs.  These forward-looking statements are subject to a number of risks, uncertai nties and assumptions as described elsewhere in this MD&A.

Other sections of this MD&A may include additional factors that could adversely affect the business and financial performance.  Moreover, the Trust operates in a very competitive and rapidly changing business environment.  New risk factors emerge from time to time and it is not possible for management to predict all risk factors, nor can the Trust assess the impact of all factors on its 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.

The Trust undertakes no obligation, except as required by securities law, to update publicly or revise any forward-looking statements.  You should not rely upon forward-looking statements as predictions of future events or performance.  The Trust cannot provide assurance that the events and circumstances reflected in the forward-looking statements will be achieved or occur.  Although the Trust believes that the expectations reflected in the forward-looking statements are reasonable, the Trust cannot guarantee future results, levels of activity, performance or achievements.

SPECIAL NOTE REGARDING NON-GAAP TERMS

This document contains the terms “funds from operations” and “netback”, which are non-GAAP terms.  The Trust uses these measures to help evaluate its performance.  The Trust considers funds from operations a key measure for the ability of the Trust to repay debt and to fund future growth through capital investment.  The term should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with Canadian GAAP as an indicator of performance.  The Trust considers netback a key measure for the ability of the Trust to analyze its operations.  The term should not be considered as an alternative to, or more meaningful than, net loss as determined in accordance with Canadian GAAP as an indicator of performance. Funds from operations and netback, as determined by the Trust may not be comparable to that reported by other companies.  The reconciliation for funds f rom operations to cash provided by operating activities and of netback to net loss can be found in the non-GAAP financial measures section of this MD&A.

CERTAIN FINANCIAL REPORTING MEASURES

Natural gas volumes recorded in thousand cubic feet (“mcf”) are converted to barrels of oil equivalent (“boe”) using the ratio of six (6) thousand cubic feet to one (1) barrel of oil (“bbl”).  Boe’s may be misleading, particularly if used in isolation.  A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.

OVERVIEW

Background

Enterra is a Canadian oil and gas trust with trust units listed on the Toronto Stock Exchange (ENT.UN) and the New York Stock Exchange (ENT).  The head office of the Trust is located in Calgary, Alberta and its United States office is located in Carney, Oklahoma.

The Trust portfolio of crude oil, natural gas liquids and natural gas interests is geographically diversified with producing properties located principally in Alberta, British Columbia, Saskatchewan and Oklahoma. Average production for 2007 of 12,428boe/day was comprised of approximately 62% natural gas and 38% crude oil and natural gas liquids.  

Current Focus of the Trust

Circumstances in 2007 that have resulted in the current suspension of Trust distributions are also causing a review of the key strategies of Enterra.  A primary goal for 2008 is the reduction of debt with the long term goal to improve the balance sheet.  At the same time, select capital reinvestment projects thought to have the best performance on a near term basis are being pursued and to the extent possible, production rates and reserve values are being preserved.  It is not anticipated that production and reserves values can be held flat with the current capital budget of $30.0 million for 2008.  Cost reduction at operating and overhead levels will be important to achieving both debt reduction and capital reinvestment goals.

Distributions to Unitholders

For the first eight months of 2007, the Trust had a strategy to deliver monthly cash distributions to its unitholders of 60% to 70% of funds from operations.  However, in September 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of debt.  As required by the September 28, 2007 amended credit facilities, the distributions were to be suspended until at least March 31, 2008.  Subsequently in December 2007 the board of directors determined to further suspend distributions until at least November 20, 2008 and this suspension became a term of the further amended credit facility effective December 18, 2007.  The curtailment of distributions has and will allow the redirection of cash flow to debt reduction, while maintaining a conservative capital reinvestment program for 2008.

Management Turnover in 2007

The Trust experienced significant turnover in key management positions during the year.  In particular, Enterra replaced its Chief Financial Officer, Vic Roskey and its Chief Operating Officer Kim Booth for U.S. operations in Q4.  Also, President and Chief Executive Officer Keith Conrad retired in December 2007 and subsequently stepped down as a director in February 2008.  With the exception of replacing Mr. Conrad, all key positions have been filled.

In October 2007, Enterra experienced the resignation of two independent directors.  These positions were filled in December 2007 and February 2008.

These consolidated financial statements have been prepared on a going concern basis in accordance with Canadian generally accepted accounting standards.  The going concern basis of presentation assumes that the Trust will continue its operations for the foreseeable future and be able to realize its assets and discharge its liabilities and commitments in the normal course of business.  

The debt agreements of the Trust currently require that borrowings under the second-lien facility, which is currently at $29.1 million, (see note 8) be reduced to $28.0 million by June 30, 2008.  Furthermore, the Trust must make interest payments on its convertible debentures (see note 11) of approximately $4.9 million on June 30, 2008.  Per the relevant agreements, the Trust cannot use cash flow from operations to fund the required debt and interest repayments.  Therefore, the Trust must use proceeds from asset dispositions or the issuance of new equity or new borrowings to make the required payments.  If the Trust is not able to meet these commitments by June 30, 2008 then the going concern assumption may not be appropriate and adjustments to the carrying values of assets and liabilities, the reported revenue and expenses, and the balance sheet classifications used may be necessary.  

Management believes that they have several options available to meet these commitments including; renegotiating these cash restrictions with the banking syndicate and funding the payments through cash flow or refinancing the entire bank syndicate debt with a debt facility with more flexible terms.  Management expects to have this issue resolved early in Q2 2008.

Business Strategy During 2007

The goal of Enterra has been to generate returns for its unitholders from steady and consistent increases in reserves, production and funds from operations per trust unit.  To achieve that goal the Trust has pursued a three-point strategy as follows:

Organic Growth

The Trust currently targets investment in the large portfolio of lower-risk development opportunities it has identified within its existing asset base.  The individual nature and number of opportunities varies across the properties, but in aggregate the Trust believes they offer a means of adding reserves and production on a basis that will be accretive to unitholders and at a pace that is generally within the control of the Trust.  As a method of countering natural production declines and potentially growing reserve values, the Trust believes that investing in such projects is in the long-term interest of unitholders.  

Accretive Acquisitions

Corporate and property acquisitions can be an effective means of consolidating assets, improving efficiencies in existing core areas or adding new core areas.  The ability to make material accretive acquisitions is subject to the business environment prevailing at any particular time and the availability of capital beyond the internally generated cash flow of the Trust.   

Strategic Partnerships

The Trust has actively sought to align itself with industry partners that provide access to projects that otherwise may not be available due to the nature or degree of risk involved or due to the expertise required to properly capitalize on the opportunity.  

In pursuing the strategies, Enterra has sought to manage the risk to unitholders by a geographically diversified production base, by maintaining a reasonable balance between liquids and gas production, operatorship and ownership of associated infrastructure, and maintaining a multi-year inventory of lower-risk development projects.

STRATEGIC ACQUISITION

On April 30, 2007, the Trust acquired all of the issued and outstanding shares of Trigger Resources Ltd. (“Trigger Resources”) for total consideration of $63.3 million.

Trigger Resources was a private company with operations in heavy oil and gas exploration and development in western Saskatchewan.  The acquisition increased the critical mass and footprint in the region and has been accretive to production, cash flow and reserves per unit.  Trigger Resources’ production at the date of acquisition was approximately 2,400 boe/day consisting of 1,400 bbls/day of oil and 6,000 mcf/day of natural gas.  Its properties generally have 100% working interest with year round access and enjoy relatively low operating costs.  The acquisition also provided the Trust with an additional 66,000 net undeveloped acres with significant drilling and development potential.

In April 2007, the Trust issued $40 million of 8.25% convertible debentures that mature on June 30, 2012 and $29.2 million of trust units (4,945,000 trust units).  The net proceeds from the issuances were used to finance the acquisition of Trigger Resources.  

OVERALL PERFORMANCE

Average production increased by 1% to 12,428 boe/day in 2007 from 12,352 boe/day in 2006.  The Trust exited the year with sales volumes of approximately 11,457 boe/day; 8% lower than the 2006 exit rate of 12,442 boe/day.  

Overall, oil prices received by the Trust in 2007 were less than in 2006 despite the increase in oil prices in the fourth quarter.  Gas prices received were consistent with 2006.  The reduced prices received by the Trust combined with relatively flat production resulted in total revenues, prior to mark-to-market hedging adjustment decreasing 4% from 2006.  Operating expenses increased 28% in 2007 to $14.29/boe compared to $11.17/boe in 2006.  G&A expenses increased 20% in 2007 to an average of $5.41/boe from $4.52/boe in 2006.  Interest expenses declined in 2007, due to the combined effect of lower average borrowings and a lower average interest rate, decreasing 15% to $22.6 million in 2007 compared to $26.7 million in 2006. The overall impact was that funds from operations decreased by 18% to $70.5 million in 2007 from $86.1 million in 2006.

In January and February of 2008, the Trust disposed of certain Canadian oil and gas assets for net cash proceeds of $39.9 million.  The Trust anticipates further net proceeds of $1.3 million upon the closing of an additional property sale.  The majority of these proceeds were directed to debt repayment.  

Proved and probable reserves decreased by 2% from the end of 2006 to the end of 2007 reflecting the acquisition of Trigger Resources and additional discoveries resulting from the 2007 drilling program and offset by reserves relating to properties that were held for sale at year end and 2007 production.

Over the course of 2007, the Trust paid distributions of $39.5 million to unitholders or US$0.60/unit, representing decreases of 56% and 67% respectively, compared to total distributions of $90.5 million or US $1.86/unit in 2006.  Distributions were suspended on September 17, 2007 and will remain suspended through at least November 2008 as part of the debt reduction strategy of the Trust.

Summary of Financial and Operating Results (in thousands except for volumes and percentages)
	Three months ended December 31			Years ended
	2007	2006	Change	2007	2006	Change
Revenues (1)	$44,470	$55,855	(20%)	$207,036	$244,220	(15%)
Average sales (boe/day)	12,174	11,905	2%	12,428	12,352	1%
Exit sales rate (boe/day)	11,457	12,442	(8%)	11,457	12,442	(8%)
Cash provided by operating activities	$2,215	$26,163	(92%)	$76,844	$64,485	19%
Funds from operations (2)	$12,110	$9,558	27%	$70,463	$86,117	(18%)
Net loss	$(39,481)	$(69,189)	43%	$(142,036)	(64,239)	(121%)
Net loss per trust unit - basic	$(0.64)	$(1.40)	54%	$(2.38)	$(1.46)	(63%)
Weighted average number of trust units outstanding - basic	61,433	49,415	24%	59,767	44,142	35%
Average price per barrel of oil	$64.23	$55.64	15%	$61.09	$62.13	(2%)
Average price per mcf of natural gas	$6.20	$7.91	(22%)	$7.04	$7.53	(7%)
Operating expenses per boe	$15.66	$16.04	(2%)	$14.29	$11.17	28%
Netback (3) per boe	$10.63	$9.46	12%	$14.66	$19.50	(25%)

(1)

Prior year restated to conform to presentation adopted in current year

(2)

Funds from operations are a non-GAAP financial measure.  See non-GAAP financial measures section of the MD&A for a reconciliation of this measure

(3)

Netback is a non-GAAP financial measure.  See non-GAAP financial measures section of the MD&A for a reconciliation of this measure.

QUARTERLY FINANCIAL INFORMATION

	2007				2006
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Revenues	$44,470	$55,685	$62,871	$44,010	$56,043	$73,335	$67,313	$47,717
Loss before taxes and NCI	$(55,618)	$(41,227)	$(8,173)	$(72,968)	$(101,242)	$(6,879)	$(10,579)	$(3,149)
Net earnings (loss)	$(39,481)	$(47,681)	$7,878	$(62,752)	$(69,189)	$3,000	$(296)	$2,248
Net earnings (loss) per unit
basic and diluted	$(0.64)	$(0.78)	$0.13	$(1.12)	$(1.40)	$0.07	$(0.01)	$0.06
Distributions declared per unit  (US$)	-	$0.12	$0.18	$0.18	$0.36	$0.36	$0.54	$0.54

The decreases in revenue in Q4 2007, Q3 2007, Q1 2007 and Q4 2006 were due to a combination of lower volumes, lower realized prices and reductions in the mark-to-market value of the derivatives of the Trust.  The decreases in distributions over the period reflect the changes in revenues as well as the decision by the Trust to reduce the level of its distributions to reduce debt.  The significant net losses in Q3 2007, Q1 2007 and Q4 2006 were due to ceiling test and goodwill impairment losses that were recorded in the periods.

RESULTS OF OPERATIONS

Average production for 2007 increased 1% to 12,428 boe/day from 12,352 boe/day in 2006.  Positive contributions to production during the year include the acquisition of Trigger Resources in Q2, start-up of a prolific Leduc well at Ricinus in late 2006, and production additions associated with our drilling programs in Oklahoma and Canada.  Offsetting these additions were natural declines, weather-related disruptions in Oklahoma due to record rainfalls for the year and a severe ice storm in December, drilling and production difficulties at our Primate field, and operational delays in tying in certain wells in Oklahoma due to equipment shortages.

Average production during 2007 consisted of 4,698 bbls/day of oil and natural gas liquids (“NGL”) and 46,378 mcf/day of natural gas, resulting in a mix of 38% oil and NGL and 62% natural gas.  At December 31, 2007 the Trust had an exit production rate of 11,457 boe/day.

Volumes for Q4 2007 averaged 12,174 boe/day up 2% compared to the average for Q4 2006 of 11,905 boe/day, but 5% below the average for Q3 2007 of 12,798 boe/day.  Production at the exit of Q4 2007 was 6% below the average for the quarter.  Factors contributing to the reduction in the 2007 exit rate included the sale in December of certain non-operated assets (166 boe/day) and weather-related issues in Oklahoma (350 boe/day) in addition to operational issues over year end at a prolific Leduc well in the Ricinus area (120 boe/day).  All of the operational issues have since been resolved.  

In 2007, the Trust participated in the drilling of 32 (11.8 net) wells; 13 (7.5 net) in Canada and 19 (4.3 net) in Oklahoma.  All wells in Oklahoma were drilled by a joint venture partner under an area farmout agreement that resulted in the joint venture partner paying 100% of the drilling and completion costs in exchange for 70% working interest.  Overall, the drilling in Canada and Oklahoma resulted in 23 (5.4 net) gas wells, 8 (5.4 net) oil wells and one well (1.0 net) that was drilled and abandoned, resulting in a success rate of 97%.

Canadian Operations

Production in Canada for the year was relatively unchanged compared to 2006.  Volumes averaged 3% lower at 7,387 boe/day in 2007 compared to 7,578 boe/day in 2006.  Gas represented approximately 45% of total production in 2007 versus 40% in 2006 on a boe basis.  For Q4 2007, volumes increased 7% to 7,512 boe/day compared to the average of 6,990 boe/day during Q4 2006.  The average for Q4 2007 is 4% lower than in Q3 2007 of 7,806 boe/day.  The 2007 exit rate for Canada was 7,167 boe/day.

The first quarter of 2007 marked the first wells drilled by the newly assembled technical and operations team at Enterra.  In February, a successful oil well was drilled at Halkirk and an existing well at Desan was re-entered as Enterra drilled a new lateral into a more prolific part of the reservoir.  The Desan well significantly contributed to our understanding of the Jean Marie play and sets the stage for future development plans in the area.  During Q2, the Trigger Resources acquisition added both heavy oil and natural gas production to the portfolio of assets and provided additional geographic diversification with significantly more production in Saskatchewan.  Additionally in Q2, Enterra executed a successful four well drilling program in the Primate area; all of which were on stream in Q3.  Drilling continued in the third quarter with another well in the Primate area.  Our technical team continues to refine, develop and prioritize our p rospect inventory in Canada.

U.S. Operations

Production in the United States averaged a total of 5,041 boe/day during 2007, of which 87% was natural gas.Production increased by 6% from 4,774 boe/day in 2006.  Volumes in the fourth quarter of 2007 in the US averaged 4,663 boe/day or 5% less than Q4 2006 and 7% less than the average for Q3 2007.  

Of the 19 (4.3 net) gas wells drilled in Oklahoma in 2007, 14 of the wells were on production at the end of 2007.  To the end of 2007, the joint venture partner of Enterra has drilled a total of 31 gas wells in the Oklahoma project area and had 3 drilling rigs operating continuously during the last half of 2007.  All of the wells drilled in the U.S. on behalf of the Trust during the year were successful.

Production
	Three Months ended December 31			Years  ended December 31
	2007	2006	Change	2007	2006	Change
Daily sales volumes – average
Oil & NGL (bbls/day)	4,585	4,774	(4%)	4,698	5,126	(8%)
Natural gas (mcf/day)	45,538	42,788	6%	46,378	43,358	7%
Total (boe/day)	12,174	11,905	2%	12,428	12,352	1%
Daily sales volumes - exit rate
Oil & NGL (bbls/day)	3,952	4,758	(17%)	3,952	4,758	(17%)
Natural gas (mcf/day)	45,031	46,105	(2%)	45,031	46,105	(2%)
Total (boe/day)	11,457	12,442	(8%)	11,457	12,442	(8%)
Sales volumes mix by product
Oil & NGL	38%	40%		38%	41%
Natural gas	62%	60%		62%	59%
	100%	100%		100%	100%

Production by Geographic Area
	Three Months Ended December 31, 2007		Year Ended December 31, 2007
	Canada	U.S.	Canada	U.S.
Daily sales volumes – average
Oil & NGL (bbls/day)	4,080	504	4,064	634
Natural gas (mcf/day)	20,589	24,951	19,933	26,444
Total (boe/day)	7,512	4,663	7,387	5,041
Daily sales volumes - exit rate
Oil & NGL (bbls/day)	3,584	368	3,584	368
Natural gas (mcf/day)	21,501	23,530	21,501	23,530
Total (boe/day)	7,167	4,290	7,167	4,290
Sales volumes mix by product
Oil & NGL	54%	11%	55%	13%
Natural gas	46%	89%	45%	87%
	100%	100%	100%	100%

COMMODITY PRICING

West Texas Intermediate (“WTI”) is a standard benchmark for the price of oil and is expressed in U.S. dollars per barrel.  The price of natural gas in the United States is benchmarked on the New York Mercantile Exchange (“NYMEX”) and expressed in U.S. dollars per million British Thermal Units (“mmbtu”).  In Western Canada the benchmark is the price at the AECO hub and is priced in Canadian dollars per gigajoule (“GJ”).  For the purposes of financial reporting, the Trust expresses its realized prices for oil and gas in Canadian dollars.

Oil prices increased 9% from 2006, averaging US$72.34/bbl in 2007.  The effect of the increase was off-set by a 6% year over year weakening of the U.S. dollar against the Canadian dollar, with the exchange rate rising to an average of US$0.93 per Canadian dollar in 2007 from an average of US$0.88 in 2006.  In the fourth quarter of 2007 WTI increased 51% to US$90.68/bbl compared to US$60.21/bbl in Q4 of 2006. The price increase was off-set by the strengthening of the Canadian dollar.  The Canadian dollar rose from an average of $0.88 against the US dollar in Q4 of 2006 to an average of $1.02 in Q4 of 2007 which represents a 16% increase.  

Natural gas prices on the NYMEX decreased US$0.34/mmbtu or 5%, from 2006, averaging US$6.92/mmbtu in 2007.  In Canada, AECO pricing was consistent with 2006 levels, averaging $6.55/GJ.

In Q4 2007, U.S. prices on the NYMEX were up from Q4 2006.  Prices averaged US$7.03/mmbtu in Q4 2007 compared to US$6.62 in Q4 2006.  AECO pricing was down by 11% in Q4 2007 to $6.14/mcf compared to $6.91/mcf in Q4 2006.  

The 2007 average price received for oil, net of hedge settlements, was down 2% to $61.09/bbl from $62.13/bbl in 2006.  The 2007 average price received for natural gas, net of hedge settlements, was down 7% to $7.04/mcf from $7.53/mcf in 2006.  

In Q4, while oil prices generally rose, the heavy oil to light oil price differential widened in the period and reduced the overall realization on oil production.  

Pricing
	Three Months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
Pricing benchmarks
WTI (US$/bbl)	90.68	60.21	51%	72.34	66.22	9%
Average exchange rate: US$ to Cdn$1.00	1.02	0.88	16%	0.93	0.88	6%
WTI (Cdn$/bbl)	88.90	68.42	30%	77.78	75.25	3%
AECO monthly index (Cdn$/GJ)	6.14	6.91	(11%)	6.55	6.53	-
NYMEX (US$/mmbtu)	7.03	6.62	6%	6.92	7.26	(5%)
Average prices received
Oil  (Cdn$ per bbl)	67.89	55.64	22%	61.84	62.54	(1%)
Natural gas (Cdn$ per mcf)	5.88	7.12	(17%)	6.60	6.70	(2%)
Oil commodity contract settlements (Cdn$ per bbl)	(3.66)	-	-	(0.75)	(0.41)	(83%)
Natural gas commodity contract settlements  (Cdn$ per mcf)	0.32	0.79	(60%)	0.44	0.83	(47%)
Combined oil and NGL  (Cdn$ per bbl)	64.23	55.64	15%	61.09	62.13	(2%)
Combined natural gas (Cdn$ per mcf)	6.20	7.91	(22%)	7.04	7.53	(7%)
Total (1) (Cdn$ per boe)	47.36	50.48	(6%)	49.34	51.82	(5%)

^{(1) Includes NGL}

Management has a policy allowing hedging up to 50% of its projected gross production up to 24 months in advance, using price collars and avoiding fixed price sales, so that the Trust is less exposed to significant short-term downward swings in commodity prices.

At December 31, 2007, the following financial derivatives and fixed price contracts were outstanding:  

Derivative Instrument	Commodity	Price	Volume (per day)	Period
Collar	Gas	8.00 by 12.00 (Cdn$/GJ)	10,000 GJ	November 1, 2007 – March 31, 2008
Floor	Gas	8.00 (US$/mmbtu)	10,000 mmbtu	November 1, 2007 – March 31, 2008
Collar	Gas	7.00 by 11.00 (US$/mmbtu)	3,000 mmbtu	November 1, 2007 – March 31, 2008
Fixed	Gas	7.95 (US$/mmbtu)	2,000 mmbtu	April 1, 2008 – October 31, 2008
Collar	Gas	6.50 by 10.50 (US$/mmbtu)	3,000 mmbtu	April 1, 2008 – October 31, 2008
Collar	Oil	55.00 by 75.25 (US$/bbl)	500 bbl	January 1, 2008 – June 30, 2008
Collar	Oil	62.00 by 78.00 (US$/bbl)	500 bbl	January 1, 2008 – June 30, 2008
Collar	Oil	62.00 by 75.50 (US$/bbl)	500 bbl	January 1, 2008 – March 31, 2008
Collar	Oil	62.00 by 75.60 (US$/bbl)	500 bbl	April 1, 2008 – June 30, 2008
Collar	Oil	62.00 by 80.50 (US$/bbl)	500 bbl	July 1, 2008 – December 31, 2008
Collar	Oil	62.00 by 80.05 (US$/bbl)	500 bbl	July 1, 2008 – December 31, 2008
Fixed purchase	Power (Alberta)	62.90 (Cdn$/Mwh)	72 Mwh	July 1, 2007 – December 31, 2009

As at December 31, 2007 the above commodity contracts had a net mark-to-market liability position of $5.2 million.  Subsequent to December 31, 2007, the following financial derivatives and fixed price contracts were entered into:

Derivative Instrument	Commodity	Price	Volume (per day)	Period
Collar	Oil	72.00 by 91.50 (US$/bbl)	1,000 bbl	January 1, 2009 – December 31, 2009
Remove Ceiling	Oil	78.00 (US$/bbl)	500 bbl	February 1, 2008 – June 30, 2008
Collar	Gas	6.00 by 7.25 by 9.75 (US$/mmbtu)	5,000 mmbtu	April 1, 2008 – October 31, 2008
Fixed	Gas	7.84 (Cdn$/GJ)	2,000 GJ	April 1, 2008 – October 31, 2008

REVENUES

Natural gas revenue was consistent with 2006 at $119.1 million.  Natural gas production volumes for 2007 increased by 1% however this was offset by a 7% decrease in the sales price of natural gas received for 2007.  For oil and NGL, the 8% revenue decrease from 2006 was consistent with an 8% decrease in production volumes from 2006, while the oil price received decreased slightly.  Overall, in 2007 revenues decreased by $37.2 million or 15% compared to 2006 with much of the decrease attributable to rising oil prices that resulted in an unrealized mark-to-market loss of $16.8 million at year-end compared to a mark-to-market gain at the end of 2006 of $10.6 million.

Revenue in Q4 2007 decreased 20% to $44.5 million from $55.9 million in 2006.  Similar to the full year results, the decrease in revenue was largely attributable to the unrealized mark-to-market loss on the financial instruments.

Revenues (in thousands except for percentages)
	Three Months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
Revenues (1)
Oil and NGL	$27,089	$24,140	12%	104,753	$114,481	(8%)
Natural gas	25,959	31,156	(17%)	119,075	119,111	-
	53,048	55,296	(4%)	223,828	233,592	(4%)
Unrealized mark-to-market gain/(loss) on financial instruments	(8,578)	559	(1,635%)	(16,792)	10,628	(258%)
Oil and natural gas revenues	44,470	$55,855	(20%)	207,036	$244,220	(15%)

(1)  Prior year restated to conform to presentation adopted in current year

Revenues by Geographic area (in thousands)
	Three Months ended December 31, 2007		Year ended December 31, 2007
	Canada	U.S.	Canada	U.S.
Revenues
Oil and NGL	$22,985	$4,104	$87,454	$17,299
Natural gas	12,046	13,913	51,390	67,685
	35,031	18,017	138,844	84,984
Unrealized mark-to-market gains (loss) on financial instruments	(6,245)	(2,333)	(10,439)	(6,353)
Oil and natural gas revenues	$28,786	$15,683	$128,405	$78,631

ROYALTIES

Royalties, which include Crown, freehold and overriding royalties and wellhead taxes, less Alberta Royalty Tax Credits (“ARTC”), vary depending on the jurisdiction, the volumes produced, total volumes sold and the price received for the sales. Overall, royalties decreased in 2007 compared to 2006 as a result of royalty rebates realized in the U.S.  The U.S. operations applied for, and received, a royalty rebate for its horizontal wells in the state of Oklahoma.  Enterra realized rebates of $3.2 million in 2007 for royalties paid in 2006 and 2007.  Enterra expects to receive the 6% rebate for all new horizontal wells drilled in Oklahoma for a time period of 48 months after each well is drilled.  

In late October 2007, the Alberta provincial government announced a new oil and gas royalty regime to take effect January 1, 2009.  The government has provided some details of the proposed royalty regime, however discussions with industry are ongoing and legislation is still pending. The Trust will assess the net economic impact on its future financial performance and reserve values when the scheme is confirmed, however the overall impact is expected to be modest given preliminary estimates generated by the independent engineers of the Trust.  Overall at the end of December 2007, approximately 38% of Enterra’s production came from Alberta.

Royalties (in thousands except for percentages and per boe amounts)
	Three Months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
Royalties	$10,860	$11,196	(3%)	$45,365	$48,288	(6%)
As a percentage of revenues	20%	20%		20%	21%
Royalties per boe	$9.70	$10.22	(5%)	$10.00	$10.71	(7%)

Royalties by Geographic Area (in thousands except for percentages and per boe amounts)
	Three Months ended December 31, 2007		Year ended December 31, 2007
	Canada	U.S.	Canada	U.S.
Royalties	$6,966	$3,894	$27,497	$17,868
As a percentage of revenues	20%	22%	20%	21%
Royalties per boe	$10.08	$9.08	$10.20	$9.71

OPERATING EXPENSES

In 2007, operating costs increased 28% to $14.29 per boe compared to $11.17 per boe in 2006.  In Q4 2007, operating costs decreased to $15.66/boe from $16.04/boe in Q4 2006.

Canadian operations experienced increased costs associated with regulatory compliance, increased well workover costs, and repair and environmental expenses associated with three pipeline failures in Canada.  Severe weather conditions increased costs and reduced production in Oklahoma as record spring and summer rain, were followed by a destructive ice storm in December.  U.S. operating costs expressed in Canadian dollars decreased in Q4 of 2006 primarily due to a gain in the U.S./Cdn$ exchange rate.

Canadian Assets

In Canada, 2007 average operating expense increased by 32% to $16.91 per boe versus $12.84 per boe in 2006.  Total operating expenses increased 28% in 2007 to $45.6 million from $35.5 million in 2006.  The Trigger Resources acquisition increased operating expenses by $3.8 million.  In Q4 2007, operating costs increased slightly to $19.45 per boe compared to $19.28 per boe in Q4 2006.

U.S. Assets

Operating expenses for the U.S. assets in 2007 increased to $10.45 per boe from a 2006 average of $8.52 per boe.  Q4 2007 operating expense decreased by 16% to $9.57 per boe from $11.43 per boe in Q4 2006 and decreased by 7% compared to Q3 2007 operating costs of $10.32 per boe.

Operating Expenses (in thousands except for percentages and per boe amounts)
	Three months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
Operating expenses	$17,545	$17,570	-	$64,823	$50,361	29%
Operating expenses per boe	$15.66	$16.04	(2%)	$14.29	$11.17	28%

Operating Expenses by Geographic Area (in thousands except for percentages and per boe amounts)
	Three months ended December 31, 2007		Year ended December 31, 2007
	Canada	U.S.	Canada	U.S.
Operating expenses	$13,440	$4,105	$45,600	$19,223
Operating expenses per boe	$19.45	$9.57	$16.91	$10.45

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses (“G&A”) increased 20% in 2007 to $24.5 million from $20.4 million in 2006.   G&A per boe increased by 20% to $5.41 per boe in 2007 compared to $4.52 per boe in 2006.  The increase in general and administrative costs related primarily to an increase in personnel in 2007 from 2006 and increased consulting costs in Q3 and Q4 2007 related to the turnover of management and employees.  Of the $24.5 million, $0.4 million related directly to financing fees on the credit facilities amendments in Q4 2007.  

Financing fees of $5.4 million were incurred in Q4 2006 on the settlement of the bridge loans and financial advisors related to the 2006 credit facilities which were separately disclosed.  

General and Administrative Expenses (in thousands except for percentages and per boe amounts)
	Three Months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
G&A expenses	$7,111	$7,608	(7%)	$24,542	$20,374	20%
G&A per boe	$6.35	$6.95	(9%)	$5.41	$4.52	20%

INTEREST EXPENSE

Total interest expense decreased in 2007 by 15% to $22.6 million compared to the 2006 amount of $26.7 million. This is a combination of lower interest rates in 2007 from 2006 and a lower average debt balance offset by a full year of interest on the $80.3 million convertible debentures issued in late 2006 and the $40.0 million of convertible debentures issued in April 2007.  

Enterra began 2007 with a bank indebtedness of $187.7 million which bore interest at banker’s acceptance (“BA”) rates, Canadian or U.S. prime rates, or LIBOR plus applicable margins of nil to 1.65%.  Enterra issued convertible debentures of 138.0 million bearing interest at 8.00% on November 21, 2006 with a maturity date of December 31, 2011.  $80.3 million remained unconverted as at December 31, 2007.  $40.0 million of convertible debentures bearing interest at 8.25% were issued on April 28, 2007 with a maturity date of June 30, 2012.   

For the majority of 2006, the debt balance ranged from $160.0 million to $350.0 million, making up a significant portion of the $25.9 million of interest expense on bank indebtedness, capital leases and notes payable for the year ended 2006.  This was comprised of a $110.0 million bridge loan bearing an average interest rate of 8% until November 2006 and US$200.0 million at an average interest rate of 10.0%.  The loans were mainly to fund the acquisition of the Oklahoma assets.  At November 21, 2006, these were replaced by credit facilities with the current bank syndicate, convertible debentures and trust units.

Interest expense of about $10.0 million on the convertible debentures reflects a full year of interest on the remaining unconverted balance of $80.3 million at 8% plus the $40.0 million of convertible debentures issued in April 2007 bearing interest at 8.25% to fund the purchase of Trigger Resources.  Total indebtedness including convertible debentures at the end of 2007 had a face value of $292.3 million compared to $268.5 million at the end of 2006.  

Interest expense for convertible debentures in Q4 2007 increased by $2.0 million compared to Q4 2006.  

Interest Expense (in thousands except for percentages and per boe amounts)
	Three months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
Interest expense on bank indebtedness, capital lease, and notes payable	$2,806	$7,739	(64%)	$12,619	$25,898	(51%)
Interest expense on convertible debentures	2,823	819	245%	9,963	819	1,116%
Interest expense	$5,629	$8,558	(34%)	$22,582	$26,717	(15%)
Interest expense per boe on bank indebtedness, capital lease, and notes payable	$2.51	$7.07	(65%)	$2.78	$5.74	(52%)
Interest expense per boe on convertible debentures	2.52	0.75	236%	2.20	0.18	1,120%
Interest expense per boe	$5.03	$7.81	(36%)	$4.98	$5.92	(16%)

DEPLETION, DEPRECIATION AND ACCRETION (“DD&A”)

DD&A expense decreased by 8% in 2007 to $124.4 million compared to $135.4 million in 2006 due to the lower property, plant and equipment values in relation to the reserve values.

At December 31, 2006, Enterra recorded a ceiling test impairment on its Canada and U.S. cost centers in the amount of $66.0 million.  At the end of Q1 2007 an additional provision of $2.1 million was necessary due to a ceiling test write down in the Canada cost center.  This charge was taken due to a reduction in the value of certain undeveloped lands and the incurrence of facility upgrade costs which did not result in additional reserve volumes.  In Q4 2007, an impairment of $24.2 million was required due to an additional ceiling test write down in the Canadian cost center.   This charge was the result of the fair value of the assets sold subsequent to year end being greater than the book value of those properties.  

In the fourth quarter of 2007, DD&A expense excluding impairment decreased 10% to $32.5 million from $36.1 million in Q4 2006 due in part to the disposition of assets in Q4 2007 in the Princess area.   

Ceiling test

Under Canadian GAAP, a ceiling test is applied to the carrying value of the property, plant and equipment and other assets. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties, and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties, and the cost of major development projects. When required the cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate.  

Depletion, Depreciation and Accretion  (in thousands except for percentages and per boe amounts)
	Three Months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
DD&A – excluding impairment/loss	$32,458	$36,148	(10%)	$124,447	$135,429	(8%)
Impairment	24,143	66,019	(63%)	26,254	66,019	(60%)
DD&A	$56,601	$102,167	(45%)	$150,701	$201,448	(25%)
DD&A per boe – excluding impairment/loss	$28.98	$33.00	(12%)	$27.43	$30.04	(9%)
Impairment per boe	21.56	60.28	(64%)	5.79	14.64	(60%)
DD&A per boe	$50.54	$93.28	(46%)	$33.22	$44.68	(26%)

GOODWILL IMPAIRMENT

During Q1 2007 and Q3 2007 the Trust recorded $49.3 million and $27.1 million impairment expense respectively, on the carrying balance of goodwill in the Canadian reporting unit.  No goodwill remains at December 31, 2007.  

TAXES

Future income tax reduction of $36.1 million arose mainly due to the reduction in book basis due to the impairment on property, plant and equipment in 2007.  The increase in non-capital losses gave rise to $4.9 million in future income tax reduction.  Depletion expense, which includes impairment of property, plant and equipment accounted for another $31.5 million.  The reduction in 2006 of $58.9 million is higher than in 2007 due to the adjustment in tax rate from 34.5% in 2005 to 32.1% giving rise to an income tax reduction of $6.7 million in 2006.

The acquisition of Trigger Resources resulted in the recognition of a future income tax liability of $15.6 million representing the difference between the tax basis and the fair value assigned to the acquired assets.  

In determining its taxable income, Enterra Energy Corp., a wholly owned subsidiary of the Trust ("the Corporation”) deducts interest payments made to the Trust, effectively transferring the income tax liability to unitholders thus reducing the Corporation’s taxable income to nil.  Under the Corporation’s policy, at the discretion of the board of directors, funds can be withheld from distributions to fund future capital expenditures, repay debt or other purposes.  In the event withholdings increase sufficiently, the Corporation could become subject to taxation on a portion of its income in the future.  This can be mitigated through options including the issuance of additional trust units, increased tax pools from additional capital spending, modifications to the distribution policy or potential changes to the corporate structure.  The corporate subsidiaries of the Trust are subject to tax if deductions are inadequa te to reduce taxable income to zero.  

On October 31, 2006 the Canadian Minister of Finance announced certain changes to the taxation of publicly traded trusts (“Bill C-52”). Bill C-52, the Budget Implementation Act 2007 received its third reading and was substantively enacted on June 12, 2007.  Bill C-52 applies to a specified investment flow-through (“SIFT”) trust and will apply a tax at the trust level on distributions of certain income from such SIFT trusts at a rate of tax comparable to the combined federal and provincial corporate tax rate.  These distributions will be treated as dividends to the trust unitholders.  The Trust constitutes a SIFT and as a result, the Trust and its unitholders will be subject to Bill C-52.  

Bill C-52 commences January 1, 2007 for all SIFT’s that began to be publicly traded after October 31, 2006 and commencing January 1, 2011 for all SIFT’s that were publicly traded on or before October 31, 2006.  It is expected that the Trust will not be subject to the taxation requirements of Bill C-52 until January 1, 2011.

Commencing January 1, 2011, the Trust will not be able to deduct certain of its distributed income.  The Trust will become subject to a distribution tax of 28 percent on distributions of income, but this tax will not apply to returns of capital.  Enterra will consider the options and alternative structures with legal and business advisors to determine if any potential restructuring available to maximize value is in the best interest of unitholders.  

The federal component of the proposed tax on SIFT is expected to be 15 percent in 2012 (28 percent total) and thereafter.  The Trust is required to recognize, on a prospective basis, future income taxes on temporary differences in the Trust.  In Q2 2007, a $9.9 million reduction of the future income tax liability was recorded for temporary difference. Subsequent to Q2 2007, the Trust suspended its distributions which caused this temporary difference to no longer meet the criteria for future income tax asset recognition.  Overall, there was nil impact in 2007 due to the proposed tax on SIFT.  

NON-GAAP FINANCIAL MEASURES

The Trust provides financial measures in the MD&A that do not have a standardized meaning prescribed by GAAP.  These non-GAAP financial measures may not be comparable to similar measures presented by other entities.  The purpose of these financial measures, and their reconciliation to GAAP financial measures, are shown below.  All of the measures have been calculated on a basis that is consistent with previous disclosures.

Netback per boe of production is summarized below:

Netback per boe
	Three Months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
Price received per boe (prior to unrealized MTM)	$47.36	$50.48	(6%)	$49.34	$51.82	(5%)
Royalties per boe	9.70	10.22	(5%)	10.00	10.71	(7%)
Operating expense per boe	15.66	16.04	(2%)	14.29	11.17	28%
Operating netback per boe	$22.00	$24.22	(9%)	$25.05	$29.94	(16%)
G&A per boe	6.35	6.95	(9%)	5.41	4.52	(20%)
Interest expense per boe	5.03	7.81	(36%)	4.98	5.92	(16%)
Corporate netback per boe	$10.63	$9.46	12%	$14.66	19.50	(25%)

Management uses netback to analyze operating performance.  Netback, as presented, is not intended to represent an alternative to net earnings (loss) or other measures of financial performance calculated in accordance with GAAP.  All references to netback throughout this MD&A are based on the reconciliation in the table below:

Netback (in thousands, except per boe)
	Three Months ended December 31		Years ended December 31
	2007	2006	2007	2006
Net loss	$(39,481)	$(69,189)	$(142,036)	$(64,239)
Income taxes	(16,136)	(31,951)	(35,950)	(57,575)
Foreign exchange gain	886	1,384	546	1,910
Non-controlling interest	-	(101)	-	(36)
Depletion, depreciation and accretion	56,601	101,987	150,701	201,448
Goodwill impairment	-	-	76,463	-
Amortization of deferred financing fees and financing fees	-	8,792	-	17,160
Other	1,457	-	-	-
Unrealized mark-to-market gains (loss) on financial instruments	8,578	(559)	16,793	(10,628)
Corporate netback	$11,905	$10,363	$66,517	$88,040
Total volume (boe)	1,120,049	1,095,260	4,536,093	4,508,480
Corporate netback per boe (non-GAAP)	$10.63	$9.46	$14.66	$19.50

Funds from Operations

Management uses funds from operations to analyze operating performance and leverage.  Funds from operations, as presented, is not intended to represent cash provided by operating activities nor should it be viewed as an alternative to cash provided by operating activities or other measures of financial performance calculated in accordance with GAAP.  All references to funds from operations throughout this MD&A are based on cash provided by operating activities, before changes in non-cash working capital, as reconciled in the table below:

Funds from operations (in thousands)
	Three Months ended December 31		Years ended December 31
	2007	2006	2007	2006
Cash provided by operating activities	$2,215	$26,163	$76,844	$64,485
Changes in non-cash working capital items	9,895	(16,605)	($6,381)	21,632
Funds from operations	$12,110	$9,558	$70,463	$86,117

In 2007, funds from operations decreased by 18% over 2006.  The decrease was primarily due to lower realized prices, an increase in operating expenses and higher general and administrative expenses.  These decreases were partially offset by lower interest expenses and the benefit of the results from Trigger Resources beginning in May 2007.

In Q4 2007, the benefit of higher production volumes due to the acquisition of Trigger Resources was only partially offset by the effects of lower commodity prices and higher operating expenses compared to Q4 2006.  As a result, funds from operations for the period increased by $2.6 million to $12.1 million compared to $9.6 million in Q4 2006.

DISTRIBUTIONS

	Three Months ended December 31 2007	Year ended December 31 2007	Years ended December 31
Cash provided by operating activities	$2,215	$76,844	$64,485	$68,120
Net earnings (loss)	$(39,481)	$(142,036)	$(64,239)	$970
Cash distributions paid	-	$39,486	$90,487	$66,195
Excess (shortfall) of cash provided by operating activities over cash distributions paid	$2,215	$37,358	$(26,002)	$1,925
Shortfall of net earnings (loss) over cash distributions paid	$(39,481)	$(181,522)	$(154,726)	$(65,225)

To the extent that the Trust uses cash to reduce debt and fund capital additions, acquisitions and other significant expenditures, the cash that is available for distribution to unitholders will be reduced.  Cash distributions as a percentage of funds from operations in Q4 2007 were 0%.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt. In December 2007, Enterra has committed to extend the distribution suspension period for the duration of the credit facilities in order to advance its debt repayment.  

The Trust currently minimizes cash income taxes in corporate subsidiaries by maximizing deductions.  However, in future periods, there may be cash income taxes if deductions in the corporate entities are not sufficient to eliminate taxable income.  Taxability of the Trust was, until September 2007, passed on to unitholders in the form of taxable distributions.  The Trust anticipates that, commencing in 2011, new tax legislation that will subject the Trust to a tax in a manner similar to corporations will decrease the amount of cash available for distribution and thus reduce any potential cash distributions to unitholders.

Distributions paid to unitholders

During 2007 the Trust paid monthly cash distributions to its unitholders in U.S. dollars.  Cash distributions were paid on the 15^th of the following month or the next business day if the 15^th of the month fell on a weekend or a statutory holiday.  These distributions were determined each month by the board of directors, after review of a number of factors potentially impacting the Trust including its available prospects and opportunities, the outlook for commodity prices, other macro-economic factors and the financial position and commitments of the Trust.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.  

In July 2006 and again in January 2007 the Trust lowered the level of its distribution with the intent of investing additional cash flow in activities that would allow it to replace produced reserves and offset natural production declines and thus sustain distributions.  Distributions declared in 2006 were US$0.18 for the first half of the year, then reduced to US$0.12 for the remainder of 2007.  In January to August 2007, distributions of US$0.06 were declared per unit.  

Taxation of distributions

Distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable).  The return of capital component reduces the cost basis of the trust units held.  For 2007, distributions declared will be 99.97% return on capital for the year (taxable) and 0.03 % return of capital per unit for the year (tax deferred).  For a more detailed breakdown, please visit our website at www.enterraenergy.com.

CAPITAL EXPENDITURES

The following table represents the capital expenditures that were paid for with cash.  The table excludes certain capital expenditures, such as the portion of the cost of acquiring the Oklahoma Assets which was paid for with non-cash consideration such as trust units.

Capital Expenditures (in thousands except for percentages)
	Three Months ended December 31			Years ended December 31
	2007	2006	Change	2007	2006	Change
Capital expenditures	$5,137	$5,144	-	$95,047	$213,101	(55%)

The Trust accounts for its investment in its U.S. operations as a self-sustaining operation which means the capital assets associated with the U.S. operations (as well as all other balance sheet accounts for the U.S. operations) are subject to revaluation to the current exchange rate at each balance sheet date.  The result of this revaluation is a change in the carrying value of the U.S. assets from period to period, which is not a result of capital additions or disposals.  

On April 30, 2007, the Trust closed the acquisition of Trigger Resources.  The results of operations of Trigger Resources are included in the consolidated financial statements as of April 30, 2007.  Total consideration paid for Trigger Resources was $63.3 million (including transaction costs of $0.3 million).

Excluding the acquisition of Trigger Resources, during the year ended December 31, 2007 in Canada, the Trust spent $16.0 million in capital expenditures the major components of which include; $2.2 million on 3-D seismic in northeastern British Columbia to aid in the development of the proved and probable reserves, $6.9 million related to drilling and completions of which $2.2 million was related to the four wells drilled on the lands in Saskatchewan, $0.7 million for the construction of facilities and pipelines and $5.5 million for other plant and equipment.  The Trust sold $11.3 million of non-core assets during the year.

During the year ended December 31, 2007 in the U.S., approximately $5.3 million of the $15.7 million capital expenditures in the U.S. operations was spent on acquisitions of land for future development in Oklahoma.  In addition, $3.8 million was incurred on completion and equipping of two salt water disposal wells and $3.0 million on infrastructure additions to service the new wells being added by the strategic partner of the Trust.  All of the expenditures were in support of new wells being drilled under the area farm-out agreement.  An additional expenditure of $3.3 million (before adjustments) was spent for the acquisition of assets from a working interest owner in certain oil and gas properties located in Wyoming.

During 2007 in the U.S., costs totaling $4.0 million for a salt water disposal well and its related infrastructure were removed from property, plant and equipment and classified as a receivable.  Under the agreement with the joint venture partner, Enterra will recover the costs of the infrastructure over a three-year period.  During 2007, the Trust earned $0.4 million of interest revenue on the receivable under this arrangement.

RESERVES AND PRESENT VALUE SUMMARY

Enterra complies with the National Instrument 51-101, issued by the Canadian Securities Administrators, in all its reserves related disclosures.

Proved reserves (P90) - For reported reserves this means there must be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

Proved plus Probable (P50) - For reported reserves there must be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the proved plus probable reserves.

The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of oil and gas activities by reporting issuers and elevate reserves reporting to a higher level of accountability.

Reserve volumes and values at December 31, 2007 are based on the interest in total proved and probable reserves prior to royalties as defined in NI 51-101.  Reserve volumes and values for years prior to 2003 are based on "established" (proved plus 50% probable) reserves prior to deduction of royalties.  Under those definitions, probable reserves were discounted by an arbitrary risk factor of 50% in reporting established reserves.  Under NI 51-101 reserves definitions, estimates are prepared such that the full proved and probable reserves are estimated to be recoverable (proved plus probable reserves are effectively a "most likely case").  As such, the probable reserves reported are already "risked."  

The reserves have been evaluated by independent engineers each year.  McDaniel and Associates Consultants Ltd. ("McDaniel") independently evaluated the 2007 Canadian reserves, MHA Petroleum Consultants, Inc. (“MHA”) independently evaluated the Wyoming reserves and Haas Petroleum Engineering Services, Inc. (“Haas”) evaluated the Oklahoma reserves as at December 31, 2007.

Reserve Continuity - Oil and Gas (mboe)
	Proved	Probable	Total
December 31, 2005	14,295	4,737	19,032
Discoveries and extensions	536	549	1,085
Purchases	15,041	1,961	17,002
Dispositions	(1,492)	(613)	(2,105)
Production	(4,508)	0	(4,508)
Revision of prior estimates	(2,654)	(494)	(3,149)
December 31, 2006	21,218	6,140	27,357
Discoveries and extensions	1,419	1,141	2,560
Purchases	2,731	1,857	4,588
Dispositions	(468)	(175)	(643)
Production	(4,536)	0	(4,536)
Revision of prior estimates	1,125	(193)	932
December 31, 2007, including properties sold subsequent to year end	21,489	8,770	30,259
Properties sold subsequent to year end	2,427	915	3,342
December 31, 2007, excluding properties sold subsequent to year end	19,062	7,855	26,917

Proved plus probable reserves increased 11% from the end of 2006 to the end of 2007 primarily due to the acquisition of Trigger Resources and ongoing development in Oklahoma and in Canada.  Proved reserves increased slightly from 21,218 mboe to 21,489 mboe.  Probable reserves increased 43% from 6,140 mboe to 8,770 mboe.  Total proved reserves represent 71% of total reserves versus 78% in 2006.

Discoveries and extensions of 2,560 mboe are primarily from the successful development well program in Oklahoma and recognition of a development location in our Ricinus Leduc pool based upon the performance of the existing well.  Revisions of prior estimates occurred both in the Canadian assets and the United States assets due to better than expected performance of our existing wells, increases in commodity price forecasts and increased operating expenditures.  Divesting of non-core assets during 2007 in Canada resulted in 643 mboe reduction in proved plus probable reserves.

Finding costs incurred over the last three years are highlighted below, along with the recycle ratios for each year.  Management uses the recycle ratio as a measure performance.  It is calculated by dividing the operating netback per boe of production by the cost per boe of finding and developing reserves. A recycle ratio of one is considered a “break even point”, indicating that the cash flow from a unit of production is equal to the cost of finding and developing a unit of reserves.

Under NI 51-101, the methodology to be used to calculate finding, development and acquisition costs (“FD&A”), includes incorporating changes in future development costs (“FDC”) required to bring the proved undeveloped and probable reserves to production.  For continuity the Trust has presented FD&A costs calculated both excluding and including FDC.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

FD&A and recycle ratio (in $/boe, except for capital expenditures, FDC and reserves which are in thousands)
	Years ended December 31,					3-year
	2007	2006		2005		Average
Capital expenditures (excluding ARO)	$95,047		$416,649		$419,679	$310,458
Future Development Costs         Proved	$34,224		$10,101		$6,973	17,099
Proved Plus Probable	$49,268		$15,002		$7,448	$23,906
Reserves (1)
Proved reserves added in the year (mboe)	5,276		12,922		9,735	9,311
Probable reserves added in the year (mboe)	2,805		2,016		2,713	2,511
Proved plus probable reserves added in the year  (mboe)	8,080		14,938		12,448	11,822
FD&A costs (excluding FDC)
Proved reserves ($/boe)	18.02		32.24		43.11	31.12
Proved plus probable reserves ($/boe)	11.76		27.89		33.71	24.45
FD&A costs (including FDC)
Proved reserves ($/boe)	24.50		33.03		43.83	33.79
Proved plus probable reserves ($/boe)	17.86		28.90		34.31	27.02
Recycle ratios
Corporate netbacks ($/boe) (2)	14.66		19.50		25.98	20.05
Corporate recycle ratio (based on proved plus probable finding costs excluding FDC’s)	1.25		0.70		0.77	0.91
Operating netbacks ($/boe) (3)	25.05		29.94		31.31	28.77
Operating recycle ratio (based on proved plus probable reserves excluding FDC’s))	2.13		1.07		0.93	1.38
(1) Includes revisions and acquisitions
(2) Corporate netbacks are production revenue less royalties, operating expenses, G&A and interest expense
(3) Operating netbacks are production revenue less royalties and operating expenses

Finding costs and recycle ratios are non-GAAP financial measures that may not be comparable to similar measures presented by other entities.

The Trust reduced its proved plus probable FD&A excluding FDC costs from $27.89/boe to $11.76/boe. This was due to the acquisition of Trigger Resources, the farm-in arrangement for development of the Oklahoma assets and improved capital project selection and improved project execution, all of which contributed to better capital efficiency than in prior years.

Enterra Energy Trust - Estimated Petroleum and Natural Gas Reserves and Net Present Value

December 31, 2007 (NPV in millions)

	Light/					Net Present Value
	Medium	Heavy		Natural		Before Income Tax ($)
	Oil	Oil	NGL	Gas	Total
	(mbbl)	(mbbl)	(mbbl)	(mmcf)	(mboe)	0%	5%	10%
Canadian Assets
McDaniel report
Proved Producing	2,100	1,444	526	33,747	9,694	233	206	185
Proved Non-Producing	26	13	38	1,995	409	(2)	(1)	(1)
Proved Undeveloped	182	120	18	2,454	730	10	8	7
Total Proved	2,308	1,577	582	38,196	10,833	241	213	191
Total Probable	1,155	662	246	24,083	6,076	149	107	81
Total Proved &       Probable	3,463	2,239	828	62,279	16,909	390	319	272
United States Assets
Haas and MHA reports(1)
Proved Producing	975	0	0	46,250	8,684	204	169	145
Proved Non-Producing	29	0	0	2,661	472	9	8	7
Proved Undeveloped	127	0	0	8,245	1,501	35	27	18
Total Proved	1,131	0	0	57,156	10,658	248	204	170
Total Probable	303	0	0	14,344	2,694	72	55	44
Total Proved &    Probable	1,434	0	0	71,500	13,351	320	259	215
Consolidated Assets
Proved Producing	3,075	1,444	526	79,997	18,377	437	375	330
Proved Non-Producing	55	13	38	4,655	882	7	7	6
Proved Undeveloped	309	120	18	10,700	2,231	45	35	25
Total Proved	3,439	1,577	582	95,352	21,490	489	417	361
Total Probable	1,458	662	246	38,427	8,770	221	161	125
Total Proved &    Probable	4,897	2,239	828	133,779	30,260	710	578	487
(1) The Haas and MHA reports were converted to Canadian dollars by the Trust using an exchange rate of US$1.00 per Canadian dollar.

Enterra Energy Trust - Estimated Petroleum and Natural Gas Reserves and Net Present Value

Total excluding properties sold subsequent to year end

December 31, 2007 (NPV in millions)

	Light/					Net Present Value
	Medium	Heavy		Natural		Before Income Tax ($)
	Oil	Oil	NGL	Gas	Total
	(mbbl)	(mbbl)	(mbbl)	(mmcf)	(mboe)	0%	5%	10%
Canadian Assets
McDaniel report
Proved Producing	2,051	922	122	25,756	7,387	175	156	142
Proved Non-Producing	26	13	33	1,678	352	(2)	(1)	(1)
Proved Undeveloped	182	120	3	2,163	665	9	7	6
Total Proved	2,259	1,055	158	29,597	8,404	182	162	147
Total Probable	1,136	547	81	20,386	5,162	122	89	68
Total Proved &       Probable	3,395	1,602	239	49,983	13,567	304	251	215
United States Assets
Haas and MHA reports(1)
Proved Producing	975	0	0	46,250	8,684	204	169	145
Proved Non-Producing	29	0	0	2,661	472	9	8	7
Proved Undeveloped	127	0	0	8,245	1,502	35	27	18
Total Proved	1,131	0	0	57,156	10,658	248	204	170
Total Probable	303	0	0	14,344	2,694	72	55	44
Total Proved &    Probable	1,434	0	0	71,500	13,351	320	259	215
Consolidated Assets
Proved Producing	3,026	922	122	72,006	16,071	378	325	287
Proved Non-Producing	55	13	33	4,339	824	8	8	6
Proved Undeveloped	309	120	3	10,408	2,166	44	34	24
Total Proved	3,390	1,055	158	86,753	19,062	430	366	317
Total Probable	1,439	547	81	34,730	7,855	194	144	113
Total Proved &    Probable	4,829	1,602	239	121,483	26,917	624	510	430
(1) The Haas and MHA reports were converted to Canadian dollars by the Trust using an exchange rate of US$1.00 per Canadian dollar.

LIQUIDITY & CAPITAL RESOURCES

On December 18, 2007 the credit facilities were amended to extend the maturity date of these facilities to November 20, 2008.  The first-lien debt of $148.0 million is made up of a $129.5 million revolving facility and a $18.5 million operating facility.  The second-lien debt was $40.0 million as at December 31, 2007.   

Under the credit agreement, Enterra will reduce the indebtedness under the revolving and operating credit facilities from $148.0 million to $110.0 million by March 31, 2008 and the indebtedness under the second lien credit facility, which is currently at $29.1 million, to $28.0 million by June 30, 2008.  Enterra has also committed to extend the distribution suspension period for the duration of the facilities in order to advance its debt repayment strategy.  The agreement also restricts the convertible debenture interest payments for June 30, 2008 from being sourced from internally generated cash flow or with the proceeds of asset sales, but allows for the payment via alternative financings or via the trust unit interest payment election mechanism contained in the terms governing the convertible debentures.

Borrowings under the $129.5 million revolving facility and the $18.5 million operating facility bear interest at Canadian dollar BA or U.S. dollar LIBOR rates plus a margin of 2.00%, or Canadian or U.S. Prime rates plus a margin of 1.00% depending on the form of borrowing and the amount of debt outstanding relative to cash flow.  As at December 31, 2007 all borrowings under the facilities were denominated in Canadian dollars and interest was being accrued at a rate of 6.37% per annum.  At December 31, 2007, letters of credit totaling $0.5 million reduced the amount that can be drawn under the operating credit facility.

The $40.0 million second-lien facility is a non-revolving credit facility that matures on November 20, 2008 and is subordinated to the $129.5 million revolving facility and to the $18.5 million revolving operating facility.  The facility bears interest at Canadian dollar BA or U.S. dollar LIBOR rates plus a margin of 6.5%, or Canadian or U.S. prime rates plus a margin of 5.5% depending on the form of borrowing.  As at December 31, 2007 all borrowings under the second-lien facility were denominated in Canadian dollars and interest was being accrued at a rate of 11.75% per annum.

On April 26, 2007, the Trust issued $40.0 million of convertible debentures with a face value of $1,000 per convertible debenture that mature on June 30, 2012, bear interest at 8.25% per annum paid semi-annually on June 30 and December 31 of each year with the first payment occurring on December 31, 2007 and are subordinated to the bank credit facilities.  The convertible debentures are convertible at the option of the holder into trust units at any time prior to the maturity date at the conversion price of $6.80 per trust unit.  

At the option of the Trust, the repayment of the principal portion of the convertible debentures may be settled in trust units.  The number of trust units issued upon redemption by the Trust will be calculated by dividing the principal by 95% of the weighted average trading price of trust units.  The convertible debentures are not redeemable on or before June 30, 2010. On or after July 1, 2010 and prior to maturity, the convertible debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days notice, at a redemption price of $1,050 per convertible debenture on or after July 1, 2010 and, on or before June 30, 2011, at a redemption price of $1,025 per convertible debenture and on or after July 1, 2011 and prior to maturity, in each case, plus accrued and unpaid interest thereon, if any.

In addition to the convertible debentures, on April 26, 2007, the Trust issued $29.2 million of trust units (4,945,000 trust units).  

The net proceeds from the equity and convertible debenture issuances were used to finance the acquisition of Trigger Resources.  

Working Capital (in thousands)	Years Ended December 31,
	2007	2006
Working capital (deficiency)	$(177,369)	$(188,683)
Working capital (deficiency) excluding bank debt	$(5,416)	$(529)

CONTRACTUAL OBLIGATIONS

The following are contractual obligations and commitments over the next five years:

	Payments due by period (in thousands)
Contractual Obligations		Total	Less than 1 year	1- 3 years	3 – 5 years	More than 5 years
Debt obligations		$171,953	$171,280	$-	$-	$336
Interest on above debt (1)		13,532	13,441	-	-	91
Convertible debentures		120,331	-	-	120,331	-
Interest on convertible debentures (2)		40,006	9,726	19,453	10,827	-
Operating lease obligations		5,317	1,165	2,118	1,758	276
Other long-term liabilities		29,939	2,000	-	-	27,939
Total		$381,078	$197,612	$21,571	$132,916	$28,642

(1)

using the December 31, 2007 debt balances and interest rate of 8.0%

(2)

using the December 31, 2007 debenture balances and its interest rates ranging from 8.0% to 8.25%

RELATED PARTY TRANSACTIONS

During 2007 Enterra paid $0.7 million (2006 - $0.8 million) to Macon Resources Ltd. (“Macon”), a company 100% owned by the former Chief Executive Officer, for management services provided by the former Chief Executive Officer, and for a portion of 2006 a previous Chief Financial Officer.  At December 31, 2007 and 2006, nil was payable to Macon for management services.  During Q1 2007 50,000 restricted units (valued at $0.4 million based on the unit price of trust units on the grant date) were granted to Macon.  On February 28, 2007, these restricted units vested and were converted to 50,441 trust units.  The former Chief Executive Officer resigned as an officer and director on November 27, 2007 and February 20, 2008 respectively.  Of the $0.7 million payment to Macon is an agreed amount of $0.3 million related to the termination of the contract that otherwise would have run to June 1, 2008.  

During 2006 Enterra entered into a farm-out agreement with Petroflow Energy Ltd. (“Petroflow”), a public oil and gas company, to fund 100% of the drilling and completion costs of the Oklahoma Asset’s undeveloped lands.  The former Chief Executive Officer of the Trust and a current member of the board of directors own, directly and indirectly, approximately 16% and 2% of the outstanding shares of Petroflow respectively.  As at December 31, 2007, US$2.5 million of trade receivables and US$6.4 million of long-term receivables were due from Petroflow (of which US$2.3 million is due within one year and classified as current).  The long-term receivables are for infrastructure costs incurred that are to be repaid by Petroflow over a three-year period and is subject to interest of 12% per annum.  During 2007, US$0.4 million of interest income was earned on the long-term receivables from Petroflow (2006 – US$0.3 million).  In 2007, $1.1 million of principal payments have been received.  The balance at year end December 31, 2007 is US$6.4 million.  

On November 23, 2007, the Trust entered into a consulting agreement with Trigger Projects Ltd. for management services that would effectively be expected of the most senior manager of the Trust.  This contract has terms that require payment for services of $40,000 per month and a bonus of up to $0.5 million on termination.  The contract expires on May 31, 2008.  Payments of $50,000 were made to Trigger Projects Ltd. during 2007 and $nil was payable at December 31, 2007.

TRUST UNIT INFORMATION

The Trust is capitalized through a combination of trust units and exchangeable shares of certain of its subsidiaries.  The Trust also has a unit option plan, restricted unit plan, performance unit plan and warrants to purchase trust units outstanding.  The following table outlines outstanding equity instruments:

Outstanding unit data
As at	March 28, 2008	December 31, 2007	December 31, 2006
Trust units	61,435,895	61,435,895	56,097,875
Exchangeable shares
EEC exchangeable shares	-	-	16,337
RMG exchangeable shares	-	-	-
RMAC Series B exchangeable shares	-	-	66,720
Trust unit options	1,451,000	1,474,334	1,481,000
Restricted units	1,200,227	1,057,483	423,855
Performance units	293,469	454,171	212,948
Warrants	301,000	301,000	301,000
8.0% Convertible debentures ($1,000 per debenture)	$80,331	$80,331	$80,331
8.25% Convertible debentures ($1,000 per debenture)	$40,000	$40,000	$         -

SENSITIVITIES

Enterra is exposed to risks inherent within the oil and gas sector, including commodity price risk, foreign-currency exchange risk, interest rate risk and credit risk.  Management conducts its operations in a manner intended to minimize exposure to these risks as described in note 16 to the consolidated financial statements.

Credit Risk

Credit risk is the risk of loss resulting from non-performance of contractual obligations by a customer or joint venture partner.  A substantial portion of accounts receivable are with customers in the energy industry and are subject to normal industry credit risk.  Management assesses the financial strength of its customers and joint venture partners through regular credit reviews in order to reduce the risk of non-payment.

Foreign Exchange Risk

The Trust is exposed to market risk from changes in the exchange rate between U.S. and Canadian dollars.  For the Canadian operations, the price received 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.  However, operating, drilling and general overhead expenses are paid in Canadian dollars.  The U.S. operations receive revenue in U.S. dollars as well as pay the operating, drilling and general overhead expenses in U.S. dollars.  Monthly distributions are paid on a value expressed in U.S. dollars.  

Changes to the exchange rate between U.S. and Canadian dollars can adversely affect the Trust.  When the value of the U.S. dollar increases, the Trust receives higher revenue and when the value of the U.S. dollar declines, the Trust receives lower revenue on the same amount of production sold at the same prices.  A change of $0.01 in the U.S. to Canadian dollar would impact earnings by approximately $0.8 million and our cash provided by operating activities by $1.8 million.

Commodity Price Risk

The financial condition of Enterra, 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 fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Trust.  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, 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 the financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that the Trust can produce economically.  Any red uction in the oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on the ability to obtain capital for development activities.  Similarly, any improvements in oil and natural gas prices can have a favorable impact on the financial condition, results of operations and capital resources.  WTI oil price sensitivity is such that a change of US$1.00 per bbl would impact earnings by approximately $1.2 million and cash flow by approximately $1.8 million.  Natural gas sensitivity is such that a change of US$0.50 per mcf would impact earnings by approximately $6.1 million and impact cash-flow provided by operating activities by approximately $9.1 million.

Enterra uses financial derivatives and physical sales contracts to mitigate a portion of oil and natural gas commodity price risk.  While the use of these derivative arrangements limits the downside risk of price declines, such use may also limit any benefits that may be derived from commodity price increases.

Interest Rate Risk

Interest rate risk exists principally with respect to indebtedness that bears interest at floating rates.  At December 31, 2007, the Trust had $172.0 million of indebtedness bearing interest at floating rates.  If interest rates were to change by 1.0%, the net impact on earnings would be approximately $1.2 million and the net impact on cash-flow provided by operating activities would be approximately $1.7 million.

Summarized below are the sensitivities to various risks based on its 2007 operations:

Sensitivity	Estimated 2007 Impact On: (‘000s)
	Net Earnings	Cash Flow
Crude oil – US$1.00/bbl change in WTI	$1,233	$1,842
Natural gas – US$0.50/mcf change	6,086	9,092
Foreign exchange - $0.01 change in U.S. to Canadian dollar	817	1,757
Interest rate – 1.0% change	1,167	1,720

MANAGEMENT’S EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Trust is collected and communicated to the management, as appropriate, to allow timely decisions regarding required disclosure.  The Chairman of the Special Committee of the Board of Directors, acting as the Chief Executive Officer, and the Chief Financial Officer have concluded, based on their evaluation as of December 31, 2007, that as a result of the material weakness described below, disclosure controls and procedures were ineffective to provide reasonable assurance that material information is made known to them by others within the Trust.

Management’s Report on Internal Controls over Financial Reporting

A material weakness, as defined by SEC rules, is a control deficiency, or combination of control deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

Management of the Trust is responsible for designing internal controls over financial reporting or causing them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP, including note disclosure of the reconciliation to US GAAP.  Management has assessed the effectiveness of internal controls over financial reporting based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  During this process, a material weakness in internal control over financial reporting was identified as follows:  

The major turnover in key personnel including the Chief Executive Officer, Chief Financial Officer, Controller and Manager of Operations Accounting in Canada and the Chief Operating Officer and Operations Manager in the U.S. have impacted the ability of the Trust to achieve complete segregation of duties  and provide adequate management review.  Notwithstanding the material weakness, no adjustments to the financial statements were made Management determined that as a result of the deficiencies, which are pervasive in nature, there is a reasonable possibility that a material misstatement of the annual or interim financial statements would not be prevented or detected on a timely basis.

As a result of the existence of the material weakness discussed above, management has concluded that the Trust did not maintain effective internal control over financial reporting as of December 31, 2007, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.  

KPMG LLP, the registered public accounting firm that audited the financial statements has issued an attestation report on the internal controls of the Trust over financial reporting dated March 31, 2008. This report is adjacent to the financial statements on page 3 of the annual financial statements and notes.

CHANGES TO INTERNAL CONTROLS AND PROCEDURES FOR FINANCIAL REPORTING

During the year ended December 31, 2007 and subsequent thereto, the Trust had turnover in some of its key positions, notably the Chief Financial Officer and the Chief Executive Officer.  As a result of this turnover, the potential for control weaknesses was heightened. In many cases the individual control deficiencies which in aggregate resulted in the material weakness have already been addressed by new management in late 2007 and Q1 2008.  Senior management will continue to monitor the effectiveness of these controls and consult with external experts to assist management in their analysis.   

MANAGEMENT REMEDIATION PLANS

Senior management positions have been filled with individuals that have the necessary experience and knowledge to address the complexity of the Trust’s financial reporting requirements.  These individuals are addressing the individual control deficiencies which in aggregate resulted in the material weakness noted above.  Senior management is very confident that these deficiencies will be resolved in a timely manner now that there is stability in key positions within the organization.

CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2007, Enterra adopted new Canadian accounting standards and related amendments to other standards on financial instruments.  Prior periods have not been restated, except as discussed below.  As at January 1, 2007 the effects on the financial statements are:

Financial instruments – recognition and measurement

Effective January 1, 2007, the Trust's cash and cash equivalents and investments in marketable securities have been classified as held for trading and are recorded at fair value on the balance sheet. Fair values are determined directly by reference to published price quotations in an active market. Changes in the fair value of these instruments are recorded in net earnings.  All other financial instruments are recorded at cost or amortized cost, subject to impairment reviews. At December 31, 2007 there were no held to maturity or available for sale financial assets.  Enterra has not elected to record any financial instruments as held for trading.  

The Trust’s physical purchase and sale contracts have been designated as derivatives and are recorded at estimated fair value with changes in estimated fair value each period charged to earnings.  Embedded derivatives that do not meet certain exemptions are also required to be separately accounted for at fair value with changes in fair value included in earnings.  There are no significant embedded derivatives that required separate accounting as at December 31, 2007.  Transaction costs on the convertible debentures are presented net of the related debt and amortized to earnings using the effective interest method.

Comprehensive income

Comprehensive income includes net loss, holding gains and losses on available for sale investments, gains and losses on cash flow hedges and foreign currency gains and losses relating to self-sustaining foreign operations, all of which are not included in the calculation of earnings until realized.

When Enterra has not adopted a new accounting standard that has been issued but not yet effective, the entity is required to disclose (a) this fact; and (b) known or reasonably estimable information relevant to assessing the possible impact that application of the new standard will have on the Trust’s financial statements in the period of initial application.  

Capital disclosures

New Canadian accounting recommendations for capital disclosures have been issued which will require additional disclosure of both qualitative and quantitative information about objectives, policies and processes for managing capital.  These recommendations are effective for year-ends beginning January 1, 2008.

International Financial Reporting Standards

In February 2008, the Canadian Institute of Chartered Accountants confirmed that Canadian GAAP for publicly accountable enterprises will be converted to International Financial Reporting Standards (IFRS) on January 1, 2011.  This change in GAAP will be effective for years beginning January 1, 2011.

In December 2007, the SEC announced that the U.S. GAAP reconciliations requirement will be waived for Foreign Private Issuers who file financial statements prepared in accordance with IFRS for years beginning on or after January 1, 2009.

CRITICAL ACCOUNTING ESTIMATES

The Trust continues to evolve and document its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.  Financial and operating results incorporate certain estimates including:

a)

estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;

b)

estimated capital expenditures on projects that are in progress;

c)

estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves, which the Trust expects to recover in the future;

d)

estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures;

e)

estimated future recoverable value of property, plant and equipment and goodwill; and

f)

estimated fair value of derivatives and investments.

ADDITIONAL INFORMATION

Additional information relating to Enterra Energy Trust can be found on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, as well as on the website at www.enterraenergy.com.

ABBREVIATIONS
AECO	Natural gas reference price in Alberta
bbl	barrel of oil
bbls/day	barrels of oil per day
boe	barrels of oil equivalent
	(6 mcf equivalent to 1 bbl)
boe/day	barrels of oil equivalent per day
Cdn$	Canadian dollars
GAAP	Canadian Generally Accepted Accounting Principles
GJ	Gigajoule
mbbl	thousand barrels of oil
mboe	thousands of barrels of oil equivalent
mcf	thousand cubic feet of natural gas
mcf/day	thousands of cubic feet of natural gas per day
mmbtu	millions of British Thermal Units
mmbtu/day	millions of British Thermal Units per day
mmcf	millions of cubic feet of natural gas
Mwh	megawatt-hour
NGL	natural gas liquids
NYMEX	New York Mercantile Exchange
Q1	first quarter of the year - January 1 to March 31
Q2	second quarter of the year - April 1 to June 30
Q3	third quarter of the year - July 1 to September 30
Q4	fourth quarter of the year - October 1 to December 31
US$	United States dollars
WTI	West Texas Intermediate (oil reference price)

EX-99.3

MANAGEMENT’S REPORT

The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. The accompanying consolidated financial statements of Enterra Energy Trust and all of the information included in this report are the responsibility of management.

Management is responsible for establishing and maintaining adequate internal controls designed to provide reasonable assurance regarding the reliability of our financial reporting and preparation of our financial statements for external purposes in accordance with accounting principles generally accepted in Canada and reconciling to accounting principles generally accepted in the U.S. for note disclosure purposes. Our internal control over financial reporting includes those policies and procedures that pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions; and that provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles.  Management has assessed the effectiveness of internal controls over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring  Organizations of the Treadway Commission (COSO).   As a result of the existence of the material weakness as discussed in management’s discussion and analysis, management has concluded that  internal controls over financial reporting were not effective as of December 31, 2007.   

Because of inherent limitations, internal controls over financial reporting may not prevent or detect material misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.  

The Board is responsible for ensuring that management fulfills its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the financial statements. The Board carries out this responsibility principally through its Audit Committee. The Audit Committee of the Board meets periodically with management and the auditors to satisfy itself that management’s responsibilities are properly discharged, to review the financial statements and reports its finding to the Board before the financial statements are approved by the Board.

Signed “Peter Carpenter”

Signed “Blaine Boerchers”

Chairman

Chief Financial Officer

March 31, 2008

March 31, 2008

Page 1 of 43

AUDITORS’ REPORT

To the Unitholders of Enterra Energy Trust

We have audited the consolidated balance sheets of Enterra Energy Trust ("the Trust") as at December 31, 2007 and 2006 and the consolidated statements of loss and comprehensive loss, deficit and cash flow for the years then ended. These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards.  With respect to the consolidated financial statements for the year ended December 31, 2007, we also conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 31, 2008 expressed an adverse opinion on the effectiveness of the Trust’s internal control over financial reporting.

Chartered Accountants

Calgary, Canada

March 31, 2008

Page 2 of 43

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Enterra Energy Corp., as Administrator of Enterra Energy Trust and the Unitholders of Enterra Energy Trust

We have audited Enterra Energy Trust’s ("the Trust") internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Trust’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely de tection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the entity’s annual or interim financial statements will not be prevented or detected on a timely basis. A material weakness related to the lack of segregation of duties and inadequate management review has been identified and included in management’s assessment. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Trust as at and for the year ended December 31, 2007. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2007 consolidated financial statements, and this report does not affect our report dated March 31, 2008, which expressed an unqualified opinion on those consolidated financi al statements.

In our opinion, because of the effect of the aforementioned material weakness on the achievement of the objectives of the control criteria, the Trust has not maintained effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Chartered Accountants

Calgary, Canada

March 31, 2008

Page 3 of 43

ENTERRA ENERGY TRUST
CONSOLIDATED BALANCE SHEETS
(Thousands of Canadian dollars)
As at	December 31	2007	2006
Assets
Current assets
	Cash and cash equivalents	$                        3,554	$                    2,162
	Accounts receivable	30,391	38,980
	Prepaid expenses, deposits and other	2,270	3,249
	Financial instruments (note 16)	607	10,775
		36,822	55,166
Property, plant and equipment (note 6)		556,778	659,268
Long term receivables (note 21)		4,003	-
Deferred financing charges		-	4,676
Goodwill (note 7)		-	76,256
		$                    597,603	$                795,366
Liabilities
Current liabilities
	Bank indebtedness (note 8)	$                    171,953	$                188,154
	Accounts payable and accrued liabilities	35,763	46,083
	Distribution payable to unitholders	-	7,910
	Financial instruments (note 16)	5,764	-
	Note payable and capital lease (note 9)	711	1,702
		214,191	243,849
Convertible debentures (note 11)		111,692	78,974
Asset retirement obligations (note 10)		29,939	28,447
Future income tax liability (note 15)		22,597	40,340
		378,419	391,610
Non-controlling interest (note 12)		-	1,732
Unitholders’ Equity (note 13)
	Unitholders’ capital	667,690	635,134
	Equity component of convertible debentures (note 11)	3,977	1,327
	Warrants	1,215	1,215
	Contributed surplus	4,660	3,195
	Accumulated other comprehensive (loss) income (note 14)	(44,978)	1,930
	Deficit	(413,380)	(240,777)
		219,184	402,024
		$                   597,603	$               795,366
Commitments and contingencies (notes 18 and 19)
Subsequent events (notes 8, 9, and 22)
See accompanying notes to consolidated financial statements.

Approved on behalf of the Board:

(signed “Peter Carpenter”)

(signed “Roger Giovanetto”)

Director

Director

Page 4 of 43

ENTERRA ENERGY TRUST
CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS
(Thousands of Canadian dollars, except per trust unit amounts)
	For year ended December 31	2007	2006
Revenues
	Oil and natural gas	$                     207,036	$         244,408
	Royalties	(45,365)	(48,288)
		161,671	196,120
Expenses
	Operating	64,823	50,361
	General and administrative	24,542	20,374
	Interest on bank indebtedness	12,619	25,898
	Interest on convertible debentures	9,963	819
	Financing fees	-	5,447
	Amortization of deferred financing charges	-	11,713
	Depletion, depreciation and accretion (note 6)	150,701	201,448
	Goodwill impairment (note 7)	76,463	-
	Foreign exchange loss	546	1,910
		339,657	317,970
Loss before taxes and non-controlling interest		(177,986)	(121,850)
Income taxes (note 15)
	Current	101	1,324
	Future reduction	(36,051)	(58,899)
		(35,950)	(57,575)
Loss before non-controlling interest		(142,036)	(64,275)
Non-controlling interest (note 12)		-	(36)
Net loss		(142,036)	(64,239)
Other comprehensive loss
	Foreign currency translation adjustment (note 14)	(46,908)	1,930
Comprehensive loss		(188,944)	(62,309)
Loss per trust unit (note 13) – basic and diluted		$                        (2.38)	$          (1.46)
CONSOLIDATED STATEMENTS OF DEFICIT
	Deficit, beginning of year	$                  (240,777)	$      (85,840)
	Change in accounting policy (note 3)	1,009	-
	Net loss	(142,036)	(64,239)
	Distributions declared	(31,576)	(90,698)
	Deficit, end of year	$                  (413,380)	(240,777)

Page 5 of 43

ENTERRA ENERGY TRUST
CONSOLIDATED STATEMENTS OF CASH FLOW
(Expressed in thousand Canadian dollars)
	For year ended December 31	2007	2006
Cash provided by (used in):
Operating
	Net loss	$                   (142,036)	$                     (64,239)
	Depletion, depreciation and accretion	150,701	201,448
	Goodwill impairment	76,463	-
	Future income tax reduction	(36,051)	(58,899)
	Amortization of deferred financing charges	988	11,713
	Financial derivatives	16,205	(10,628)
	Financing fees	-	5,065
	Amortization of marketing contract	-	(1,447)
	Non-controlling interest	-	(36)
	Foreign exchange	951	1,038
	Unit-based compensation	4,128	3,229
	Loss on sale of assets	-	59
	Cash paid on asset retirement obligations	(2,225)	(1,219)
	Non-cash interest expense	1,338	33
	Changes in non-cash working capital items (note 17)	6,381	(21,632)
		76,844	64,485
Financing
	Distributions paid	(39,486)	(90,487)
	Increase in bank indebtedness (note 8)	-	587,818
	Issuance of convertible debentures	37,514	138,000
	Repayment of bank indebtedness (note 8)	(15,495)	(510,353)
	Proceeds from (repayment of) notes, net	878	(3,990)
	Capital lease	(1,702)	(878)
	Financing fees	-	(22,405)
	Due to JED Oil Inc.	-	(2,009)
	Issue of trust units, net of issue costs (note 13)	27,438	50,391
	Exercise of trust unit options (note 13)	-	1,399
		9,147	147,486
Investing
	Property, plant and equipment additions	(31,790)	(30,918)
	Proceeds on disposal of property, plant and equipment	11,349	6,586
	Acquisition of Trigger Resources (note 5)	(63,257)	-
	Acquisition of Oklahoma Assets	-	(182,183)
	Long-term receivable	1,105	-
	Changes in non-cash working capital items (note 17)	(1,778)	(7,645)
		(84,371)	(214,160)
Foreign exchange on financial balances		(228)	(7,592)
Change in cash and cash equivalents		1,392	(9,781)
Cash and cash equivalents, beginning of year		2,162	11,943
Cash and cash equivalents, end of year		$                    3,554	$                    2,162
	See accompanying notes to consolidated financial statements.

Page 6 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

1.

Basis of presentation

Enterra Energy Trust (the “Trust”) was established in November 2003 pursuant to the Plan of Arrangement.  The Trust is an open-end unincorporated investment trust governed by the laws of the province of Alberta and created pursuant to a trust indenture (the “Trust Indenture”).  The purpose of the Trust is to indirectly hold interests in petroleum and natural gas properties, through notes from, and investments in securities of its subsidiaries.  The beneficiaries of the Trust are the holders of trust units issued by the Trust (the “unitholders”).  

These consolidated financial statements include the accounts of the Trust and its subsidiaries (collectively the “Trust” or “Enterra” for purposes of the following notes to the consolidated financial statements).  All inter-company accounts and transactions have been eliminated.

2.

Going concern

These consolidated financial statements have been prepared on a going concern basis in accordance with Canadian generally accepted accounting standards.  The going concern basis of presentation assumes that the Trust will continue its operations for the foreseeable future and be able to realize its assets and discharge its liabilities and commitments in the normal course of business.  

The debt agreements of the Trust currently require that borrowings under the second-lien facility, which is currently at $29.1 million, (see note 8) be reduced to $28.0 million by June 30, 2008.  Furthermore, the Trust must make interest payments on its convertible debentures (see note 11) of approximately $4.9 million on June 30, 2008.  Per the relevant agreements, the Trust cannot use cash flow from operations to fund the required debt and interest repayments.  Therefore, the Trust must use proceeds from asset dispositions or the issuance of new equity or new borrowings to make the required payments.  If the Trust is not able to meet these commitments by June 30, 2008 then the going concern assumption may not be appropriate and adjustments to the carrying values of assets and liabilities, the reported revenue and expenses, and the balance sheet classifications used may be necessary.  

3.     Significant Accounting Policies

Management has prepared the consolidated financial statements in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). The following significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements, and together with the following notes, should be considered an integral part of the consolidated financial statements.

(a)

Basis of accounting

Substantially all exploration, development and production activities related to the oil and gas business are conducted jointly with others and the accounts reflect only the Enterra proportionate interest.

(b)

Cash and cash equivalents

Cash and cash equivalents consists of cash on hand and balances invested in short-term securities with original maturities less than 90 days at the date of acquisition.

Page 7 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

(c)

Revenue recognition

Revenue associated with the sale of crude oil, natural gas and natural gas liquids is recognized when title passes from the Trust to its customers based on contracts which establish the price of products sold and when collection is reasonably assured.

(d)

Petroleum and natural gas properties

Enterra follows the “full cost” method of accounting for petroleum and natural gas properties. All costs related to the exploration for and the development of oil and gas reserves are capitalized into one of two cost centers, Canada or the United States.  Costs capitalized include land acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling productive and non-productive wells and production equipment.

General and administrative costs are capitalized if they are directly related to development or exploration projects.

Proceeds from the disposal of oil and natural gas properties are applied as a reduction of cost without recognition of a gain or loss except where such disposals would result in a 20% change in the depletion rate.

Repair and maintenance costs are expensed as incurred.

(e)

Impairment test

The Trust places a limit on the carrying value of property and equipment, which may be depleted against revenues of future periods (the “ceiling test”). The ceiling test is conducted separately for each cost center, Canada and the United States.  The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying value of the cost center. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of petroleum and natural gas properties exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. The cash flows are estimated using expected futur e product prices and costs and are discounted using a risk-free interest rate. The carrying value of property and equipment subject to the ceiling test includes asset retirement costs.

(f)

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenue and expenses during the reporting periods.

The amounts recorded for depletion, depreciation and the asset retirement obligation are based on estimates. The ceiling test calculation is based on estimates of reserves, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods.

The amounts recorded for financial derivatives are based on estimates of the price for oil and natural gas in future periods.  These estimates are subject to fluctuations in market prices and will impact the consolidated financial statements of future periods.

(g)

Depletion and depreciation

The provision for depletion of petroleum and natural gas properties is calculated, by cost center, using the unit-of-production method based on the Enterra’s share of estimated proved reserves before royalties. Natural gas reserves and production are converted to equivalent units of crude oil using their approximate relative energy content.

Office furniture and equipment is depreciated on a 20% declining balance basis.

(h)

Goodwill

Enterra recognizes goodwill relating to acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities acquired. The goodwill balance is assessed for impairment annually at year-end or as events occur that could result in an impairment. To assess impairment, the estimated fair value of a reporting unit is compared to its book value. If the fair value is less than the book value, a second test is performed to determine the amount of impairment. The amount of impairment is measured by allocating the estimated fair value to a reporting unit’s identifiable assets and liabilities as if it had been acquired in a business combination for a purchase price equal to its estimated fair market value. If goodwill determined in this manner is less than the carrying value of goodwill, an impairment loss is recognized in the period in which it occurs. Goodwill is stated at cost less impairment.  Goodwill is tes ted for impairment separately for the Canadian and the United States reporting units.

(i)

Asset retirement obligations

Enterra recognizes a liability for the estimated fair value of the future retirement obligations associated with property and equipment. The fair value of the estimated asset retirement obligations is recorded as a liability with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit-of-production method based on proved reserves. The Trust estimates the liability based on the estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. This estimate is evaluated on a periodic basis and any adjustment to the estimate is prospectively applied. As time passes, the change in net present value of the future retirement obligation is expensed through accretion. Retirement obligations settled during the period reduce the future retirement liability.

(j)

Income taxes

Enterra follows the asset and liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized based on the differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.  Future tax assets are recognized to the extent they are more likely than not to be realized.

Enterra is a taxable entity under the Canadian Income Tax Act and is currently taxable only on income that is not distributed or distributable to the unitholders.  In 2007, changes to Canadian tax legislation resulted in a new tax on distributions from publicly traded income trusts commencing in 2011.  This has resulted in the recognition of future income taxes at the trust level.  Prior to 2007, future income taxes were recognized only on the corporate subsidiaries of the Trust.      

Page 8 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

(k)

Non-controlling interest

Enterra had, through its subsidiaries four types of exchangeable shares that are classified as non-controlling interest on the consolidated balance sheets.  Income after tax attributable to these exchangeable shares is deducted from net earnings of Enterra on the consolidated statement of loss.

When the Enterra Energy Corp. exchangeable shares are exchanged for trust units, they are measured at the fair value of the trust units issued.  The amounts in excess of the carrying value of exchangeable shares are allocated to property, plant and equipment, to the extent possible, with any excess amounts being allocated to goodwill.  When the other exchangeable shares, which were initially recorded at estimated fair value, are exchanged for trust units, they are measured at their carrying value.    

(l)

Financial instruments

Enterra uses derivative financial instruments such as collars and swaps to manage its exposure to commodity price fluctuations. Actual amounts received, or paid, on the settlement of the derivative financial instruments are recorded in oil and gas revenue.  Enterra uses the fair value method for reporting derivative financial instruments whereby a derivative financial instrument is recorded as an asset or a liability on the balance sheet, and changes in the fair value during a financial period are recorded in oil and natural gas revenue.

(m)

Trust unit compensation plans

Enterra has multiple unit based compensation plans, which are described in note 13. Compensation expense associated with each unit based compensation plan is recognized in earnings over the vesting period of the plan with a corresponding increase in contributed surplus.  Any consideration received upon the exercise of the unit based compensation together with the amount of non-cash compensation expense recognized in contributed surplus is recorded as an increase in unitholders’ capital. Compensation expense is based on the fair value of the unit based compensation at the date of grant.

(n)

Deferred financing charges

Prior to January 1, 2007, deferred financing charges were amortized over the lives of the related debt.  Subsequent to January 1, 2007 transactions costs are recorded net of the related financing and amortized using the effective interest method.

(o)

Foreign currency transactions

Transactions completed in U.S. dollars are reflected in Canadian dollars at the exchange rates prevailing at the time of the transactions.  Current assets and liabilities denominated in U.S. dollars are reflected in the financial statements at the Canadian equivalent at the rate of exchange prevailing at the balance sheet date.  Translation gains and losses are included in earnings.

The U.S. subsidiaries of Enterra are considered to be "self sustaining operations".  As a result, the revenues and expenses are translated to Canadian dollars using average exchange rates for the period.  Assets and liabilities are translated at the period-end exchange rate.  Gains or losses resulting from the translation are included in accumulated other comprehensive income (loss) in unitholders’ equity.

Page 9 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

(p)

Per unit amounts

Per unit amounts are calculated using the weighted average number of units outstanding. The Trust follows the treasury stock method to determine dilutive effect of options, warrants and other dilutive instruments. Under the treasury stock method, only “in-the-money” dilutive instruments impact the diluted calculations.  Exchangeable shares are included in the calculation of diluted earnings per unit based on the number of trust units that would be issued on conversion of the exchangeable shares at the end of the year as long as the conversion is anti-dilutive.  Convertible debentures are included in the calculation of diluted earnings per unit based on the number of trust units that would be issued on conversion of the convertible debentures at the end of the year and an add-back of the associated interest expense for the year as long as the conversion results in a dilution to the Trust.  

(q)

Comparative figures

Certain comparative figures have been reclassified to conform with the presentation adopted in the current year.

4.

Adoption of New Accounting Standards

Effective January 1, 2007, Enterra adopted new Canadian accounting standards and related amendments to other standards on financial instruments.  Prior periods have not been restated, except as discussed in below.  As at January 1, 2007 the effects on the financial statements are:

i.

Financial instruments – recognition and measurement

Effective January 1, 2007, the Trust's cash and cash equivalents, investments in marketable securities and commodity contracts have been classified as held for trading and are recorded at fair value on the balance sheet. Fair values are determined directly by reference to published price quotations in an active market. Changes in the fair value of these instruments are recorded in net earnings.  All other financial instruments are recorded at cost or amortized cost, subject to impairment reviews. At December 31, 2007 there were no held to maturity or available for sale financial assets.  Enterra has not voluntarily elected to record any financial instruments as held for trading.  

The Trust’s physical purchase and sale contracts have been designated as derivatives and are recorded at estimated fair value with changes in estimated fair value each period charged to earnings.

Embedded derivatives that do not meet certain exemptions are also required to be separately accounted for at fair value with changes in fair value included in earnings.  Enterra elected January 1, 2007 as the effective date for assessing embedded derivatives.  There are no significant embedded derivatives that required separate accounting as at January 1, 2007.

Transaction costs on the convertible debentures are presented net of the related debt and amortized to earnings using the effective interest method.

ii.

Comprehensive income

Comprehensive income includes net loss, holding gains and losses on available for sale investments, gains and losses on cash flow hedges and foreign currency gains and losses relating to self-sustaining foreign operations, all of which are not included in the calculation of earnings until realized.

Page 10 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

The impact of adopting these standards at January 1, 2007 is as follows:

	As reported	Adjustments		As adjusted
Assets:
Current assets	$      55,166	$          2,637	(a)(b)	$      57,803
Deferred finance charges	4,676	(4,676)	(b)	-
Liabilities:
Convertible debentures	78,974	(3,481)	(b)	75,493
Future income tax	40,340	432	(a)	40,772
Unitholder's Equity
Cumulative translation adjustment	1,930	(1,930)	(c)	-
Deficit	(240,777)	1,009	(a)	(239,768)
Accumulated other comprehensive income	-	1,930	(c)	1,930

Notes:

(a) Physical purchase and sale contracts have been designated as derivatives and are measured at their estimated fair value of $1.4 million with the offset, as required on adoption of the new standards, included in retained earnings ($1.0 million net of income taxes).

(b) Convertible debenture financing costs of $3.5 million, previously classified as deferred financing charges, are reclassified to convertible debentures.  Financing fees of $1.2 million have been reclassified to prepaid expenses and are amortized over the term of the related credit facilities.

(c) The cumulative translation adjustment is reclassified to accumulated other comprehensive income.  The cumulative translation adjustment as at December 31, 2006 was reclassified to accumulated other comprehensive income as required by the new standards.

When Enterra has not adopted a new accounting standard that has been issued but not yet effective, the entity is required to disclose (a) this fact; and (b) known or reasonably estimable information relevant to assessing the possible impact that application of the new standard will have on the Trust’s financial statements in the period of initial application.  

New Canadian accounting recommendations for capital disclosures have been issued which will require additional disclosure of both qualitative and quantitative information about objectives, policies and processes for managing capital.  These recommendations are effective for year-ends beginning January 1, 2008.

In February 2008, the Canadian Institute of Chartered Accountants confirmed that Canadian GAAP for publicly accountable enterprises will be converted to International Financial Reporting Standards (IFRS) on January 1, 2011.  This change in GAAP will be effective for years beginning January 1, 2011.

In December 2007, the SEC announced that the U.S. GAAP reconciliations requirement will be waived for Foreign Private Issuers who file financial statements prepared in accordance with IFRS for years beginning on or after January 1, 2009.

Page 11 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

5.

Acquisitions

Acquisition of Trigger Resources

On April 30, 2007 Enterra acquired all of the issued and outstanding shares of Trigger Resources Ltd. (“Trigger Resources”).  The results of the operations of Trigger Resources are included in the consolidated financial statements of Enterra as of April 30, 2007.

Trigger Resources was a private company with operations in heavy oil and gas exploration and development in western Saskatchewan.  The acquisition increased the Trust’s operations in the region and provides additional reserves, production and cash flow.  The acquisition also provides the Trust with additional net undeveloped acreage with drilling and development potential.  

The acquisition was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration paid as follows:

Allocation of purchase price:
Current assets	$             2,806
Property, plant and equipment	81,382
Current liabilities	(2,781)
Future income tax liability	(15,576)
Asset retirement obligations	(2,574)
	$           63,257

Consideration:
Cash	$         62,965
Transaction costs	292
	$         63,257

Acquisition of Oklahoma Assets

During 2006, Enterra acquired oil and natural gas properties located in Oklahoma (“Oklahoma Assets”).  The acquisition was completed in four stages.

Prior to closing the acquisitions, the Trust acquired $49.7 million of notes payable by the primary vendors of the Oklahoma Assets; as a result the vendors owed the Trust $49.7 million.  The primary vendors repaid the Trust $38.5 million of the notes upon closing the second stage of the acquisition of the Oklahoma Assets.  The acquisition of the notes, by the Trust, was financed with a US$50.0 million senior bridge credit facility.

On January 18, 2006, the Trust closed the first stage of the acquisition of the Oklahoma Assets.  The results of the operations of the assets acquired are included in the Trust’s consolidated financial statements as of January 18, 2006.

On March 21, 2006, the Trust closed the second stage of the acquisition of the Oklahoma Assets.  Along with the second stage, the Trust acquired the operating company of the Oklahoma Assets.  The results of operations of the assets acquired and the operating company are included in the Trust’s consolidated financial statements as of March 21, 2006.

Page 12 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

On April 4, 2006, the Trust closed the third stage of the acquisition of the Oklahoma Assets.  The results of operations of the assets acquired are included in the Trust’s consolidated financial statements as of April 4, 2006.

On April 18, 2006, the Trust closed the fourth stage of the acquisition of the Oklahoma Assets.  The results of operations of the assets acquired are included in the Trust’s consolidated financial statements as of April 18, 2006.

The acquisition was accounted for using the purchase method of accounting with the allocation of the purchase price and consideration paid as follows:

Allocation of purchase price:
Current assets	$             6,412
Property, plant and equipment	352,999
Current liabilities	(25,355)
Financial derivatives	(485)
Debt	(24,036)
Asset retirement obligations	(1,926)
	$         307,609

Cost of acquisitions:
Cash paid and payable	$         181,044
Transaction costs	10,040
5,685,028 trust units	116,525
	$         307,609

The value assigned to each trust unit of $20.51 (US$17.70) was based on the weighted average trading price immediately prior to the measurement date.  The acquisition provides cash flows from currently producing assets and provides the opportunity for the exploitation of the undeveloped lands.  

As a result of adjustments to the purchase price, as determined by the purchase and sale agreement, Enterra owes $1.4 million (US$1.5 million) to the vendors as at December 31, 2007 ($8.9 million (US$7.6 million) in 2006).

Page 13 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

6.

Property, plant and equipment

			2007
		Accumulated
		depletion and
	Cost	depreciation	Net
Petroleum and natural gas properties	$1,064,536	$510,798	$553,738
Office furniture and equipment	5,355	2,315	3,040
	$1,069,891	$513,113	$556,778
			2006
		Accumulated
		depletion and
	Cost	depreciation	Net
Petroleum and natural gas properties	$1,011,399	$355,304	$656,095
Office furniture and equipment	5,118	1,945	3,173
	$1,016,517	$357,249	$659,268

During 2007 $1.1 million of general and administrative expenses were capitalized and included in the cost of the petroleum and natural gas properties (2006 - $nil).

At December 31, 2007 costs of undeveloped land and seismic of $18.6 million (2006 - $25.9 million) were excluded from and $11.8 million (2006 - $8.0 million) of future development costs were added to the Canadian cost centre for purposes of the calculation of depletion expense.  At December 31, 2007 costs of undeveloped land of $nil (2006 – $16.8 million) were excluded from and $3.0 million (2006 - $3.0 million) of future development costs were added to the U.S. cost centre for purposes of the calculation of depletion expense.  

Depletion and depreciation expense related to the Canadian and the U.S. cost centers in 2007 were $77.7 million and $44.5 million respectively (2006 – $90.7 million and $42.6 million).  

The following table summarizes the benchmark prices used in the ceiling test calculation. The petroleum and natural gas prices are based on the December 31, 2007 commodity price forecast of our independent reserve engineers.

Page 14 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

Year	WTI Oil ($U.S./bbl)	Foreign Exchange Rate	Edmonton Light Crude Oil ($Cdn/bbl)	AECO Gas ($Cdn/GJ)	Henry Hub ($U.S./Mmbtu)
2008	90.00	1.000	89.00	6.45	7.75
2009	86.70	1.000	85.70	7.00	8.40
2010	83.20	1.000	82.20	7.00	8.40
2011	79.60	1.000	78.50	7.00	8.40
2012	78.50	1.000	77.40	7.10	8.55
2013	77.30	1.000	76.20	7.30	8.75
Escalate Thereafter	Average 2% per year	1.000	Average 2% per year	Average 2% per year	Average 2% per year

Enterra completed ceiling test calculations for the Canadian and U.S. cost centers at December 31, 2007 to assess the recoverability of costs recorded in respect of the petroleum and natural gas properties.  The ceiling test resulted in a write down of $26.3 million in the Canadian cost center and nil in the U.S. cost center (2006 - $48.8 million write down in the Canadian cost center and $17.2 million write down in the U.S. cost center).  The ceiling test write down has been included in depletion expense.   

7.

Goodwill

During 2007 Enterra recorded a goodwill impairment loss of $76.5 million relating to the Canadian reporting unit.

8.

Debt

	2007	2006
Revolving credit facility	$       129,500	$         180,000
Operating credit facility	2,116	7,695
Second-lien facility	40,000	-
Other	337	459
Bank indebtedness	$       171,953	$        188,154

In February 2007 the $180.0 million revolving extendible credit facility was amended to a $140.0 million revolving credit facility with the same terms as the $180.0 million revolving facility and a $40.0 million second-lien non-revolving credit facility.  

The credit facilities were further amended subsequent to December 31, 2007 such that Enterra has available a $129.5 million revolving extendible facility, a $18.5 million operating facility and a $40.0 million second-lien non-revolving facility.  The maturity date of each of these credit facilities was extended to November 20, 2008.  

Borrowings under the $129.5 million revolving facility and the $18.5 million operating facility bear interest at Canadian dollar bankers’ acceptance (“BA”) or U.S. dollar LIBOR rates plus a margin of 2%, or Canadian or U.S. prime rates plus a margin of 1% depending on the form of borrowing.  As at December 31, 2007 all borrowings under the facilities were denominated in Canadian dollars and interest was being accrued at a rate of 6.37% per annum.  At December 31, 2007, letters of credit totaling $0.5 million reduced the amount that can be drawn under the operating credit facility.

Page 15 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

The $40.0 million second-lien facility is subordinated to the $129.5 million revolving facility and to the $18.5 million revolving operating facility.  The facility bears interest at Canadian dollar BA or U.S. dollar LIBOR rates plus a margin of 6.5%, or Canadian or U.S. prime rates plus a margin of 5.5% depending on the form of borrowing.  As at December 31, 2007 all borrowings under the second-lien facility were denominated in Canadian dollars and interest was being accrued at a rate of 11.75% per annum.

Under the credit agreement, Enterra is required to reduce the indebtedness under the revolving and operating credit facilities from $148.0 million to $110.0 million by March 31, 2008.  Enterra is also required to make quarterly payments of $3.0 million commencing at the end of June, 2008 to further reduce the amounts drawn on the revolving and operating facilities.  The quarterly payments on these facilities permanently reduce the amounts that can be drawn on the facilities.  Subsequent to December 31, 2007 proceeds from asset dispositions and cash flow from operations were used to reduce the indebtedness under the revolving and operating credit facilities to less than $110.0 million.

In addition, Enterra is required to reduce the indebtedness under the second lien facility, which is currently at $29.1 million, to $28.0 million by June 30, 2008.  Enterra is not permitted to use cash flow from operations to fund the required debt payments.  Certain proceeds from asset dispositions or proceeds from the issuance of new equity can be used to finance the required debt payments.  

Enterra is required to maintain an interest coverage ratio of 3.0:1.0 as calculated pursuant to the terms of the credit agreement.  The Trust is in compliance with this covenant as at December 31, 2007.   

Enterra has also committed to extend the distribution suspension period for the duration of the facilities in order to advance its debt repayment strategy.  The credit agreement also restricts the convertible debenture interest payments for June 30, 2008 from being sourced from internally generated cash flow or with the proceeds of asset sales, but allows for the payment through alternative financings or through the trust unit interest payment election mechanism contained in the terms governing the convertible debentures.

The lenders are currently conducting a borrowing base review based on the 2008 reserve report.  Management does not anticipate that the amounts available under the revolving and operating facility will be reduced as a result of the lenders review of the borrowing base.

On November 21, 2006, the Trust closed a $180.0 million revolving extendible credit facility and a $20.0 million revolving extendible operating credit facility.  As at December 31, 2006, the Trust had $187.7 million of borrowings (of which $77.1 million was denominated in U.S. dollars) and $0.2 million of letters of credit drawn on the facilities.  The $180.0 million and $20.0 million facilities were 364 day extendible facilities that are secured with a first priority charge over the Trust’s assets.  Borrowings under these facilities bore interest at BA rates, Canadian or US prime rates, or LIBOR plus applicable margins ranging from nil to 1.65% depending on the form of borrowing and the Trust’s debt to cash flow ratio. At December 31, 2006 the margin was 0.25% on prime rate borrowings and 1.4% on banker’s acceptance rates or LIBOR borrowing.  Should the lenders decline to extend the facilities at the end of the 364 day period, the facilities convert into one year term loans.  

In March 2006, the Trust closed a $110.0 million senior secured bridge facility.  This reducing non-revolving credit facility was used to repay the existing $100.0 million credit facilities of the Trust.  The facility bore interest at 2.5% above bank prime lending rates.  $2.0 million of the facility was repaid on June 30, 2006 with the remaining $108.0 million repaid on November 21, 2006.  The facility was secured by a first charge over all Canadian assets of the Trust and a second charge over all US assets.  

In March 2006, the Trust closed a US$200.0 million senior secured bridge credit facility to fund the acquisition of the Oklahoma Assets.  The facility bore interest at 4.5% above LIBOR.  The facility was repaid on November 21, 2006.

Page 16 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

Other credit facilities

·

A building mortgage, secured by the building that bears interest at 7% per annum.  The facility matures on July 1, 2020.  The loan balance was US$0.3 million (2006 - US$0.3 million) as at December 31, 2007.

·

A promissory note, used to acquire, and secured by, equipment owned by Enterra.  The note matures on February 20, 2009 and bears interest at US prime plus 1%.  At December 31, 2007 and 2006, the balance of the note was $0.1 million.

9.

Note payable and capital lease

Note payable

Enterra has a $0.7 million (US$0.7 million) (2006 - $nil) note payable for the purchase of certain natural gas interests in the U.S.  The note is secured by certain specified assets and bears interest at 10.0%.  The note was repaid subsequent to December 31, 2007.

Capital lease

The capital lease bore a rate of interest of 8.6% and was repayable in monthly installments of at $0.1 million, including interest with a final payment of $1.0 million.  The lease term was for 60 months ending on October 1, 2007.    Interest expense on the lease in 2007 was $0.2 million (2006 - $0.2 million).

10.

Asset retirement obligations

The asset retirement obligations were estimated by management based on the Enterra’s working interests in its wells and facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred. At December 31, 2007, the asset retirement obligation is estimated to be $29.9 million (2006 – $28.4 million), based on a total future liability of $49.4 million (2006 - $49.4 million). These obligations will be settled at the end of the useful lives of the underlying assets, which currently averages at five years, but extends up to 21 years into the future. This amount has been calculated using an inflation rate of 2.0% and discounted using a credit-adjusted risk-free interest rate of 8.0%.

The following table reconciles the asset retirement obligations:

	2007	2006
Asset retirement obligation, beginning of year	$        28,447	$       24,323
Acquisitions	2,574	1,926
Additions	2,108	1,281
Revisions	-	2,000
Accretion expense	2,182	2,166
Dispositions	(2,130)	-
Costs incurred	(2,225)	(3,178)
Foreign exchange	(1,017)	(71)
Asset retirement obligation, end of year	$        29,939	$        28,447

Page 17 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

11.

Convertible debentures

The unsecured convertible debentures are classified as debt with a portion of the proceeds allocated to equity representing the value of the conversion option.  If the debentures are converted to trust units, the debt and equity components are transferred to unitholders’ capital.  The debt balance associated with the convertible debentures accretes over time to the amount owing on maturity with such increases reflected as non-cash interest expense in the statement of loss.

On April 26, 2007, the Trust issued $40.0 million of convertible debentures with a face value of $1,000 per convertible debenture that mature on June 30, 2012, bear interest at 8.25% per annum paid semi-annually on June 30 and December 31 of each year with the first payment on December 31, 2007 and are subordinated to the bank credit facilities.  The convertible debentures are convertible at the option of the holder into trust units at any time prior to the maturity date at the conversion price of $6.80 per trust unit.  

On November 21, 2006, the Trust issued $138.0 million of convertible debentures that mature on December 31, 2011, bear interest at 8% per annum paid semi-annually on June 30 and December 31 of each year with the first payment occurring in 2007 and are subordinated to the bank credit facilities.  The convertible debentures are convertible at the option of the holder into trust units at any time prior to the maturity date at the conversion price of $9.25 per trust unit being a conversion rate of 108.1081 trust units for each $1,000 principal amount of debentures.  During 2006, convertible debentures were converted, resulting in the issuance of 6,234,483 trust units.  None were converted in 2007.

At the option of the Trust, the repayment of the principal portion of the convertible debentures may be settled in trust units.  The number of trust units issued upon redemption by the Trust will be calculated by dividing the principal by 95% of the weighted average trading price of trust units.  The 8.25% convertible debentures are not redeemable on or before June 30, 2010 (8% - December 31, 2009). On or after July 1, 2010 and prior to maturity, the convertible debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days notice, at a redemption price of $1,050 per convertible debenture on or after July 1, 2010  (8% - January 1, 2010) and, on or before June 30, 2011 (8% - January 1, 2010), at a redemption price of $1,025 per convertible debenture and on or after July 1, 2011  (8% - January 1, 2011) and prior to maturity, in each case, plus accrued and un paid interest thereon, if any. At December 31, 2007, the Trust had $80.3 million in 8% convertible debentures outstanding with an estimated fair value of $76.0 million and $40.0 million in 8.25% convertible debentures outstanding with an estimated fair value of $35.7 million.

Page 18 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

	8% Series	8.25% Series	Total	Equity Component
November 21, 2006 issuance	$  138,000	-	$   138,000	$             -
Portion allocated to equity	(2,387)	-	(2,387)	2,387
Issue costs	-	-	-	(107)
Accretion of non-cash interest expense	33	-	33	-
Converted to trust units	(56,672)	-	(56,672)	(953)
Balance, December 31, 2006	$    78,974	$              -	$    78,974	$     1,327
April 28, 2007 issuance	-	40,000	40,000	-
Portion allocated to equity	-	(2,765)	(2,765)	2,765
Issue costs reclassified against carrying value (note 4)	(3,481)	-	(3,481)	-
Issue costs	(305)	(2,069)	(2,374)	(115)
Accretion of discount	844	494	1,338	-
Balance, December 31, 2007	$   76,032	$    35,660	$111,692	$    3,977

12.

Non-controlling interest

Number of exchangeable shares issued	EEC	RMG	RMAC series B	Total
Balance at December 31, 2005	348,146	736,842	659,116	1,744,104
Exchanged for trust units	(331,809)	(736,842)	(592,396)	(1,661,047)
Balance at December 31, 2006	16,337	-	66,720	83,057
Exchanged for trust units	(16,337)	-	(66,720)	(83,057)
Balance at December 31, 2007	-	-	-	-

Non-controlling interest	Amount
Balance at December 31, 2005	$      32,402
Exchanged for trust units	(30,634)
Non-controlling interest share of net earnings	(36)
Balance at December 31, 2006	$      1,732
Exchanged for trust units	(1,732)
Balance at December 31, 2007	-

During Q1 2007, all remaining Enterra Energy Corp. (“EEC”) exchangeable shares (16,337) were converted into 23,401 trust units at an exchange ratio prevailing at the time of conversion and all remaining RMAC series B exchangeable shares (66,720) were converted into 81,028 trust units at an exchange ratio prevailing at the time of conversion.  The exchange of the EEC exchangeable shares is treated as a step acquisition which increases goodwill by $0.2 million for the difference between the fair value of the trust unit issued and the carrying value of the EEC exchangeable share at the time of exchange.

Page 19 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

During 2006, a total of 331,809 Enterra Energy Corp. exchangeable shares were converted into 422,397 trust units at an exchange ratio prevailing at the time of conversion (2005 – 62,624, exchangeable shares were converted into 73,432 trust units).  During 2006 a total of 592,396 RMAC series B exchangeable shares were converted into 619,945 trust units at an exchange ratio prevailing at the time of conversion (2005 – 748,061 exchangeable shares were converted into 758,109 trust units).  The exchange of the EEC exchangeable shares is treated as a step acquisition which increases goodwill by $5.7 million (2005 – $1.4 million) for the difference between the fair value of the trust unit issued and the carrying value of the EEC exchangeable share at the time of exchange.  At December 31, 2006, the exchange ratio for Enterra Energy Corp. exchangeable shares was 1.39937 (2005 - 1.20694) and for RMAC series B exchangeable shares was 1.19626, (2005 - 1.03175).

13.

Unitholders’ equity

Authorized trust units

An unlimited number of trust units may be issued.

The trust units are redeemable at the option of the holder based on the lesser of 90% of the average market trading price of the trust units for the 10 trading days after the date of redemption or the closing market price of the trust units on the date of redemption.   Trust units can be redeemed to a cash limit of $0.1 million per year or a greater limit at the discretion of the Trust.  Redemptions in excess of the cash limit shall be satisfied first by the issuance of notes by a subsidiary of the Trust and second by issuance of promissory notes by the Trust.

Issued trust units

	Number of Units	Amount
Balance at December 31, 2005	36,504,416	$    373,761
Issued for cash pursuant to private placements	657,500	12,544
Issued on acquisition of Oklahoma Assets	5,685,028	116,525
Issued for cash pursuant to prospectus offering	4,979,500	40,334
Issued on conversion of convertible debentures	6,234,483	57,625
Issued as financing fees on bridge credit facilities	116,054	2,077
Issued for exchangeable shares	1,779,184	36,502
Issued under restricted unit plan	41,805	579
Issued on exercise of options	99,905	1,427
Unit issue costs	-	(6,240)
Balance at December 31, 2006	56,097,875	$  635,134
Issued for cash pursuant to prospectus offering	4,945,000	29,176
Issued as financing fees related to the retirement of the 2006 bridge credit facilities	50,000	515
Issued for exchangeable shares	104,429	1,940
Issued under restricted unit plan	238,591	2,663
Unit issue costs	-	(1,738)
Balance at December 31, 2007	61,435,895	$667,690

Page 20 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

Warrants

In April 2005 as part of an agreement to issue equity, the Trust granted warrants to Kingsbridge Capital Limited (“Kingsbridge”) to purchase 301,000 trust units. The warrants have a three-year term.  The exercise price of the warrants was initially US$25.77 per trust unit and is reduced each month by the amount of the Trust’s distribution for such month on the trust units, provided that the price shall not decrease below US$21.55 per trust unit.  As at December 31, 2007 the exercise price of the warrants was US$22.17 (2006 – US$22.65).  No warrants have been exercised since this issuance.    

 Contributed surplus

Balance at December 31, 2005	$       573
Trust unit option based compensation	1,294
Restricted and performance unit compensation	1,935
Transfer to trust units on restricted and performance unit exercises	(579)
Transfer to trust units on option exercises	(28)
Balance at December 31, 2006	$    3,195
Trust unit option based compensation	1,300
Restricted and performance unit compensation	2,828
Transfer to trust units on restricted and performance unit exercises	(2,663)
Balance at December 31, 2007	$  4,660

Trust unit options

Enterra has granted trust unit options to its directors, officers, employees and consultants.  Each trust unit option permits the holder to purchase one trust unit at the stated exercise price.  All options vest over a 2 to 3 year period and have a term of 4 to 5 years. At the time of grant, the exercise price is equal to the market price.  The forfeiture rate is estimated to be 10%. The following options have been granted:

Page 21 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

	2007		2006
	Number of options	Weighted- average exercise price	Number of options	Weighted- average exercise price
Options outstanding, beginning of year	1,481,000	$     20.28	1,431,405	$22.31
Options granted	485,000	2.64	752,000	15.70
Options exercised	-	-	(99,905)	14.00
Options forfeited	(491,666)	20.08	(602,500)	23.62
Options outstanding, end of year	1,474,334	$    14.51	1,481,000	$  20.28
Options exercisable at end of year	710,333	$    17.14	254,666	$  23.85

Exercise price range	Number of options	Weighted average                    exercise price	Weighted average remaining contract life
$1.65	450,000	$     1.65	4.90
$13.48 to $20.12	516,334	16.50	3.34
$23.15 to $29.31	508,000	23.88	2.45
	1,474,334	$    14.51	3.54

Estimated fair value of stock options

The estimated grant date fair value of options was determined using the Black-Scholes model under the following assumptions:

	2007	2006
Weighted-average fair value of options granted ($/option)	$       0.96	$     1.07
Risk-free interest rate (%)	4.7	4.2
Estimated hold period prior to exercise (years)	4	5
Expected volatility (%)	77	45
Expected cash distribution yield (%)	1	14

Page 22 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

Restricted and performance units

Enterra has granted restricted and performance units to directors, officers, and employees.  Restricted units vest over a contracted period and provide the holder with trust units on the vesting dates of the restricted units.  The units granted are the product of the number of restricted units times a multiplier.  The multiplier starts at 1.0 and is adjusted each month based on the monthly distribution of the Trust divided by the five-day weighted average price of the  trust units based on the New York Stock Exchange for the period preceding the distribution date.  Performance units vest at the end of two years and provide the holder with trust units based on the same multiplier as the restricted units as well as a payout multiplier.  The payout multiplier ranges between 0.0 and 2.0 based on the Trust’s total unitholder return compared to its peers.  The forfeiture rate for is estimated to be 10% for 2007 and 2006.  As at December 31, 2007 and 2006 the payout multiplier was estimated to be nil based on the Enterra’s total unitholder return compared to its peers.

The following restricted and performance units have been granted:

	Number of restricted units	Weighted-average grant date fair value	Number of performance units	Weighted-average grant date fair value
Units outstanding, December 31, 2005	-	$             -	-	$            -
Granted	479,466	14.90	215,119	15.06
Vested	(44,375)	15.08	-	-
Forfeited	(11,236)	15.66	(2,171)	15.66
Units outstanding, December 31, 2006	423,855	$     14.91	212,948	$    15.41
Granted	1,045,507	3.53	363,940	3.20
Vested	(215,383)	12.76	-	-
Forfeited	(196,496)	11.22 22	(122,717)	13.46
Units outstanding, December 31, 2007	1,057,483	$     4.77	454,171	$   6.29

The estimated value of the restricted units and performance units is based on the trading price of the trust units on the grant date.  For performance units the estimated fair value is adjusted for the estimated payout multiple, which at December 31, 2007 and 2006 was nil.

Reconciliation of earnings per unit calculations

For the year ended December 31, 2007
	Net loss	Weighted Average Units Outstanding	Per Unit
Basic and diluted	$    (142,036)	59,766,567	$    (2.38)

Page 23 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

For the year ended December 31, 2006
	Net loss	Weighted Average Units Outstanding	Per Unit
Basic	$   (64,239)	44,141,688	$    (1.46)
For the calculation of the weighted average number of diluted units outstanding for 2007 and 2006, all options, restricted and performance units, convertible debentures, warrants and exchangeable shares were excluded, as they were anti-dilutive to the calculation.

Trust unit savings plan

Enterra established a trust unit savings plan whereby it will match an employee’s contributions to the plan to a maximum of 9.0% of their salary.  Both the contributions of the employee and the Trust were used to purchase trust units on the NYSE. During 2007 the Trust expensed approximately $0.4 million (2006 - $0.3 million) relating to its contributions to the plan.  

14.

Accumulated other comprehensive (loss)

	2007	2006
Opening balance	$       1,930	$      -
Cumulative translation of self-sustaining operations	(48,986)	1,082
Foreign exchange loss realized	2,078	848
Balance at December 31, 2007	(44,978)	$   1,930

Accumulated other comprehensive (loss) is comprised entirely of currency translation adjustments on the U.S. operations.

Page 24 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

15.

Income taxes

The income tax provision is calculated by applying federal and provincial statutory tax rates to earnings or loss as follows:

	2007	2006
Loss before income taxes and non-controlling interest	$  (177,986)	$(121,850)
Combined federal and provincial income tax rate	32.12%	34.50%
Computed income tax reduction	(57,169)	(42,038)
Increase (decrease) resulting from:
Interest component of trust distributions	(10,139)	(13,788)
Non-deductible crown charges	-	3,614
Resource allowance	-	(1,464)
Goodwill impairment	24,560	-
Other non-deductible items	1,880	1,418
Difference between U.S. and Canadian tax rates	(2,076)	(1,494)
Change in estimated pool balances	567	-
Change in tax rates	2,447	(6,669)
Other	3,879	1,521
Capital tax	481	341
Current tax	(380)	984
	$  (35,950)	$(57,575)

The components of the net future income tax liability at December 31 were as follows:

	2007	2006
Future income tax assets:
Non-capital loss carry-forwards	$     47,475	$     20,255
Valuation allowance on non-capital losses	(9,451)	-
Asset retirement obligations	8,786	8,969
Attributed Canadian royalty income	1,317	689
Financial instruments	1,516	689
Deferred financing charges	850	689
	$     50,493	$     29,913
Future income tax liabilities:
Property, plant and equipment	72,911	66,343
Financial instruments	179	3,910
Net future income tax liability	$  22,597	$     40,340

The tax rate applied to temporary difference is approximately 30.2% in 2007 (2006 – 29.7%) compared to the federal and provincial statutory rate of 32.1% (2006 – 34.5%).  On a consolidated basis, property, plant and equipment have an approximate tax basis of $350.4 million ($477.3 million in 2006) available for future use as deductions from taxable income.  Non-capital loss carry-forwards, excluding those for which a valuation allowance has been taken, amongst Canadian and U.S. subsidiaries, totaled $104.4 million ($60.0 million in 2006) and expired from 2008 to 2025.

The effect of the enactment of the SIFT tax on the future tax provision for the year ended December 31, 2007 was not significant.  

Page 25 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

16.

Financial instruments

The financial instruments recognized on the consolidated balance sheets include cash, accounts receivable, accounts payable and accrued liabilities, distributions payable to unitholders, notes payable, bank indebtedness, convertible debentures, capital lease and financial derivatives.  The fair values of financial instruments other than the financial derivatives, convertible debentures, and bank indebtedness approximate their carrying amounts due to the short-term nature of the instruments.  The carrying value of bank indebtedness approximates its fair value due to floating interest terms.  The financial derivative contracts are recorded at fair value with the gains and losses included within earnings for the period.

Enterra is exposed to fluctuations in commodity prices, foreign-currency exchange rates, interest rates and credit risk. Enterra manages its operations to minimize the exposure to these risks to the extent practical and, to a lesser extent, using derivative instruments and physical sales contracts.  Management uses non-exchange traded forwards, swaps, options and physical delivery contracts to manage a portion of commodity price risk.  Management monitors the exposure to the above risks and regularly reviews its derivative activities and all outstanding positions.

(a)

Commodity price risks

Enterra is exposed to fluctuations in natural gas and crude oil prices.  

The Trust has entered into derivative financial instruments and fixed price physical contracts to minimize the exposure to fluctuations in the crude oil and natural gas prices. At December 31, 2007, the following financial derivative contracts are outstanding:  

Page 26 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

Derivative Instrument	Commodity	Price	Volume (per day)	Period
Collars	Gas	8.00 by 12.00 (Cdn$/GJ)	10,000 GJ	November 1, 2007 – March 31, 2008
Floor	Gas	8.00 (US$/mmbtu)	10,000 mmbtu	November 1, 2007 – March 31, 2008
Collars	Gas	7.00 by 11.00 (US$/mmbtu)	3,000 mmbtu	November 1, 2007 – March 31, 2008
Fixed	Gas	7.95 (US$/mmbtu)	2,000 mmbtu	April 1, 2008 – October 31, 2008
Collars	Gas	6.50 by 10.50 (US$/mmbtu)	3,000 mmbtu	April 1, 2008 – October 31, 2008
Collars	Oil	55.00 by 75.25 (US$/bbl)	500 bbl	January 1, 2008 – June 30, 2008
Collars	Oil	62.00 by 78.00 (US $/bbl)	500 bbl	January 1, 2008 – June 30, 2008
Collars	Oil	62.00 by 75.50 (US $/bbl)	500 bbl	January 1, 2008 – March 31, 2008
Collars	Oil	62.00 by 75.60 (US $/bbl)	500 bbl	April 1, 2008 – June 30, 2008
Collars	Oil	62.00 by 80.50 (US$/bbl)	500 bbl	July 1, 2008 – December 31, 2008
Collars	Oil	62.00 by 80.05 (US$/bbl)	500 bbl	July 1, 2008 – December 31, 2008

Enterra had the following fixed price physical contracts outstanding as at December 31, 2007:

Fixed purchase Power (Alberta) 62.90 (Cdn $/Mwh) 72 Mwh July 1, 2007 – December 31, 2009

The fair market value of the financial derivatives at December 31, 2007 is estimated to be a liability of $5.2 million (2006 – asset of $10.8 million).  Included in the oil and natural gas revenues is an unrealized loss on financial derivatives of $16.8 million (2006 – unrealized gain of $10.6 million).  Included in operating expenses is an unrealized loss of $0.4 million (2006 – $0.2 million).

(b)

Foreign currency exchange risk

Enterra is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar denominated prices.  The U.S. subsidiary of Enterra operates in a foreign currency which is translated to Canadian dollars as described in note 3.  These operations are exposed to currency fluctuations.

(c)

Credit risk

Purchasers of Enterra’s natural gas, crude oil and natural gas liquids comprise a substantial portion of Enterra’s accounts receivable.  These purchasers are subject to an internal credit review to reduce the risk of non-payment.  A portion of Enterra’s accounts receivable are with joint venture partners in the oil and gas industry and are subject to normal industry credit risks.   As at December 31, 2007 and 2006 accounts receivable includes a balance of $1.1 million as an allowance for doubtful accounts.

Page 27 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

(d)

Interest rate risk

Interest rate risk exists principally with respect to the indebtedness that bears interest at floating rates. At December 31, 2007, the balance sheet had $171.6 million (2006 - $187.7 million) of indebtedness bearing interest at floating rates.   The balance of the indebtedness which is the convertible debentures, bear interest at fixed rates.

17.

Changes in non-cash working capital

	2007	2006
Accounts receivable	$        11,899	$     1,369
Prepaid expenses, deposits and other	1,661	(175)
Accounts payable and accrued liabilities	(9,020)	(18,891)
Foreign exchange on working capital	1,841	(3,935)
Changes in non-cash operating working capital	$           6,381	$     (21,632)
Changes in non-cash investing working capital	$         (1,778)	$        (7,645)

During the year ended December 31, 2007 the Trust paid interest of $21.7 million (2006 - $26.5 million) and taxes of $0.5 million (2006 – $2.9 million).

18.

Commitments

During 2007 total rental expense was $1.2 million (2006 - $0.8 million).  Enterra has commitments for the following payments over the next six years:

	2008	2009	2010	2011	2012	2013
Office leases	$     825	$     896	$     989	$  1,359	$     323	$     239
Vehicle and other operating leases	340	173	59	38	38	38
	$  1,165	$  1,069	$  1,048	$  1,397	$     361	$     277

19.

Contingencies

At December 31, 2007 a claim in the amount of approximately US$3.9 million has been filed against Enterra related to its U.S. operations.  The outcome of the claim is not determinable.  Enterra has also filed claims against the claimant. No amounts have been accrued in the financial statements relating to this claim.

Certain claims have been brought against Enterra in the ordinary course of business.  In the opinion of management, all such claims, except as noted above, are adequately covered by insurance, or if not so covered, are not expected to materially affect its financial position.

Page 28 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

20.

Segmented information

The Trust has one operating segment that is divided amongst two geographical areas.  The following is selected financial information from the two geographic areas.  

	Year ended December 31, 2007	Year ended December 31, 2006
Revenue
Canada	$   128,406	$   156,859
U.S.	78,630	87,549
	$   207,036	$   244,408
Property, plant and equipment
Canada	$   315,569	$   333,911
U.S.	241,209	325,357
	$   556,778	$   659,268
Goodwill
Canada	-	$     76,256
U.S.	-	-
	-	$     76,256

21.

Related party transactions

During 2007 Enterra paid $0.7 million (2006 - $0.8 million) to Macon Resources Ltd. (“Macon”), a company 100% owned by the former Chief Executive Officer, for management services provided by the former Chief Executive Officer for a portion of 2006 and a previous Chief Financial Officer.  The amounts have been recorded at the agreed values.  At December 31, 2007 and 2006, no amount was payable to Macon for management services.  In Q1 2007 50,000 restricted units (valued at $0.4 million based on the unit price of trust units on the grant date) were granted to Macon.  On February 28, 2007, these restricted units vested and were converted to 50,441 trust units.  The former Chief Executive Officer resigned as an officer and director on November 27, 2007 and February 20, 2008 respectively. Of the $0.7 million payment to Macon is an agreed amount of $0.3 million related to the termination of the con tract that otherwise would have run to June 1, 2008..  

During 2006 Enterra entered into a farmout agreement with Petroflow Energy Ltd. (“Petroflow”), a public oil and gas company, to fund 100% of the drilling and completion costs of the Oklahoma Assets’ undeveloped lands.  The former Chief Executive Officer of the Trust and a current member of the board of directors own, directly and indirectly, approximately 16% and 2% of the outstanding shares of Petroflow respectively.  As at December 31, 2007, US$2.5 million (2006 - $US1.5 million) of trade receivables were due from Petroflow.  The long-term receivables are for infrastructure costs incurred that are to be repaid by Petroflow over a three-year period and is subject to interest of 12.0% per annum.  During 2007, US$0.4 million of interest income was earned on the long-term receivables from Petroflow.  In 2007, $1.1 million of principal payments have been received.  The balance at year end December 31, 2007 is US$6.4 million of which US$2.3 million is due within one year and has been included in accounts receivable.   

Page 29 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

On November 23, 2007, the Trust entered into a consulting agreement with Trigger Projects Ltd. for management services that would be expected of the most senior manager of the Trust.  This contract has terms that require payment for services of $40,000 per month and a bonus of up to $0.5 million on termination.  The contract expires on May 31, 2008.  Payments of $50,000 were made to Trigger Projects Ltd. during 2007 and no amounts were payable at December 31, 2007.

Relationship with JED Oil Inc. and JMG Exploration Inc.

On January 1, 2006, Enterra terminated a Technical Services Agreement with JED Oil Inc (“JED”), which had provided for services required to manage the Trust’s field operations and governed the allocation of general and administrative expenses between the two entities.  The Trust now manages its own management, development, exploitation, operations and general and administrative activities.  

On September 28, 2006, Enterra terminated the existing farmout, joint services and an Agreement of Business Principles with JED.  Concurrent with the termination of the agreements, the Trust settled all amounts owing to JED.

In September 2006, Enterra sold $44.0 million of petroleum and natural gas properties to JED in exchange for $30.9 million of petroleum and natural gas properties and the settlement of the $13.1 million balance due to JED.   

Previously, under an Agreement of Business Principles, properties acquired by the Trust were contract operated and drilled by JMG Exploration, Inc. (“JMG”), a publicly traded oil and gas exploration company, if they were exploration properties, and contract operated and drilled by JED, a publicly traded oil and gas development company, if they were development projects.  Exploration of the properties was done by JMG, which paid 100% of the exploration costs to earn a 70% working interest in the properties. If JMG discovered commercially viable reserves on the exploration properties, the Trust had the right to purchase 80% of JMG’s working interest in the properties at a fair value as determined by independent engineers.  Had the Trust elected to have JED develop the properties, development would have been done by JED, which would pay 100% of the development costs to earn 70% of the interests of both JM G and the Trust.  The Trust had a first right to purchase assets developed by JED.   

22.  Subsequent events

In January and February of 2008, the Trust disposed of certain Canadian oil and gas assets for net cash proceeds of $39.9 million.  The Trust anticipates further net proceeds of $1.3 million upon the closing of an additional property sale. The majority of these proceeds were directed to debt repayment.

Page 30 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

AUDITORS' REPORT ON RECONCILIATION TO UNITED STATES GAAP

To the Board of Directors of Enterra Energy Corp., as administrator of Enterra Energy Trust

On March 31, 2008, we reported on the consolidated balance sheets of Enterra Energy Trust (the “Trust”) as at December 31, 2007 and 2006 and the consolidated statements of loss and comprehensive loss, deficit and cash flow for the years then ended, which are included in the annual report on Form 40-F.  In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related supplemental note entitled "Differences between Canadian and United States Generally Accepted Accounting Principles" included in the Form 40-F. This supplemental note is the responsibility of the Trust's management. Our responsibility is to express an opinion on this supplemental note based on our audits.

In our opinion, such supplemental note, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

Chartered Accountants

Calgary, Canada

March 31, 2008

Page 31 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

Differences between Canadian and United States Generally Accepted Accounting Principles

The consolidated financial statements of Enterra Energy Trust (“Enterra”) have been prepared in accordance with Canadian GAAP, which differs in some respects from U.S. GAAP.  Differences in accounting principles as they pertain to the consolidated financial statements are immaterial except as described below.

The application of U.S. GAAP would have the following effect on net income (loss) as reported for the year ended December 31, 2007 and 2006:

	2007	2006
Net loss under Canadian GAAP	$ (142,036)	$ (64,239)
Adjustments for U.S. GAAP
Depletion expense (a)	59,731	(357,312)
Related income taxes	(17,917)	135,822
Gain on financial instruments (b)	-	1,289
Related income taxes	-	(441)
Reverse unit based compensation expense under Canadian GAAP (f)	4,128	3,229
Unit-based compensation recovery (expense) under U.S. GAAP (f)	1,230	(935)
Non-controlling interest (e)	-	(36)
Interest accretion on convertible debentures under Canadian GAAP (h)	491	35
Gain on warrants (c)	-	1,215
Foreign exchange (g)	2,078	848
Adjustment to goodwill impairment due to EIC-151 (e)	26,631	-
Net loss under U.S. GAAP before cumulative effect of change in accounting policy under SFAS 123R	(65,664)	(280,525)
Cumulative effect of change in accounting policy under SFAS 123R (f)	-	177
Net loss under U.S. GAAP	$ (65,664)	$ (280,348)
Other comprehensive loss:
Cumulative translation adjustment (g)	(23,558)	(1,082)
Other comprehensive loss under U.S. GAAP	$ (89,222)	$ (281,430)
Net loss under U.S. GAAP	$ (65,664)	$ (280,348)
Deficit, beginning of year, under U.S. GAAP	(352,054)	(422,991)
Distributions declared (Canadian and U.S. GAAP)	(31,576)	(90,698)
Temporary equity adjustment (d)	423,366	441,983
Deficit, end of year, under U.S. GAAP	$ (25,928)	$ (352,054)
Weighted average units for U.S. GAAP (000’s)
Basic and diluted	59,767	44,846
Net loss per unit under U.S. GAAP before cumulative effect of change in accounting policy under SFAS 123R:
Basic and diluted	$ (1.10)	$ (6.26)
Net loss per unit under U.S. GAAP
Basic and diluted	$ (1.10)	$ (6.25)

Page 32 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

The application of U.S. GAAP would have the following effect on the consolidated balance sheets as reported at December 31, 2007 and 2006:

	2007		2006
	Canadian GAAP	U.S.     GAAP	Canadian      GAAP	U.S.       GAAP
Assets:
Current assets (b)	$ 36,822	$ 36,822	$ 55,166	$ 56,609
Property, plant and equipment (a)	556,778	241,665	659,268	241,188
Goodwill (e)	-	-	76,256	49,832
Long-term receivables	4,003	4,003	-	-
Deferred finance charges	-	-	4,676	1,195
Future income tax (a)(b)	-	99,369	-	116,852
	$ 597,603	$ 381,859	$ 795,366	$ 465,676
Liabilities:
Current liabilities (f)	$ 214,191	$ 214,528	$ 243,849	$ 245,416
Convertible debentures (h)	111,692	115,145	78,974	76,787
Asset retirement obligations	29,939	29,939	28,447	28,447
Future income tax (a)(b)	22,597	-	40,340	-
	378,419	359,612	391,610	350,650
Non-controlling interest (e)	-	-	1,732	-
Mezzanine equity (d)	-	70,651	-	465,998
Unitholder's Equity
Unitholders’ capital (d)(e)	667,690	-	635,134	-
Equity component of convertible      debentures (h)	3,977	-	1,327	-
Warrants (c)	1,215	-	1,215	-
Contributed surplus (f)	4,660	-	3,195	-
Accumulated other comprehensive (loss) income (g)	(44,978)	(22,476)	1,930	1,082
Deficit (d)	(413,380)	(25,928)	(240,777)	(352,054)
	219,184	(48,404)	402,024	(350,972)
	$ 597,603	$ 381,859	$ 795,366	$ 465,676

(a)  Property, plant and equipment

Under Canadian GAAP, the impairment test limits the capitalized costs of oil and natural gas assets to the discounted estimated future net revenue from proved and probable oil and natural gas reserves using forecast prices plus the costs of unproved properties less impairment.  The discount rate used is a risk free interest rate.

Under U.S. GAAP, the full cost method of accounting for oil and natural gas activities requires Enterra to perform an impairment test using after-tax future net revenue from proved oil and natural gas reserves, discounted at 10% plus the cost of unproved properties less impairment.  The prices and costs used in the U.S. GAAP ceiling test are those in effect at the consolidated balance sheet date.  Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion will differ.

Page 33 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

There were ceiling test impairments recognized under U.S. GAAP at December 31, 2007, 2006, 2005, 2004 and 2001.  At December 31, 2007, under the U.S. GAAP ceiling test, Enterra recognized an additional write-down of $1.0 million ($0.7 million after tax) in its Canadian cost center.  No ceiling test impairment was recorded at December 31, 2007 in the U.S. cost center.  At December 31, 2006, Enterra recognized an additional ceiling test write-down under U.S. GAAP of $76.9 million ($53.8 million after tax) in its Canadian cost center and $292.0 million ($175.2 million after tax) in its U.S. cost center.  Prior to 2006, Enterra had recognized additional ceiling test write-downs under U.S. GAAP of $72.8 million ($46.3 million after tax) in its Canadian cost center and $3.0 million ($2.0 million after tax) in its U.S. cost center.    

Under Canadian GAAP, pursuant to EIC-151, property, plant and equipment increased as a result of the conversion of one class of exchangeable shares into trust units.  Under U.S. GAAP, all classes of exchangeable shares are classified as mezzanine equity, valued at their redemption value.  Conversion of exchangeable shares does not result in an increase in property, plant and equipment.  This GAAP difference in the valuation of property, plant and equipment results in an increase in depletion expense during the periods presented for Canadian GAAP as compared with U.S. GAAP.

These differences in the carrying value of property, plant and equipment results in depletion expense being different under U.S. GAAP as compared with Canadian GAAP.  For the years ended December 31, 2007 and 2006, depletion expense under U.S. GAAP was lower by $60.7 million ($42.5 million net of tax) and $12.6 million ($8.3 million net of tax), respectively.

(b)  Financial instruments and marketing contracts

Prior to January 1, 2007, under Canadian GAAP, Enterra’s physical delivery contracts were not considered financial instruments and were not measured at fair value on the consolidated balance sheet.  For U.S. GAAP, Enterra did not formally document and designate these outstanding contracts as physical sales contracts, therefore the contracts were revalued each year end to estimated fair value (marked-to-market).  At December 31, 2006, Enterra had physical delivery contracts in place valued at $1.4 million which increased earnings under U.S. GAAP by $1.4 million ($1.0 million after tax).  

(c)  Warrants

Enterra accounts for purchase warrants as equity under Canadian GAAP.  Under U.S. GAAP the share purchase warrants are accounted for as liabilities with changes in fair value recorded in the statement of operations.  As at December 31, 2007 and December 31, 2006, the estimated fair value of the warrants were $nil.

(d)  Unitholder's mezzanine equity

Under Canadian GAAP, the trust units are considered to be permanent equity and are classified as unitholders' capital.  A U.S. GAAP difference exists due to the redemption feature attached to each trust unit.  Trust units are redeemable at the option of the holder based on the lesser of 90% of the average market trading price of the trust units for the ten trading days after the date of redemption or the closing market price of the trust units on the date of redemption.   Trust units can be redeemed to a cash limit of $100,000 per year or a greater limit at the discretion of Enterra.  Redemptions in excess of the cash limit shall be satisfied first by the issuance of notes by a subsidiary of Enterra and second by issuance of promissory notes by Enterra.

Page 34 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

The redemption feature causes the trust units to be classified as mezzanine equity under U.S. GAAP.    Mezzanine equity is valued at an amount equal to the redemption value of the trust units at the balance sheet date.  Included in the redemption value of the trust units is the redemption value of the exchangeable shares as if all exchangeable shares had previously been converted into trust units.   Any increase or decrease in the redemption value during a period is charged to the deficit.

As at December 31, 2007, unitholders’ capital was reduced by $667.7 million and non-controlling interest was reduced by $nil (December 31, 2006 - $ 635.1 million and $1.7 million, respectively) and the redemption value of the trust units and exchangeable units of $70.7 million (December 31, 2006 - $466.0 million) was recorded as mezzanine equity.  The change in the redemption value of the trust units and exchangeable units is recorded as a reduction or increase to the deficit.  For the year ended December 31, 2007, the deficit was reduced by $423.4 million (December 31, 2006 – $442.0 million).

(e)  Exchangeable securities issued by subsidiaries of income trusts pursuant to EIC-151

On January 19, 2005, the CICA issued EIC-151 “Exchangeable Securities Issued by Subsidiaries of Income Trusts” which states that equity interests held by third parties in subsidiaries of an income trust should be reflected as either non-controlling interest or debt in the consolidated balance sheet unless they meet certain criteria. EIC-151 requires that non-transferable shares be classified as equity.  Enterra's exchangeable shares are transferable and, in accordance with EIC-151, have been classified as non-controlling interest on the Canadian GAAP consolidated balance sheets.  

Since a portion of Enterra's exchangeable shares were not initially recorded at fair value, subsequent exchanges for trust units are measured at the fair value of the trust units issued.  The excess of fair values over book values on the exchange are recorded as additions to property, plant and equipment and goodwill.  In addition, non-controlling interest is reflected as a reduction of such earnings in the Enterra’s consolidated statements of loss and comprehensive loss.

As a result of EIC 151, property, plant and equipment increased by $1.8 million (December 31, 2006 - $1.8 million), goodwill has been increased by $26.6 (December 31, 2006 - $26.4 million), future income tax liability has been increased by $0.7 million (December 31, 2006 - $0.7 million), unitholder’s capital has been increased by $28.3 million (December 31, 2006 - $27.9 million), and the deficit has been increased by $0.4 million (December 31, 2006 - $0.4 million).  Under U.S. GAAP, these adjustments are reversed as the exchangeable shares are included in temporary equity.

Page 35 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

(f)  Unit-based compensation

Effective January 1, 2006, Enterra adopted SFAS No. 123 (revised 2004), “Share-Based Payment”, (“SFAS 123R”) which is a revision of SFAS No. 123, “Accounting for Stock-based Compensation”.  SFAS 123R requires all unit-based payments to employees, including grants of employee unit options, be recognized in the financial statements based on their fair values.  Liability classified awards, such as Enterra’s restricted units, performance units and unit options are remeasured to fair value at each consolidated balance sheet date until the award is settled rather than being treated as an equity classified award on the grant date as required under Canadian GAAP.  Enterra has adopted this standard by applying the modified prospective method.  As a result of the adoption of SFAS 123R, in the year ended December 31, 2006, Enterra has increased current liabilities by $0.6 million, wh ich represented the fair value of all outstanding unit options at January 1, 2006, in proportion to the requisite service period rendered to that date.  In addition, contributed surplus was reduced by $0.5 million and net earnings have been increased by $0.2 million representing previously recognized compensation cost for all outstanding unit options and a credit to record the cumulative effect of a change in accounting principle. Changes in fair value between periods are charged or credited to earnings with a corresponding change in current liabilities.  As at December 31, 2007, the fair value decrease recognized within current liabilities was $1.2 million (December 31, 2006 – increase of $0.9 million).  

Enterra issues units out of treasury upon the exercise of all unit options, restricted units and performance units.

For the years ended December 31, 2007 and 2006, Enterra recorded the following unit-based compensation (000s):

	Restricted and performance units		Unit options		Total
	2007	2006	2007	2006	2007	2006
General and administrative (recovery) expense	$ (1,012)	$1,280	$  (218)	$  (345)	$ (1,230)	$  935

A summary of the status of the unvested options, restricted units and performance units as of December 31, 2006 and 2007, and changes during the years then ended, is presented below:

	Number of unvested options	Weighted average grant date fair value	Number of unvested restricted units	Weighted average grant date fair value	Number of unvested performance units	Weighted average grant date fair value
Unvested, January 1, 2006	1,361,500	$    2.35	-	$          -	-	$           -
Granted	752,000	1.07	479,466	14.90	215,119	15.06
Vested	(384,669)	2.12	(44,375)	15.08	-	-
Forfeited	(502,497)	2.27	(11,236)	15.66	(2,171)	15.66
Unvested, December 31, 2006	1,226,334	$    1.62	423,855	$   14.91	212,948	$    15.41

Granted	485,000	0.59	1,045,507	3.53	363,940	3.20
Vested	(678,666)	1.42	(215,383)	12.76	-	-
Forfeited	(268,667)	1.88	(196,496)	11.22	(122,717)	13.46
Unvested, December 31, 2007	764,001	$    1.04	1,057,483	$     4.77	454,171	$      6.29

Page 36 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

The following tables provide information related to option, restricted unit and performance unitactivity during the years ended December 31, 2006 and 2007:

	Number of unit options	Weighted average exercise price	Weighted average contract life	Aggregate intrinsic value (000’s)
Options outstanding, January 1, 2007	1,481,000	$        20.28		$                  -
Options granted	485,000	2.64		-
Options forfeited	(491,666)	20.08		-
Options outstanding, December 31, 2007	1,474,334	$        14.51	3.54	$                  -
Options expected to vest,    December 31, 2007	1,326,900	$        14.51	2.61	$                  -
Options exercisable, December 31, 2007	710,333	$        17.14	2.79	$                  -

	Number of unit options	Weighted average exercise price	Weighted average contract life	Aggregate intrinsic value (000’s)
Options outstanding, January 1, 2006	1,431,405	$          22.31		$                 -
Options granted	752,000	15.70		-
Options exercised	(99,905)	14.00		50
Options forfeited	(602,500)	23.62		-
Options outstanding, December 31, 2006	1,481,000	$         20.28	3.89	$                 -
Options expected to vest,    December 31, 2006	1,332,900	$         20.28	3.89	$                 -
Options exercisable, December 31, 2006	254,666	$         23.85	3.47	$                 -

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Restricted units outstanding, January 1, 2007	423,855		$                 -
Restricted units granted	1,045,507		-
Restricted units exercised	(215,383)		1,229
Restricted units forfeited	(196,496)		-
Restricted units outstanding, December 31, 2007	1,057,483	2.58	$         1,216
Restricted units expected to vest, December 31, 2007	951,734	2.58	$         1,094
Restricted units exercisable, December 31, 2007	-	-	$                 -

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Restricted units outstanding, January 1, 2006	-		$                  -
Restricted units granted	479,466		-
Restricted units exercised	(44,375)		400
Restricted units forfeited	(11,236)		-
Restricted units outstanding, December 31, 2006	423,855	2.03	$          4,435
Restricted units expected to vest, December 31, 2006	381,470	2.03	$          3,992
Restricted units exercisable, December 31, 2006	-	-	$                  -

Page 37 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Performance units outstanding, January 1, 2007	212,948		$                   -
Performance units granted	363,940		-
Performance units exercised	-		-
Performance units forfeited	(122,717)		-
Performance units outstanding, December 31, 2007	454,171	1.43	$                   -
Performance units expected to vest, December 31, 2007	408,754	1.43	$                   -
Performance units exercisable, December 31, 2007	-	-	$                   -

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Performance units outstanding, January 1, 2006	-		$                    -
Performance units granted	215,119		-
Performance units exercised	-		-
Performance units forfeited	(2,171)		-
Performance units outstanding, December 31, 2006	212,948	1.38	$                    -
Performance units expected to vest, December 31, 2006	191,653	1.38	$                    -
Performance units exercisable, December 31, 2006	-	-	$                    -

The intrinsic value of a unit option is the amount by which the current market value of the underlying unit exceeds the exercise price of the option.  The intrinsic value of a restricted unit is the current market value of the underlying unit.  The intrinsic value of a performance unit is the market value of the underlying unit multiplied by the performance factor at year end which was estimated to be $nil in 2007 and 2006.

As of December 31, 2007, there was $0.1 million (2006 - $0.5 million) of total unrecognized compensation cost related to unvested unit options.  The cost is expected to be recognized over a weighted average period of 1.2 years (2006 – 1.9 years).  

As of December 31, 2007, there was $0.9 million (2006 - $2.7 million) of unrecognized compensation cost related to unvested restricted units.  The cost is expected to be recognized over a weighted average period of 1.2 years (2006 – 2.0 years).  

As of December 31, 2007 and 2006, there was no amount of unrecognized compensation cost related to unvested performance units.  

(g) Cumulative translation adjustment and other comprehensive income

Enterra’s U.S. oil and natural gas properties are considered to be self sustaining.  Under Canadian GAAP, a portion of the cumulative translation adjustment is recognized in income as the investment in the foreign operations is reduced.  Under U.S. GAAP, the cumulative translation adjustment is only recognized in income upon disposition of the segment.  For the year ended December 31, 2007, $2.1 million (2006 - $0.8 million) of the cumulative translation adjustment was recognized as a foreign exchange loss under Canadian GAAP.  In addition, the cumulative translation adjustment under U.S. GAAP differs due to the changes in the carrying values of the U.S. division’s assets and liabilities as a result of additional ceiling test impairments under U.S. GAAP.  The cumulative translation adjustment was reduced by $25.4 million with a corresponding increase to property, plant and equipment of $ 43.2   million and a $17.8 million decrease to the future income tax asset.  

Page 38 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

(h) Convertible debentures

In November 2006 and April 2007, Enterra issued convertible debentures.  Under Canadian GAAP, Enterra’s convertible debentures are classified as debt with a portion representing the value associated with the conversion feature being allocated to equity.  Under U.S. GAAP, the convertible debentures in their entirety are classified as debt.  The non-cash interest expense recorded under Canadian GAAP related to the accretion of the portion of the convertible debentures included in equity is not recorded under U.S. GAAP.   

(i) Additional disclosure under U.S. GAAP

		2007	2006
Components of accounts receivable:
	Trade	$     11,497	$    17,301
	Accruals	19,983	22,736
	Allowance for doubtful accounts	(1,089)	(1,057)
		$     30,391	$    38,980
Components of prepaid expenses:
	Prepaid expenses	$      1,290	$      1,772
	Funds on deposit	980	1,477
		$      2,270	$      3,249
Components of accounts payable:
	Accounts payable	$    22,316	$    17,402
	Accrued liabilities	13,447	28,681
		$    35,763	$    46,083

(j) Select pro forma financial information for the acquisition of Trigger Resources (unaudited)

On April 30, 2007, Enterra acquired Trigger Resources Ltd.  Under U.S. GAAP, select pro forma financial information is disclosed as if the acquisition had occurred on January 1 instead of the actual closing of April 30, 2007.  The following table shows select pro forma financial information:

	2007 (unaudited)	2006 (unaudited)
Oil and natural gas revenue	$     217,994	$     272,239
Net loss	(67,681)	(288,116)
Per unit – basic and diluted	$         (1.10)	$        (5.87)

Page 39 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

(k) Uncertainty in tax positions

On January 1, 2007, Enterra adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.”  FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  The interpretation requires that Enterra recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the and technical merits of the position.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, and accounting in interim periods and disclosure. In accordance with the provisions of FIN 48, any cumulative effect resultin g from the change in accounting principle is to be recorded as an adjustment to the opening deficit balance.

As at December 31, 2007 and 2006, Enterra did not have any amounts recorded pertaining to uncertain tax positions.  The adoption of FIN 48 did not impact Enterra’s tax provision.    

Enterra files federal and provincial income tax returns in Canada and federal, state and local income tax returns in the U.S., as applicable.  Enterra may be subject to a reassessment of federal and provincial income taxes by Canadian tax authorities for a period of four years from the date of mailing of the original notice of assessment in respect of any particular taxation year.  For Canadian tax returns, the open taxation years range from 2003 to 2007.  The U.S. federal statute of limitations for assessment of income tax is generally closed for the tax years ending on or prior to 2002.  In certain circumstances, the U.S. federal statute of limitations can reach beyond the standard three year period. U.S. state statutes of limitations for income tax assessment vary from state to state.  Tax authorities of Canada and U.S. have not audited any of Enterra’s, or its subsidi aries’, income tax returns for the open taxation years noted above.  

Enterra recognizes interest and penalties related to uncertain tax positions in tax expense.  During the years ended December 31, 2007 and 2006, there were no charges for interest or penalties.

(l) New Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, ‘Fair Value Measurements’ (“SFAS 157”).  SFAS 157 defines fair value, establishes a framework for measuring fair value under U.S. GAAP and to expand disclosures about fair value measurements.  The statement is effective for fair value measures already required or permitted by other standards for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years.  The effective date for SFAS 157 as it relates to fair value measurement requirements for financial assets and liabilities that are not remeasured at fair value on a recurring basis has been deferred to fiscal years beginning on or after December 31, 2008.  Enterra has not yet determined the impact of the financial position, results of operations or cash flows from SFAS 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (“SFAS 159”).  This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates.  After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred.  SFAS 159 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted.  However, entities may not retroactively apply the provisions of SFAS 159 to fiscal years preceding the date of adoption.  Enterra is currently reviewing the impact SFAS 159 may have on the financial po sition, results of operations or cash flows.

Page 40 of 43

Enterra Energy Trust

Notes to Consolidated Financial Statements

As at December 31, 2007 and 2006 and for the years there ended

(Expressed in millions of Canadian Dollars)

(Tabular amounts are stated in thousands of dollars except unit and per unit information)

In December 2007, FASB issued SFAS No. 141 (revised 2007) “Business Combinations” which replaces SFAS No. 141 “Business Combinations”. The new standard requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; and recognize and measure the goodwill acquired in the business combinations for which the acquisition date is on or after January 1, 2009. The adoption of this accounting standard will impact business combinations, if any, after the adoption date.

In December 2007, FASB issued SFAS No. 160 “Non-controlling Interests in Consolidated Financial Statements” (“SFAS 160”) which requires Enterra to report non-controlling interests in subsidiaries as equity in the consolidated financial statements; and all transactions between an entity and non controlling interests as equity transactions.  SFAS 160 is effective for Enterra commencing on January 1, 2009 and it will not impact the current consolidated financial statements of Enterra.

Page 41 of 43

EX-99.4

KPMGLLP

Chartered Accountants

Telephone

(403) 691-8000

2700-205 5^th Avenue SW

Fax

(403) 691-8008

Calgary AB  T2P 4B9

Internet

www.kpmg.ca

COMMENTS BY AUDITORS FOR US READERS ON CANADA – US REPORTING DIFFERENCES

To the Board of Directors of Enterra Energy Corp., as administrator of Enterra Energy Trust

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of Enterra Energy Trust’s financial statements, such as the change described in note 4 to the consolidated financial statements as at December 31, 2007 and 2006 and for the years then ended. Our report to the unitholders dated March 31, 2008 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in accounting principles in the auditors' report when the change is properly accounted for and adequately disclosed in the financial statements.

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when the financial statements are affected by conditions and events that cast substantial doubt on the entity's ability to continue as a going concern, such as those described in note 2 to the consolidated financial statements. Our report to the unitholders dated March 31, 3008 is expressed in accordance with Canadian reporting standards, which do not permit a reference to such events and conditions in the auditors' report when these are adequately disclosed in the financial statements.

Signed “KPMG LLP”

Chartered Accountants

Calgary, Canada

March 31, 2008

KPMG LLP, a Canadian owned limited liability partnership, is the Canadian
member firm of KPMG International, a Swiss association

EX-99.5

APPENDIX E

DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES AS AT AND FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006, INCLUDING THE AUDITORS’ REPORT THEREON.

 1

AUDITORS' REPORT ON RECONCILIATION TO UNITED STATES GAAP

To the Board of Directors of Enterra Energy Corp., as administrator of Enterra Energy Trust

On March 31, 2008, we reported on the consolidated balance sheets of Enterra Energy Trust (the “Trust”) as at December 31, 2007 and 2006 and the consolidated statements of loss and comprehensive loss, deficit and cash flow for the years then ended, which are included in the annual report on Form 40-F.  In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related supplemental note entitled "Differences between Canadian and United States Generally Accepted Accounting Principles" included in the Form 40-F. This supplemental note is the responsibility of the Trust's management. Our responsibility is to express an opinion on this supplemental note based on our audits.

In our opinion, such supplemental note, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

Signed “KPMG LLP”

Chartered Accountants

Calgary, Canada

March 31, 2008

 2

Differences between Canadian and United States Generally Accepted Accounting Principles

The consolidated financial statements of Enterra Energy Trust (“Enterra”) have been prepared in accordance with Canadian GAAP, which differs in some respects from U.S. GAAP.  Differences in accounting principles as they pertain to the consolidated financial statements are immaterial except as described below.

The application of U.S. GAAP would have the following effect on net income (loss) as reported for the year ended December 31, 2007 and 2006:

	2007	2006
Net loss under Canadian GAAP	$ (142,036)	$ (64,239)
Adjustments for U.S. GAAP
Depletion expense (a)	59,731	(357,312)
Related income taxes	(17,917)	135,822
Gain on financial instruments (b)	-	1,289
Related income taxes	-	(441)
Reverse unit based compensation expense under Canadian GAAP (f)	4,128	3,229
Unit-based compensation recovery (expense) under U.S. GAAP (f)	1,230	(935)
Non-controlling interest (e)	-	(36)
Interest accretion on convertible debentures under Canadian GAAP (h)	491	35
Gain on warrants (c)	-	1,215
Foreign exchange (g)	2,078	848
Adjustment to goodwill impairment due to EIC-151 (e)	26,631	-
Net loss under U.S. GAAP before cumulative effect of change in accounting policy under SFAS 123R	(65,664)	(280,525)
Cumulative effect of change in accounting policy under SFAS 123R (f)	-	177
Net loss under U.S. GAAP	$ (65,664)	$ (280,348)
Other comprehensive loss:
Cumulative translation adjustment (g)	(23,558)	(1,082)
Other comprehensive loss under U.S. GAAP	$ (89,222)	$ (281,430)
Net loss under U.S. GAAP	$ (65,664)	$ (280,348)
Deficit, beginning of year, under U.S. GAAP	(352,054)	(422,991)
Distributions declared (Canadian and U.S. GAAP)	(31,576)	(90,698)
Temporary equity adjustment (d)	423,366	441,983
Deficit, end of year, under U.S. GAAP	$ (25,928)	$ (352,054)
Weighted average units for U.S. GAAP (000’s)
Basic and diluted	59,767	44,846
Net loss per unit under U.S. GAAP before cumulative effect of change in accounting policy under SFAS 123R:
Basic and diluted	$ (1.10)	$ (6.26)
Net loss per unit under U.S. GAAP
Basic and diluted	$ (1.10)	$ (6.25)

 3

The application of U.S. GAAP would have the following effect on the consolidated balance sheets as reported at December 31, 2007 and 2006:

	2007		2006
	Canadian GAAP	U.S. GAAP	Canadian GAAP	U.S. GAAP
Assets:
Current assets (b)	$ 36,822	$ 36,822	$ 55,166	$ 56,609
Property, plant and equipment (a)	556,778	241,665	659,268	241,188
Goodwill (e)	-	-	76,256	49,832
Long-term receivables	4,003	4,003	-	-
Deferred finance charges	-	-	4,676	1,195
Future income tax (a)(b)	-	99,369	-	116,852
	$ 597,603	$ 381,859	$ 795,366	$ 465,676
Liabilities:
Current liabilities (f)	$ 214,191	$ 214,528	$ 243,849	$ 245,416
Convertible debentures (h)	111,692	115,145	78,974	76,787
Asset retirement obligations	29,939	29,939	28,447	28,447
Future income tax (a)(b)	22,597	-	40,340	-
	378,419	359,612	391,610	350,650
Non-controlling interest (e)	-	-	1,732	-
Mezzanine equity (d)	-	70,651	-	465,998
Unitholder's Equity
Unitholders’ capital (d)(e)	667,690	-	635,134	-
Equity component of convertible      debentures (h)	3,977	-	1,327	-
Warrants (c)	1,215	-	1,215	-
Contributed surplus (f)	4,660	-	3,195	-
Accumulated other comprehensive (loss) income (g)	(44,978)	(22,476)	1,930	1,082
Deficit (d)	(413,380)	(25,928)	(240,777)	(352,054)
	219,184	(48,404)	402,024	(350,972)
	$ 597,603	$ 381,859	$ 795,366	$ 465,676

(a)  Property, plant and equipment

Under Canadian GAAP, the impairment test limits the capitalized costs of oil and natural gas assets to the discounted estimated future net revenue from proved and probable oil and natural gas reserves using forecast prices plus the costs of unproved properties less impairment.  The discount rate used is a risk free interest rate.

Under U.S. GAAP, the full cost method of accounting for oil and natural gas activities requires Enterra to perform an impairment test using after-tax future net revenue from proved oil and natural gas reserves, discounted at 10% plus the cost of unproved properties less impairment.  The prices and costs used in the U.S. GAAP ceiling test are those in effect at the consolidated balance sheet date.  Where the amount of a ceiling test write-down under Canadian GAAP differs from the amount of the write-down under U.S. GAAP, the charge for depletion will differ.

 4

There were ceiling test impairments recognized under U.S. GAAP at December 31, 2007, 2006, 2005, 2004 and 2001.  At December 31, 2007, under the U.S. GAAP ceiling test, Enterra recognized an additional write-down of $1.0 million ($0.7 million after tax) in its Canadian cost center.  No ceiling test impairment was recorded at December 31, 2007 in the U.S. cost center.  At December 31, 2006, Enterra recognized an additional ceiling test write-down under U.S. GAAP of $76.9 million ($53.8 million after tax) in its Canadian cost center and $292.0 million ($175.2 million after tax) in its U.S. cost center.  Prior to 2006, Enterra had recognized additional ceiling test write-downs under U.S. GAAP of $72.8 million ($46.3 million after tax) in its Canadian cost center and $3.0 million ($2.0 million after tax) in its U.S. cost center.    

Under Canadian GAAP, pursuant to EIC-151, property, plant and equipment increased as a result of the conversion of one class of exchangeable shares into trust units.  Under U.S. GAAP, all classes of exchangeable shares are classified as mezzanine equity, valued at their redemption value.  Conversion of exchangeable shares does not result in an increase in property, plant and equipment.  This GAAP difference in the valuation of property, plant and equipment results in an increase in depletion expense during the periods presented for Canadian GAAP as compared with U.S. GAAP.

These differences in the carrying value of property, plant and equipment results in depletion expense being different under U.S. GAAP as compared with Canadian GAAP.  For the years ended December 31, 2007 and 2006, depletion expense under U.S. GAAP was lower by $60.7 million ($42.5 million net of tax) and $12.6 million ($8.3 million net of tax), respectively.

(b)  Financial instruments and marketing contracts

Prior to January 1, 2007, under Canadian GAAP, Enterra’s physical delivery contracts were not considered financial instruments and were not measured at fair value on the consolidated balance sheet.  For U.S. GAAP, Enterra did not formally document and designate these outstanding contracts as physical sales contracts, therefore the contracts were revalued each year end to estimated fair value (marked-to-market).  At December 31, 2006, Enterra had physical delivery contracts in place valued at $1.4 million which increased earnings under U.S. GAAP by $1.4 million ($1.0 million after tax).  

(c)  Warrants

Enterra accounts for purchase warrants as equity under Canadian GAAP.  Under U.S. GAAP the share purchase warrants are accounted for as liabilities with changes in fair value recorded in the statement of operations.  As at December 31, 2007 and December 31, 2006, the estimated fair value of the warrants were $nil.

(d)  Unitholder's mezzanine equity

Under Canadian GAAP, the trust units are considered to be permanent equity and are classified as unitholders' capital.  A U.S. GAAP difference exists due to the redemption feature attached to each trust unit.  Trust units are redeemable at the option of the holder based on the lesser of 90% of the average market trading price of the trust units for the ten trading days after the date of redemption or the closing market price of the trust units on the date of redemption.   Trust units can be redeemed to a cash limit of $100,000 per year or a greater limit at the discretion of Enterra.  Redemptions in excess of the cash limit shall be satisfied first by the issuance of notes by a subsidiary of Enterra and second by issuance of promissory notes by Enterra.

The redemption feature causes the trust units to be classified as mezzanine equity under U.S. GAAP.    Mezzanine equity is valued at an amount equal to the redemption value of the trust units at the balance sheet date.  Included in the redemption value of the trust units is the redemption value of the exchangeable shares as if all exchangeable shares had previously been converted into trust units.   Any increase or decrease in the redemption value during a period is charged to the deficit.

As at December 31, 2007, unitholders’ capital was reduced by $667.7 million and non-controlling interest was reduced by $nil (December 31, 2006 - $ 635.1 million and $1.7 million, respectively) and the redemption value of the trust units and exchangeable units of $70.7 million (December 31, 2006 - $466.0 million) was recorded as mezzanine equity.  The change in the redemption value of the trust units and exchangeable units is recorded as a reduction or increase to the deficit.  For the year ended December 31, 2007, the deficit was reduced by $423.4 million (December 31, 2006 – $442.0 million).

(e)  Exchangeable securities issued by subsidiaries of income trusts pursuant to EIC-151

On January 19, 2005, the CICA issued EIC-151 “Exchangeable Securities Issued by Subsidiaries of Income Trusts” which states that equity interests held by third parties in subsidiaries of an income trust should be reflected as either non-controlling interest or debt in the consolidated balance sheet unless they meet certain criteria. EIC-151 requires that non-transferable shares be classified as equity.  Enterra's exchangeable shares are transferable and, in accordance with EIC-151, have been classified as non-controlling interest on the Canadian GAAP consolidated balance sheets.  

Since a portion of Enterra's exchangeable shares were not initially recorded at fair value, subsequent exchanges for trust units are measured at the fair value of the trust units issued.  The excess of fair values over book values on the exchange are recorded as additions to property, plant and equipment and goodwill.  In addition, non-controlling interest is reflected as a reduction of such earnings in the Enterra’s consolidated statements of loss and comprehensive loss.

As a result of EIC 151, property, plant and equipment increased by $1.8 million (December 31, 2006 - $1.8 million), goodwill has been increased by $26.6 (December 31, 2006 - $26.4 million), future income tax liability has been increased by $0.7 million (December 31, 2006 - $0.7 million), unitholder’s capital has been increased by $28.3 million (December 31, 2006 - $27.9 million), and the deficit has been increased by $0.4 million (December 31, 2006 - $0.4 million).  Under U.S. GAAP, these adjustments are reversed as the exchangeable shares are included in temporary equity.

 5

(f)  Unit-based compensation

Effective January 1, 2006, Enterra adopted SFAS No. 123 (revised 2004), “Share-Based Payment”, (“SFAS 123R”) which is a revision of SFAS No. 123, “Accounting for Stock-based Compensation”.  SFAS 123R requires all unit-based payments to employees, including grants of employee unit options, be recognized in the financial statements based on their fair values.  Liability classified awards, such as Enterra’s restricted units, performance units and unit options are remeasured to fair value at each consolidated balance sheet date until the award is settled rather than being treated as an equity classified award on the grant date as required under Canadian GAAP.  Enterra has adopted this standard by applying the modified prospective method.  As a result of the adoption of SFAS 123R, in the year ended December 31, 2006, Enterra has increased current liabilities by $0.6 million, wh ich represented the fair value of all outstanding unit options at January 1, 2006, in proportion to the requisite service period rendered to that date.  In addition, contributed surplus was reduced by $0.5 million and net earnings have been increased by $0.2 million representing previously recognized compensation cost for all outstanding unit options and a credit to record the cumulative effect of a change in accounting principle. Changes in fair value between periods are charged or credited to earnings with a corresponding change in current liabilities.  As at December 31, 2007, the fair value decrease recognized within current liabilities was $1.2 million (December 31, 2006 – increase of $0.9 million).  

Enterra issues units out of treasury upon the exercise of all unit options, restricted units and performance units.

For the years ended December 31, 2007 and 2006, Enterra recorded the following unit-based compensation (000s):

	Restricted and performance units		Unit options		Total
	2007	2006	2007	2006	2007	2006
General and administrative (recovery) expense	$ (1,012)	$1,280	$  (218)	$  (345)	$ (1,230)	$  935

A summary of the status of the unvested options, restricted units and performance units as of December 31, 2006 and 2007, and changes during the years then ended, is presented below:

	Number of unvested options	Weighted average grant date fair value	Number of unvested restricted units	Weighted average grant date fair value	Number of unvested performance units	Weighted average grant date fair value
Unvested, January 1, 2006	1,361,500	$    2.35	-	$          -	-	$           -
Granted	752,000	1.07	479,466	14.90	215,119	15.06
Vested	(384,669)	2.12	(44,375)	15.08	-	-
Forfeited	(502,497)	2.27	(11,236)	15.66	(2,171)	15.66
Unvested, December 31, 2006	1,226,334	$    1.62	423,855	$   14.91	212,948	$    15.41

Granted	485,000	0.59	1,045,507	3.53	363,940	3.20
Vested	(678,666)	1.42	(215,383)	12.76	-	-
Forfeited	(268,667)	1.88	(196,496)	11.22	(122,717)	13.46
Unvested, December 31, 2007	764,001	$    1.04	1,057,483	$     4.77	454,171	$      6.29

 6

The following tables provide information related to option, restricted unit and performance unitactivity during the years ended December 31, 2006 and 2007:

	Number of unit options	Weighted average exercise price	Weighted average contract life	Aggregate intrinsic value (000’s)
Options outstanding, January 1, 2007	1,481,000	$        20.28		$                  -
Options granted	485,000	2.64		-
Options forfeited	(491,666)	20.08		-
Options outstanding, December 31, 2007	1,474,334	$        14.51	3.54	$                  -
Options expected to vest,    December 31, 2007	1,326,900	$        14.51	2.61	$                  -
Options exercisable, December 31, 2007	710,333	$        17.14	2.79	$                  -

	Number of unit options	Weighted average exercise price	Weighted average contract life	Aggregate intrinsic value (000’s)
Options outstanding, January 1, 2006	1,431,405	$          22.31		$                 -
Options granted	752,000	15.70		-
Options exercised	(99,905)	14.00		50
Options forfeited	(602,500)	23.62		-
Options outstanding, December 31, 2006	1,481,000	$         20.28	3.89	$                 -
Options expected to vest,    December 31, 2006	1,332,900	$         20.28	3.89	$                  -
Options exercisable, December 31, 2006	254,666	$         23.85	3.47	$                 -

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Restricted units outstanding, January 1, 2007	423,855		$                 -
Restricted units granted	1,045,507		-
Restricted units exercised	(215,383)		1,229
Restricted units forfeited	(196,496)		-
Restricted units outstanding, December 31, 2007	1,057,483	2.58	$            1,216
Restricted units expected to vest, December 31, 2007	951,734	2.58	$            1,094
Restricted units exercisable, December 31, 2007	-	-	$                 -

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Restricted units outstanding, January 1, 2006	-		$                  -
Restricted units granted	479,466		-
Restricted units exercised	(44,375)		400
Restricted units forfeited	(11,236)		-
Restricted units outstanding, December 31, 2006	423,855	2.03	$          4,435
Restricted units expected to vest, December 31, 2006	381,470	2.03	$          3,992
Restricted units exercisable, December 31, 2006	-	-	$                  -

 7

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Performance units outstanding, January 1, 2007	212,948		$                   -
Performance units granted	363,940		-
Performance units exercised	-		-
Performance units forfeited	(122,717)		-
Performance units outstanding, December 31, 2007	454,171	1.43	$                   -
Performance units expected to vest, December 31, 2007	408,754	1.43	$                   -
Performance units exercisable, December 31, 2007	-	-	$                   -

	Number of units	Weighted average contract life	Aggregate intrinsic value (000’s)
Performance units outstanding, January 1, 2006	-		$                    -
Performance units granted	215,119		-
Performance units exercised	-		-
Performance units forfeited	(2,171)		-
Performance units outstanding, December 31, 2006	212,948	1.38	$                    -
Performance units expected to vest, December 31, 2006	191,653	1.38	$                    -
Performance units exercisable, December 31, 2006	-	-	$                    -

The intrinsic value of a unit option is the amount by which the current market value of the underlying unit exceeds the exercise price of the option.  The intrinsic value of a restricted unit is the current market value of the underlying unit.  The intrinsic value of a performance unit is the market value of the underlying unit multiplied by the performance factor at year end which was estimated to be $nil in 2007 and 2006.

As of December 31, 2007, there was $0.1 million (2006 - $0.5 million) of total unrecognized compensation cost related to unvested unit options.  The cost is expected to be recognized over a weighted average period of 1.2 years (2006 – 1.9 years).  

As of December 31, 2007, there was $0.9 million (2006 - $2.7 million) of unrecognized compensation cost related to unvested restricted units.  The cost is expected to be recognized over a weighted average period of 1.2 years (2006 – 2.0 years).  

As of December 31, 2007 and 2006, there was no amount of unrecognized compensation cost related to unvested performance units.  

(g) Cumulative translation adjustment and other comprehensive income

Enterra’s U.S. oil and natural gas properties are considered to be self sustaining.  Under Canadian GAAP, a portion of the cumulative translation adjustment is recognized in income as the investment in the foreign operations is reduced.  Under U.S. GAAP, the cumulative translation adjustment is only recognized in income upon disposition of the segment.  For the year ended December 31, 2007, $2.1 million (2006 - $0.8 million) of the cumulative translation adjustment was recognized as a foreign exchange loss under Canadian GAAP.  In addition, the cumulative translation adjustment under U.S. GAAP differs due to the changes in the carrying values of the U.S. division’s assets and liabilities as a result of additional ceiling test impairments under U.S. GAAP.  The cumulative translation adjustment was reduced by $25.4 million with a corresponding increase to property, plant and equipment of $ 43.2   million and a $17.8 million decrease to the future income tax asset.  

 8

(h) Convertible debentures

In November 2006 and April 2007, Enterra issued convertible debentures.  Under Canadian GAAP, Enterra’s convertible debentures are classified as debt with a portion representing the value associated with the conversion feature being allocated to equity.  Under U.S. GAAP, the convertible debentures in their entirety are classified as debt.  The non-cash interest expense recorded under Canadian GAAP related to the accretion of the portion of the convertible debentures included in equity is not recorded under U.S. GAAP.   

(i) Additional disclosure under U.S. GAAP

		2007	2006
Components of accounts receivable:
	Trade	$     11,497	$    17,301
	Accruals	19,983	22,736
	Allowance for doubtful accounts	(1,089)	(1,057)
		$     30,391	$    38,980
Components of prepaid expenses:
	Prepaid expenses	$      1,290	$      1,772
	Funds on deposit	980	1,477
		$      2,270	$      3,249
Components of accounts payable:
	Accounts payable	$    22,316	$    17,402
	Accrued liabilities	13,447	28,681
		$    35,763	$    46,083

(j) Select pro forma financial information for the acquisition of Trigger Resources (unaudited)

On April 30, 2007, Enterra acquired Trigger Resources Ltd.  Under U.S. GAAP, select pro forma financial information is disclosed as if the acquisition had occurred on January 1 instead of the actual closing of April 30, 2007.  The following table shows select pro forma financial information:

	2007 (unaudited)	2006 (unaudited)
Oil and natural gas revenue	$     217,994	$     272,239
Net loss	(67,681)	(288,116)
Per unit – basic and diluted	$         (1.10)	$        (5.87)

 9

(k) Uncertainty in tax positions

On January 1, 2007, Enterra adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.”  FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.  The interpretation requires that Enterra recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the and technical merits of the position.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, and accounting in interim periods and disclosure. In accordance with the provisions of FIN 48, any cumulative effect resultin g from the change in accounting principle is to be recorded as an adjustment to the opening deficit balance.

As at December 31, 2007 and 2006, Enterra did not have any amounts recorded pertaining to uncertain tax positions.  The adoption of FIN 48 did not impact Enterra’s tax provision.    

Enterra files federal and provincial income tax returns in Canada and federal, state and local income tax returns in the U.S., as applicable.  Enterra may be subject to a reassessment of federal and provincial income taxes by Canadian tax authorities for a period of four years from the date of mailing of the original notice of assessment in respect of any particular taxation year.  For Canadian tax returns, the open taxation years range from 2003 to 2007.  The U.S. federal statute of limitations for assessment of income tax is generally closed for the tax years ending on or prior to 2002.  In certain circumstances, the U.S. federal statute of limitations can reach beyond the standard three year period. U.S. state statutes of limitations for income tax assessment vary from state to state.  Tax authorities of Canada and U.S. have not audited any of Enterra’s, or its subsidi aries’, income tax returns for the open taxation years noted above.  

Enterra recognizes interest and penalties related to uncertain tax positions in tax expense.  During the years ended December 31, 2007 and 2006, there were no charges for interest or penalties.

(l) New Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, ‘Fair Value Measurements’ (“SFAS 157”).  SFAS 157 defines fair value, establishes a framework for measuring fair value under U.S. GAAP and to expand disclosures about fair value measurements.  The statement is effective for fair value measures already required or permitted by other standards for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years.  The effective date for SFAS 157 as it relates to fair value measurement requirements for financial assets and liabilities that are not remeasured at fair value on a recurring basis has been deferred to fiscal years beginning on or after December 31, 2008.  Enterra has not yet determined the impact of the financial position, results of operations or cash flows from SFAS 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (“SFAS 159”).  This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates.  After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred.  SFAS 159 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted.  However, entities may not retroactively apply the provisions of SFAS 159 to fiscal years preceding the date of adoption.  Enterra is currently reviewing the impact SFAS 159 may have on the financial po sition, results of operations or cash flows.

In December 2007, FASB issued SFAS No. 141 (revised 2007) “Business Combinations” which replaces SFAS No. 141 “Business Combinations”. The new standard requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; and recognize and measure the goodwill acquired in the business combinations for which the acquisition date is on or after January 1, 2009. The adoption of this accounting standard will impact business combinations, if any, after the adoption date.

In December 2007, FASB issued SFAS No. 160 “Non-controlling Interests in Consolidated Financial Statements” (“SFAS 160”) which requires Enterra to report non-controlling interests in subsidiaries as equity in the consolidated financial statements; and all transactions between an entity and non controlling interests as equity transactions.  SFAS 160 is effective for Enterra commencing on January 1, 2009 and it will not impact the current consolidated financial statements of Enterra.

 10

EX-99.6

EXHIBIT 99.6

CERTIFICATION OF THE ACTING CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this annual report of Enterra Energy Trust (the “Issuer”) on Form 40-F for the year ended December 31, 2007, as filed with the Securities and Exchange Commission on the date thereof, I, Peter Carpenter, Chairman of the special committee of the board of directors, as Acting CEO of the Issuer, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:  

1.

The annual report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934;  and

2.

The information contained in the annual report fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

Date: March 31, 2008 By:   Signed “Peter Carpenter” Peter Carpenter Chairman and Acting CEO

EX-99.7

EXHIBIT 99.7

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER  PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this annual report of Enterra Energy Trust (the “Issuer”) on Form 40-F for the year ended December 31, 2007, as filed with the Securities and Exchange Commission on the date thereof, I, Blaine Boerchers, Chief Financial Officer of the Issuer, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:  

1.

The annual report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934;  and

2.

The information contained in the annual report fairly presents, in all material respects, the financial condition and results of operations of the Issuer.

Date: March 31, 2008 By:   Signed “Blaine Boerchers” Blaine Boerchers Chief Financial Officer

EX-99.8

EXHIBIT 99.8

CERTIFICATION OF THE ACTING CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Peter Carpenter, certify that:

1.

I have reviewed this annual report on Form 40-F of Enterra Energy Trust;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit  to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.

The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal controls over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.

 The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:

March 31, 2008

By:

Signed “Peter Carpenter”

Peter Carpenter

Chairman and Acting Chief Executive Officer

EX-99.9

EXHIBIT 99.9

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Blaine Boerchers, certify that:

1.

I have reviewed this annual report on Form 40-F of Enterra Energy Trust;

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.

The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal controls over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.

 The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date:

March 31, 2008

By:

Signed “Blaine Boerchers”

Blaine Boerchers

 Chief Financial Officer

EX-99.10

KPMGLLP

Chartered Accountants

Telephone

(403) 691-8000

2700-205 5^th Avenue SW

Fax

(403) 691-8008

Calgary AB  T2P 4B9

Internet

www.kpmg.ca

Exhibit 99.10

Consent of Independent Registered Public Accounting Firm

The Board of Directors of Enterra Energy Corp.,

as Administrator of Enterra Energy Trust

We consent to the inclusion in this annual report on Form 40-F of:

─

our auditors' report dated March 31, 2008 on the consolidated balance sheets of Enterra Energy Trust ("the Trust") as at December 31, 2007 and 2006 and the consolidated statements of loss and comprehensive loss, deficit and cash flow for each of the years then ended;  

─

our Report of Independent Registered Public Accounting Firm dated March 31, 2008 on the effectiveness of internal control over financial reporting as of December 31, 2007;

─

our auditors’ report dated March 31, 2008 on the supplemental note to the consolidated financial statements entitled “Differences between Canadian and United States Generally Accepted Accounting Principles”; and

─

our Comments by Auditors for US Readers on Canada-US Reporting Differences, dated March 31, 2008

each of which is contained in this annual report on Form 40-F of the Trust for the fiscal year ended December 31, 2007.

We also consent to the incorporation by reference of such reports in the Registration Statements (No. 333-113609 and No. 333-115318) on Form F-3 and in the Registration Statement (No. 333-120996) on Form S-8 of the Trust.

We also consent to the reference to our firm under the heading “Interest of Experts” in the Registration Statements on Form F-3 (No. 333-113609 and No. 333-115318).

Signed “KPMG LLP”

Chartered Accountants

Calgary, Canada

March 31, 2008

KPMG LLP, a Canadian owned limited liability partnership, is the Canadian
member firm of KPMG International, a Swiss association

EX-99.11

EXHIBIT 99.11

CONSENT OF MCDANIEL & ASSOCIATES CONSULTANTS LTD.

We hereby consent to the reference to us in this annual report on Form 40-F of Enterra Energy Trust and all other references to our name included or incorporated by reference in: (i) Enterra Energy Trust’s annual report on Form 40-F for the year ended December 31, 2007 and (ii) the registration statement on Form F-3 (File Nos. 333-113609 and 333-115318) and the registration statement on Form S-8 (No. 333-120996), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended as applicable.  

Dated:  March 31, 2008

Calgary, Alberta  

Signed “B.J. Wurster”

McDaniel & Associates Consultants Ltd.

EX-99.12

EXHIBIT 99.12

CONSENT OF HAAS PETROLEUM ENGINEERING SERVICES, INC.  

We hereby consent to the reference to us in this annual report on Form 40-F of Enterra Energy Trust and all other references to our name included or incorporated by reference in: (i) Enterra Energy Trust’s annual report on Form 40-F for the year ended December 31, 2007 and (ii) the registration statement on Form F-3 (File Nos. 333-113609 and 333-115318) and the registration statement on Form S-8 (No. 333-120996), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended as applicable.  

Dated:  March 31, 2008

Dallas, Texas

Signed “Robert W. Haas”

Haas Petroleum Engineering Services, Inc.

EX-99.13

EXHIBIT 99.13

CONSENT OF MHA PETROLEUM CONSULTANTS, INC.

We hereby consent to the reference to us in this annual report on Form 40-F of Enterra Energy Trust and all other references to our name included or incorporated by reference in: (i) Enterra Energy Trust’s annual report on Form 40-F for the year ended December 31, 2007 and (ii) the registration statement on Form F-3 (File Nos. 333-113609 and 333-115318) and the registration statement on Form S-8 (No. 333-120996), filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended as applicable.  

Dated:  March 31, 2008

Lakewood, Colorado  

Signed “John P. Seidle”

MHA Petroleum Consultants, Inc.