Enterra Energy

EX-1 2 enterraaif.htm ANNUAL INFORMATION FORM Enterra Energy

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Enterra Energy Trust

Annual Information Form

For the year ended December 31, 2006

March 30, 2007

TABLE OF CONTENTS

GENERAL INFORMATION

Glossary

Abbreviations, Conventions, Conversions and Exchange Rate Information

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 Production Corp.

Enterra US Acquisitions Inc.

Enterra Acquisitions Corp.

Organizational Chart

GENERAL DEVELOPMENTS OF OUR BUSINESS

Three Year History and Significant Acquisitions

Equity Offerings

Anticipated Developments

DESCRIPTION OF OUR BUSINESS AND PROPERTIES

Who We Are

Our Goal, Business Strategy and Operating Principles

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

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue Constant Prices Case as of December 31, 2006 Total of All Areas 33

Reserves Data – Forecast Prices and Costs

Reserves Reconciliation

Undeveloped Reserves

Significant Factors or Uncertainties Affecting Reserves Data

Future Development Costs

Common Infrastructure Costs

Oil and Gas Properties

- i -

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

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

Restriction on the Trustee’s Powers

Amendments to the Trust Indenture

Takeover Bid

Termination of the Trust

Reporting to Unitholders

MARKET FOR SECURITIES

Trading Price and Volume

DISTRIBUTIONS

GOVERNANCE

Delegation of Authority, Administration and Trust Governance

Directors and Officers

Committees

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

CONFLICTS OF INTEREST AND INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS 72

Relationship with JED and JMG

Relationship with Petroflow

Relationship with Macon

Other Management and Director Interests

- ii -

TRANSFER AGENT AND REGISTRAR

MATERIAL CONTRACTS

INTERESTS OF EXPERTS

ADDITIONAL INFORMATION

APPENDIX “A” AUDIT COMMITTEE MANDATE

A-1

APPENDIX “B-1” REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR B-6

APPENDIX “B-2” REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR B-6

APPENDIX “B-3” REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR B-10

APPENDIX “C” REPORT OF MANAGEMENT AND DIRECTORS ON RESERVE DATA AND OTHER INFORMATION C-1

APPENDIX “D” CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR

SANCTIONS

D-1

- iii -

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;

“Board” means the board of directors of EEC;

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

“Debentures” means the 8% 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;

“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 U.S. Acquisitions Inc., a Washington corporation and an indirect subsidiary of the Trust;

“EPC” means Enterra Production Corp., an Alberta corporation and a wholly-owned subsidiary of the Trust until it amalgamated with EEC on 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 principles in Canada;

“Haas” means Haas Petroleum Engineering Services, Inc.;

“Haas Report” means the independent engineering evaluation of certain oil, NGL and natural gas interests of the Trust prepared by Haas dated March 2, 2007 and effective December 31, 2006;

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

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

“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;

“Macon” means Macon Resources 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 20, 2007 and effective December 31, 2006;

“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, 2007 and effective December 31, 2006;

“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, EPC, EPP and EAC);

“Petroflow” means Petroflow Energy Ltd.;

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

“Revolving and Operating Credit Facilities” means

(a)

a $140 million revolving credit facility with a syndicate of lenders, and

(b)

a $20 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;

“RMAC” means Rocky Mountain Acquisition Corp., a corporation created by amalgamation under the laws of Alberta. On January 1, 2006, RMAC amalgamated with High Point to form EPC;

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

“RMG” means Rocky Mountain Gas, Inc. a Wyoming corporation and a wholly-owned subsidiary of the Trust;

“Second-Lien Credit Facility” means a $40 million non-revolving second-lien credit facility with a syndicate of lenders provided pursuant to the amended and restated syndicated credit agreement dated February 1, 2007;

“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” means units of the Trust;

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

“U.S. Holder” means a unitholder that is 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.

Abbreviations, Conventions, Conversions and Exchange Rate Information

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
NGL	natural gas liquids	MMcf/d	million cubic feet per day
		MMBtu	million British thermal units


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

Conventions

The information set out in this AIF is stated as at December 31, 2006 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):


To Convert from	To	Multiply by
Mcf	m³	28.174
m³	cubic feet	35.494
bbls	cubic metres	0.159
m³	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 U.S./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 U.S. 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
	2006	2005	2004
Year End	0.8581	0.8577	0.8308
High	0.9134	0.8609	0.8493
Low	0.8479	0.7872	0.7159
Average	0.8818	0.8258	0.7697

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 only 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;

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.

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. Our Trustee’s head office is located at Suite 2300, 125 - 9th Avenue S.E., Calgary, Alberta, Canada T2G 0P6. Our business strategy is to maintain and enhance our oil and natural gas reserves to provide long-term sustainable cash distributions to our unitholders.

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. See “Organizational Chart”.

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 and continues under the name 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 Production Corp.

EPC was an Alberta corporation created as a result of the amalgamation of High Point and its subsidiaries with RMAC as of January 1, 2006. Some of the crude oil and natural gas properties and related assets in which the Trust had an indirect interest were held, directly or indirectly, through EPC. EPC amalgamated with EEC on January 31, 2007.

Enterra US Acquisitions Inc.

Enterra US Acqco is a Washington corporation. A majority of our United States assets and operations are held and conducted indirectly through Enterra US Acqco.

Enterra Acquisitions Corp.

EAC is a Delaware corporation and is qualified as a foreign corporation in Oklahoma. Enterra US Acqco owns all of the issued and outstanding shares of EAC.

Organizational Chart

As of February 1, 2007, our structure is as follows:

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

GENERAL DEVELOPMENTS OF OUR BUSINESS

Three Year 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 for Trust Units.

2004 Acquisition of Rocky Mountain Energy Corp.

On September 29, 2004 we completed the acquisition of RMEC by way of a plan of arrangement whereby our wholly-owned subsidiary, 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. On January 19, 2007 all of the then-outstanding RMAC Exchangeable Shares were redeemed for Trust Units.

2005 Acquisition of Rocky Mountain Gas, Inc.

On June 1, 2005, we acquired 100% of the issued and outstanding shares of RMG, an entity with natural gas properties in Montana and Wyoming. RMG provides us with future cash potential through the exploitation of coal-bed methane on its undeveloped land as well as its currently producing assets. Results from operations of RMG subsequent to June 1, 2005 are included in our consolidated financial statements. The transaction was valued at approximately $24.0 million and was financed with 736,842 Enterra US Acqco. 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 Enterra US Acqco Exchangeable Shares were redeemed for Trust Units.

2005 Acquisition of High Point Resources Inc.

On August 17, 2005 we completed the acquisition of 100% of the common shares of High Point 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 are predominantly in Alberta and British Columbia. The acquisition was completed to increase our natural gas portfolio, provide strong cash flows and significant tax pools.

2006 Acquisition of Oklahoma Assets

During the first six months of 2006, we 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 deliverability. The second closing occurred on March 21, 2006 and represented approximately 3,700 boe/d of production deliverability. The final two closings occurred on April 4, 2006 and April 18, 2006 and represented approximately 1,300 boe/d of production deliverability. As at December 31, 2006, the assets consist of approximately 84% natural gas and 16% light oil and include over 69,000 net acres of land of which over 42,000 net acres are undeveloped. The purchase price of $307.6 million was paid for through the issuance of 5,685,028 Trust Units valued at $116.5 million, $181.0 million of cash, including $8.9 million that remains unpaid at December 31, 2006, and closing costs of $10.0 million. A business acquisition report dated June 29, 2006 with respect to this acquisition has been filed on SEDAR.

The current and anticipated production from these assets is 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 is exploited at depths of approximately 1,500 metres using long, multi-leg horizontal wells. We will operate all of the related production, gathering and water disposal facilities. A

staff of approximately twenty-six joined us as a result of completing these transactions. During 2006, we entered into a farmout agreement with Petroflow, a public oil and gas company. Under the farmout agreement, Petroflow pays 100% of the costs of drilling and completing each well to earn a 70% working interest. The farmout requires Petroflow to drill not less than 30 wells by the end of 2007 and not less than 30 wells during any twenty-month period thereafter. All 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. Our long term plans include testing of this concept.

2006 Property Swap with JED

On September 28, 2006, we closed a property swap agreement with JED whereby we swapped certain of our interests in properties in the Ferrier area of Alberta for interests of JED in common with ours in East Central Alberta, the Desan area of North Eastern 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 farmin on the Trust’s undeveloped lands. Concurrent with the swap, the Trust settled all amounts owing to JED.

Equity Offerings

2004 Financings

On January 16, 2004 we entered into a financing agreement whereby the Trust agreed to issue 1,650,000 Trust Units at a price of US$10.00 per unit for gross proceeds of US$16.5 million. We applied funds received from this financing to reduce our outstanding debt and for general corporate purposes. The financing closed on June 29, 2004.

On February 20, 2004 we completed a private placement of 1,049,400 Trust Units at a price of US$11.25 per unit for gross proceeds of US$11.8 million (US$10.3 million net of financing costs). We applied funds received from this financing to reduce our outstanding debt.

2005 Financings

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

On April 22, 2005 we entered into an equity line of credit arrangement with Kingsbridge Capital Limited whereby they committed to purchase up to US$100.0 million of Trust Units in various draw downs at the option of the Trust. Under the arrangement, the Trust issued 695,141 Trust Units for proceeds of $15.8 million, which were used to reduce our outstanding debt and for working capital.

On December 20, 2005 we 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 had to be completed by January 13, 2006. We issued 950,000 Trust Units for proceeds of $17.8 million under this prospectus supplement. We applied funds received from this financing for capital expenditures and for general corporate purposes.

2006 Financings

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

On November 10, 2006 we 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 and $138,000,000 of 8% debentures convertible into Trust Units at $9.25 per unit. We applied the funds received from this financing to partially repay our 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.

Anticipated Developments

For a discussion of anticipated developments for 2007, please see the subsequent events and proposed transactions section of the Management’s Discussion and Analysis for the year ending December 31, 2006 (the “MD&A”) which may be found on SEDAR at www.sedar.com.

Implications of Recent Tax Proposals by the Canadian Minister of Finance

On October 31, 2006 the Canadian Minister of Finance (the "Finance Minister") announced a proposal to apply a tax at the trust level on distributions of certain income from publicly-traded mutual fund trusts and other “specified investment flow-through” (“SIFT”) entities at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders. The Finance Minister said existing trusts would have a four-year transition period and would not be subject to the new rules until 2011. However, the proposals also provide that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" could result in the transition period being "revisited", presumably with the loss of the benefit to the Trust of that transition period. As a result, the adverse tax consequences resulting from the proposals could be realized sooner than 2011. On December 15, 2006 the Finance Minister provided additional guidance clarifying what will be deemed to be “normal growth”. Specifically, the transition period will not be revisited for any SIFT whose equity capital grows as a result of issuances of new equity, in any certain intervening periods, by an amount that does not exceed the greater of $50 million and an objective “safe harbour” amount. The safe harbour amount will be measured by reference to a SIFT’s market capitalization as of the end of trading on October 31, 2006 by measuring the value of the SIFT’s issued and outstanding publicly-traded units and excluding options or other interests that were convertible into units of the SIFT. For the period from November 1, 2006 to the end of 2007, a SIFT’s safe harbour will be 40% of that October 31, 2007 benchmark. Thereafter, for each calendar year 2008 through 2010 the safe harbour will be 20% of that benchmark. The annual safe harbour limits are cumulative but the $50 million amounts are not. New equity for purposes of the safe harbour will include issuances of units and debt that is convertible into units, but will not include new equity raised to replace debt that was outstanding as of October 31, 2006, or units acquired through a right existing as of October 31, 2006.

As of October 31, 2006 the Trust had a benchmark market capitalization of approximately $408 million. As a result, assuming the proposals are enacted as proposed, the safe harbour limit for the Trust from November 1, 2006 to the end of 2007 is 40% of the benchmark or approximately $163 million, and 20% of the benchmark or approximately $82 million for each calendar year 2008 through 2010. On November 21, 2006 the Trust issued trust units and debentures for total gross proceeds of $178.3 million. The net

proceeds of the issue combined with drawings under the Trust’s Syndicated Credit Facilities were used to repay in full bridge loans that had been outstanding at October 31, 2006. As a result, it does not appear that the issuances will be considered new equity for purposes of the safe harbour amounts.

If the proposals are ultimately enacted, the implementation of such proposals is expected to result in adverse tax consequences to the Trust and certain of its unitholders (including most particularly investors that are tax exempt or non-residents of Canada) which could be material and may impact cash distributions from the Trust and the value of its units. In the absence of legislation implementing the proposals, the implications of the proposals are difficult to evaluate and no assurance can be provided as to the extent and timing of their application to Enterra. The Trust continues to research its position based on the proposed rules and is waiting for the final legislation.

The October 31 Proposals and, by reference, the December 15 guidelines with respect to “normal growth” were included in a Notice of Ways and Means motion tabled in the House of Commons on March 27, 2007.

Implications of Recent U.S Tax Proposals Contained in H.R. 1672

On March 23, 2007, Rep. Richard Neal of Massachusetts (D) sponsored H.R. 1672 which was referred to the United States House Committee on Ways and Means. This bill proposes amendments to the Code that would deny the maximum 15% preferential federal income tax treatment otherwise available to non-corporate U.S. Holders in respect of distributions from Canadian trusts that are treated as corporations for federal income tax purposes. Since the Trust is classified for United States federal income tax purposes as a partnership, the proposed amendments introduced by H.R. 1672, if enacted as currently drafted, would not appear to apply to distributions made by the Trust that constitute dividends from its underlying Canadian corporate subsidiaries. For more detail see "Risk Factors – United States unitholders may be limited in their ability to use the Canadian withholding tax as a credit against federal income tax and in their ability to claim the effect of certain other favourable income tax provisions".

DESCRIPTION OF OUR BUSINESS AND PROPERTIES

Who We Are

We are an oil and gas trust. Our portfolio of crude oil, NGL and natural gas interests is geographically diversified and balanced between natural gas and liquids production. Our properties are located principally in Alberta, British Columbia and Oklahoma. Our average production for 2006 was approximately 12,352 boe/d, which was comprised of approximately 59% natural gas and 41% crude oil and NGL. As at December 31, 2006, we have working interests in our producing properties averaging approximately 53% and we operate approximately 80% of our production.

Based on the Reserve Reports, our crude oil, NGL and natural gas reserves as of December 31, 2006 are as set forth below.


Pro Forma Reserves⁽¹⁾
Proved (MMboe)	Proved + Probable (MMboe)	RLI (years)
21.2	27.4	6.0 ⁽²⁾

(a)

Based on a forecasted price case.

(b)

Based on proved and probable reserves and a December exit production rate of 12,442 boe/d.

We currently strive to make monthly cash distributions based on a target payout range of 60% to 70% of funds from operations. Cash distributions are paid on or about the 15th day of each month or the first business day thereafter and are paid in U.S. dollars. See “Risk Factors”.

We are structured as a trust to provide a more tax-efficient means to distribute funds to our unitholders than a corporate structure under current Canadian tax laws. As the Trust distributes all of its taxable income to its unitholders, no income taxes are currently paid at the Trust level. However, see the discussion regarding the potential impact of the October 31 Proposals, which is set out under the heading “General Developments of Our Business – Anticipated Developments – Implications of Recent Tax Proposals by the Canadian Minister of Finance”.

Our Goal, Business Strategy and Operating Principles

Our goal is to generate strong returns for our unitholders through a combination of cash distributions that are predictable and sustainable and that increase over time, and capital appreciation from steady and consistent increases in reserves, production and funds from operations per Trust Unit. To achieve that goal we intend to adhere to a three-pronged strategy as follows.

Organic Growth

We currently distribute the majority of funds from operations to unitholders and to invest the balance in the development of the large portfolio of lower-risk opportunities we have identified within our existing asset base. The individual nature and number of the opportunities vary across our properties, but in aggregate we believe they offer us a means of adding reserves and production on a basis that will be accretive to unitholders and at a pace that generally is within our control.

Accretive Acquisitions

Corporate and property acquisitions are an effective means of consolidating assets, improving efficiencies in existing core areas or adding new core areas. We intend to be pro-active, focused and disciplined in our approach to such acquisitions. Generally, we seek to make acquisitions that:

are accretive on a per Trust Unit basis;

add to our portfolio of infill and step-out drilling opportunities, which we believe to be lower-risk in nature;

consolidate our position within an existing core area;

have high working interests and operatorship; and

maintain a reasonable balance among crude oil, NGL production with natural gas production and geographic diversification.

Strategic Partnerships

We actively seek to align ourselves with industry partners that give us access to projects that otherwise may not be available to us due to the nature or degree of risk involved or due to the expertise required to properly capitalize on the opportunity. The basis of our partnerships will vary, but may involve a farmout of our existing assets or a joint acquisition with one of our partners, followed by a farmout or joint venture. Our objectives in structuring these relationships include:

providing us with controlled exposure to higher-risk, higher-return opportunities;

aligning with management teams or individuals with specific experience, proven skills or a demonstrated competitive advantage;

adding reserves and production over an extended period of time at minimal cost and risk to us and, as a result, providing a source of funds for future distributions; and

creating opportunities to purchase at an attractive cost, assets from our partner once the risk is better defined or we have acquired the necessary expertise to exploit the opportunity ourselves.

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:

Diversified Production Base

Our assets are concentrated in three areas: North East British Columbia, Alberta, 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 Data and other Oil and Gas Information”.

Large Portfolio of Development Projects

Our properties contain a number of potential development projects, which we believe support our strategy of reserving a portion of funds from operations to invest in organic growth opportunities. Currently, we estimate that there are in excess of 120 drilling opportunities on our approximately 294,449 net acres of undeveloped land. See “Statement of Reserves Data and other Oil and Gas Information”.

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

Based on average production in the fourth quarter of 2006, approximately 41% of our production is in the United States, which we believe is a high percentage relative to most other Canadian oil and gas trusts. 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 2006 consolidated annual financial statements and in the associated “Management’s Discussion and Analysis – Commodity Pricing”.

Experienced Management Team

Over the past year, we have assembled a strong and committed management team that has demonstrated its ability to identify and successfully execute our business plans. See “Governance – Directors and Officers”.

Personnel

At December 31, 2006, we employed 46 office employees and 29 field operations employees in our Canadian operations and 15 office employees and 22 field employees in our Oklahoma operations for a total of 112 employees.

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 maintain our distributions at current levels.

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, 2007, and we may not be able to obtain additional financing on economic terms attractive to us, if at all.

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 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 and Second-Lien Credit Facility provide 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.

Our assets are leveraged. Any material change in our liquidity could impair our ability to make 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, result in distributions to unitholders being materially reduced, or adversely affect the market price of our Trust Units or Debentures.

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 and distributions to unitholders.

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. We currently distribute the majority of funds from operations to unitholders rather than reinvesting it in reserve additions. 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 will 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 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 and distributions to unitholders.

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 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.

Distributions 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, 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 North East British Columbia and the Hunton formation in Oklahoma), actual results are more likely to vary from estimates.

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 will 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.

Until recently, our operations and expertise were 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 little direct experience operating in these jurisdictions and therefore will face operating and business challenges that we cannot at present foresee and will need to rely on local management.

In addition, 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 have not 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:

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 have limited experience operating properties in the United States and are reliant on the local employees and on our partners, including Petroflow, for technical and operational support. It is our expectation that we will gain 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.

At the current time, Petroflow does not have the ability to fund its commitments to us in 2007 with internal resources and we expect it to seek external sources of capital. To the extent Petroflow is unable to obtain such capital on commercially reasonable terms or otherwise becomes unable to effectively satisfy its obligations to us, our revenues may be reduced and we may not be able to add reserves to offset natural production declines.

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 2006, approximately 20% 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 make estimates of future capital expenditures more difficult.

Further, the operating agreements which govern the properties not operated by us typically require the operator to conduct operations in a “good and 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.

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.

Our recent change in business strategy and accompanying expansion of our employee base may expose us to organizational complications that could negatively impact our business.

Attendant to our recent change in business strategy, there has been a significant expansion of the number of our employees to allow us to become an internally managed entity with operational capabilities. The rapid expansion of the number of employees results in increased logistical complexities, including human resources administration, workforce integration and coordination and related matters. Any significant delay in our ability to organize our workforce in an effective manner or any disruptions in completing that organization could result in the loss of or delay in the receipt of advances in our development or exploitation of our assets and may result in a reduction in the value of our Trust Units or Debentures and a reduction in cash available for distributions to unitholders.

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 Interest of Management and Others in Material Transactions”.

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 nature 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. For example, the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol, was ratified by the Canadian government in December 2002 and will require, among other things, significant reductions

in greenhouse gases. The impact of the Kyoto Protocol on us is uncertain and may result in significant additional costs 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.

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.

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, 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 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 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 increases when crude oil and natural gas prices are low or volatile.

At December 31, 2006 a provision of $66.0 million ($48.8 million in the Canada cost center and $17.2 million in the U.S. cost center) was recorded due to a ceiling test impairment on our property plant and equipment. This provision was required due to a reduction in proven reserves value due to a combination of forecasted increased expenses, commodity prices and decreased reservoir performance and a reduction of the carrying value of undeveloped lands.

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.

Aboriginal land claims may have an effect on our business and operations.

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 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 higher 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 its 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, on December 31, 2006, an estimated 86% 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 Exception 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 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 transferred to non-residents, including limiting or suspending the trading of our Trust Units.

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 would 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 Finance Minister announced a proposal to apply a tax at the trust level on distributions of certain income from publicly-traded trusts and other SIFT entities at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders. For a more detailed discussion of risks related to these proposals, see “General Developments of our Business – Anticipated Developments – Implications of Recent Tax Proposals by the Canadian Minister of Finance.”

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 distribution 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 regulations 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.

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 any basket. Any gain that is recognized by a U.S. Holder on the sale of a Trust Unit that is recognized because a distribution thereon is in excess of basis in that security will generally constitute income from sources within the United States for U.S. foreign tax credit purposes and will therefore not increase the ability to use foreign taxes as credits.

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 federal income tax at a maximum rate of 15 percent provided that, among other things, (a) 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) the U.S. Holder has satisfied certain holding period requirements, and (c) the U.S. Holder has not made an election to treat the dividend as “investment income” for purposes of the investment interest deduction rules. 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. In addition, if H.R. 1672 is enacted into law and if it is expanded to include trusts that are treated as partnerships for U.S. tax purposes, this rate reduction will not apply. For a more detailed discussion of H.R. 1672, see “General Developments of our Business – Anticipated Developments – Implications of Recent U.S. Tax Proposals Contained in H. R. 1672.

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 advisors.

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 future 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 United States federal income taxation of distributions that an individual retirement account or other employee benefit plans makes to its beneficiary or beneficiaries.

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 taxable 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 United 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, including 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 United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or the securities laws of any state within the United States.

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’s 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 shareholder is protected from the liabilities of a corporation. Further, although the Trust has agreed to indemnify and hold harmless each unitholder from any costs, damages, liabilities, expenses, charges and losses suffered by the unitholder resulting from or arising out of that unitholder not having limited liability, the Trust cannot guarantee that any assets would be available in these circumstances to reimburse unitholders for any such liability. 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.

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 – Trust Units and other Securities”.

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 at the discretion of, the Board. On July 18, 2006, the Board determined to reduce the Trust’s target payout ratio range to 60% to 70% of funds from operations. On January 19, 2007, the Board 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.

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.

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, 2006 contained in the McDaniel Report, by Haas with an effective date December 31, 2006 contained in the Haas Report and by MHA with an effective date December 31, 2006 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 Report, Haas and MHA Report 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, Haas and MHA to provide an evaluation of our proved and proved plus probable reserves.

At December 31, 2006 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 Report, Haas Report and MHA Report. Gross reserves include royalty interests. The data may contain slightly different numbers than such report due to rounding. Additionally, the numbers in the tables may not add exactly due to rounding.

The McDaniel Report, Haas Report and MHA Report 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.

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, 2006
Total of All Areas


	Remaining Reserves
	Light and Medium Crude Oil		Heavy Oil			NGL			Natural Gas			Total
Reserves Category	Gross [Mbbl]	Net [Mbbl]	Gross [Mbbl]		Net [Mbbl]		Gross [Mbbl]	Net [Mbbl]		Gross [MMcf]	Net [MMcf]	Gross [Mboe]	Net [Mboe]

CANADA⁽¹⁾ (McDaniel Report)
Producing	2,907	2,773	1,067	956		672		475		28,389	20,945	9,377	7,695
Non-Producing	27	21	-	-		41		28		1,405	1,058	302	225
Proved Undeveloped	111	98	-	-		30		22		2,171	1,666	502	398
Total Proved	3,044	2,892	1,067	956		742		525		31,964	23,668	10,181	8,317
Probable	1,091	1,004	313	272		271		193		14,175	10,554	4,037	3,228
Total Proved plus Probable	4,135	3,896	1,380	1,228		1,013		718		46,139	34,223	14,218	11,545

OKLAHOMA⁽¹⁾ (Haas Report)
Producing	1,324	1,061	-	-		-		-		36,340	29,151	7,381	5,920
Non-Producing	53	43	-	-		-		-		2,165	1,808	414	344
Proved Undeveloped	316	252	-	-		-		-		8,949	7,159	1,808	1,445
Total Proved	1,693	1,356	-	-		-		-		47,454	38,118	9,602	7,709
Probable	197	159	-	-		-		-		9,158	7,384	1,723	1,390
Total Proved plus Probable	1,890	1,515	-	-		-		-		56,612	45,502	11,325	9,099

WYOMING⁽¹⁾ (MHA Report)
Producing	-	-	-	-		-		-		825	678	137	113
Non-Producing	-	-	-	-		-		-		-	-	-	-
Proved Undeveloped	-	-	-	-		-		-		-	-	-	-
Total Proved	-	-	-	-		-		-		825	678	137	113
Probable	-	-	-	-		-		-		1,736	1,400	289	233
Total Proved plus Probable	-	-	-	-		-		-		2,561	2,078	427	346

AGGREGATE
Producing	4,231	3,834	1,067	956		672		475		65,553	50,774	16,895	13,727
Non-Producing	80	64	-	-		41		28		3,570	2,866	716	569
Proved Undeveloped	427	350	-	-		30		22		11,120	8,825	2,309	1,843
Total Proved	4,737	4,248	1,067	956		742		525		80,243	62,464	19,920	16,139
Probable	1,288	1,163	313	272		271		193		25,069	19,338	6,050	4,851
Total Proved Plus Probable	6,025	5,411	1,380	1,228		1,013		718		105,312	81,803	25,970	20,990

(a)

Oklahoma and Wyoming NPV converted to Cdn$ at an exchange rate of Cdn$1.00=US$0.87.

(b)

Gross refers to our working interest before royalties

(c)

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

Summary of Oil and Gas Reserves and
Net Present Values of Future Net Revenue
Constant Prices Case as of December 31, 2006
Total of All Areas


	Net Present Values of Future Net Revenue Constant Prices and Costs
	Before Income Taxes Discounted at (%/year)⁽¹⁾						After Income Taxes Discounted at (%/year)
	-	5	10	15	20	-		5	10	15	20
Reserves Category	[MM$]	[MM$]	[MM$]	[MM$]	[MM$]	[MM$]		[MM$]	[MM$]	[MM$]	[MM$]

CANADA
( McDaniel Report)
Producing	199	175	156	142	131	191		168	151	137	127
Non-Producing	-	-	-	-	-	-		-	-	-	-
Proved Undeveloped	6	4	3	2	1	4		3	2	1	-
Total Proved	205	178	159	144	132	195		171	152	138	127
Probable	92	66	51	41	34	65		47	36	28	23
Total Proved plus Probable	297	245	210	184	165	261		217	188	167	150

OKLAHOMA⁽¹⁾
(Haas Report)
Producing	133	116	102	92	83	132		112	97	86	77
Non-Producing	7	6	5	5	4	7		6	5	5	4
Proved Undeveloped	48	39	33	27	23	43		34	28	24	20
Total Proved	189	161	140	123	110	181		152	131	114	101
Probable	33	27	23	20	17	14		12	10	9	8
Total Proved plus Probable	221	188	163	144	128	195		164	141	123	109

WYOMING⁽¹⁾
(MHA Report)
Proved	1	1	1	1	1	1		1	1	1	1
Non-Producing	-	-	-	-	-	-		-	-	-	-
Proved Undeveloped	-	-	-	-	-	-		-	-	-	-
Total Proved	1	1	1	1	1	1		1	1	1	1
Probable	3	3	2	2	2	2		2	2	1	1
Total Proved plus Probable	4	4	4	3	3	3		3	2	2	2

AGGREGATE
Producing	334	291	259	235	215	324		281	249	224	204
Non-Producing	7	6	5	4	4	7		6	5	4	4
Proved Undeveloped	54	43	35	29	24	47		37	30	25	20
Total Proved	395	341	300	268	243	378		324	284	253	228
Probable	128	97	77	63	53	81		60	47	39	32
Total Proved Plus Probable	523	437	377	331	296	459		384	331	291	261

(a)

Oklahoma and Wyoming NPV converted to Cdn$ at an exchange rate of Cdn$1.00=US$0.87.

Total Future Net Revenue (Undiscounted)
Constant Prices as of December 31, 2006
Total Reserves


Reserves Category	Revenue	Royalties Net of ARTC	Operating Costs	Capital Development Costs	Abandonment Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Net Revenue After Income Taxes
	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)
CANADA (McDaniel Report)
Total Proved	470	80	159	8	18	205	10	195
Total Proved plus Probable	652	114	210	13	18	297	36	261


OKLAHOMA⁽¹⁾ (Haas Report)
Total Proved	385	91	100	3	2	189	7	181
Total Proved plus Probable	446	105	113	3	3	221	26	195


WYOMING⁽¹⁾ (MHA Report)
Total Proved	4	1	1	-	1	1	-	1
Total Proved plus Probable	13	2	5	-	1	4	1	3


AGGREGATE
Total Proved	859	172	260	11	22	395	17	378
Total Proved plus Probable	1,111	221	328	17	23	523	64	459

(a)

Oklahoma and Wyoming NPV converted to Cdn$ at an exchange rate of Cdn$1.00=US$0.87

Oil and Gas Reserves and Net Present Values by Production Group
Constant Prices as of December 31, 2006
Total Reserves


	Discounted at 10%

Reserves Category	Canada $MM	Oklahoma $MM	Wyoming $MM	Total $MM
Proved
Light and Medium Crude Oil⁽¹⁾	76	41	-	117
Heavy Oil	11	-	-	11
Natural Gas	72	96	1	168
Total⁽²⁾	159	137	1	297

Proved Plus Probable
Light and Medium Crude Oil⁽¹⁾	102	46	-	46
Heavy Oil	15	-	-	-
Natural Gas	93	113	4	117
Total⁽²⁾	210	160	4	163

(a)

Including by-products

(b)

Excludes ARTC

Reserves Data – Forecast Prices and Costs

Summary of Oil and Gas Reserves and
Net Present Values of Future Net Revenue
As of December 31, 2006
Forecast Prices and Costs


	Remaining Reserves
	Light and
	Medium Crude		Heavy
	Oil		Oil		NGL		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Reserves Category	[Mbbl]	[Mbbl]	[Mbbl]	[Mbbl]	[Mbbl]	[Mbbl]	[MMcf]	[MMcf]	[Mboe]	[Mboe]

CANADA (McDaniel Report)
Proved
Developed Producing	2,928	2,795	1,070	959	672	475	28,380	20,935	9,400	7,718
Developed Non-Producing	27	21	-	-	41	28	1,405	1,058	302	225
Undeveloped	111	98	-	-	30	22	2,171	1,666	502	398
Total Proved	3,066	2,913	1,070	959	742	525	31,956	23,658	10,204	8,340
Probable	1,092	1,005	313	273	269	192	14,114	10,494	4,026	3,218
Total Proved Plus Probable	4,157	3,918	1,383	1,232	1,011	717	46,070	34,152	14,230	11,558

OKLAHOMA⁽¹⁾ (Haas Report)
Proved
Developed Producing	1,423	1,141	-	-	-	-	42,614	34,203	8,525	6,842
Developed Non-Producing	55	44	-	-	-	-	2,364	1,976	449	373
Undeveloped	319	255	-	-	-	-	9,337	7,470	1,875	1,500
Total Proved	1,797	1,440	-	-	-	-	54,315	43,649	10,850	8,715
Probable	202	164	-	-	-	-	9,584	7,725	1,799	1,452
Total Proved Plus Probable	1,999	1,604	-	-	-	-	63,899	51,374	12,649	10,166

WYOMING⁽¹⁾ (MHA Report)
Proved
Developed Producing	-	-	-	-	-	-	988	807	165	135
Developed Non-Producing	-	-	-	-	-	-	-	-	-	-
Undeveloped	-	-	-	-	-	-	-	-	-	-
Total Proved	-	-	-	-	-	-	988	807	165	135
Probable	-	-	-	-	-	-	1,886	1,519	314	253
Total Proved Plus Probable	-	-	-	-	-	-	2,874	2,326	479	388

AGGREGATE
Proved
Developed Producing	4,351	3,936	1,070	959	672	475	71,983	55,945	18,090	14,694
Developed Non-Producing	82	65	-	-	41	28	3,769	3,034	751	598
Undeveloped	430	353	-	-	30	22	11,508	9,136	2,377	1,898
Total Proved	4,863	4,353	1,070	959	742	525	87,259	68,115	21,218	17,189
Probable	1,294	1,169	313	273	269	192	25,584	19,738	6,139	4,923
Total Proved Plus Probable	6,156	5,522	1,383	1,232	1,011	717	112,843	87,852	27,358	22,112

(a)

Oklahoma and Wyoming NPV converted to Cdn$ at an exchange rate of Cdn$1.00=US$0.87.

(b)

Gross refers to our working interest before royalties

(c)

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

Summary of Oil and Gas Reserves and
Net Present Values of Future Net Revenue
As of December 31, 2006
Forecast Prices and Costs


	Net Present Value of Future Net Revenue Forecast Prices and Costs
	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 (McDaniel Report)
Proved
Developed Producing	226	196	175	158	145	210	184	164	149	137
Developed Non-Producing	2	1	1	-	-	1	1	-	-	-
Undeveloped	8	6	4	3	2	6	4	3	2	1
Total Proved	236	203	180	162	148	217	188	167	151	139
Probable	114	80	60	47	39	80	56	42	33	27
Total Proved Plus Probable	350	283	240	209	186	298	244	209	184	165

OKLAHOMA⁽¹⁾ (Haas Report)
Proved
Developed Producing	212	179	156	137	123	180	150	129	113	100
Developed Non-Producing	11	10	8	7	6	10	8	7	6	5
Undeveloped	68	54	44	37	31	54	43	35	29	25
Total Proved	292	243	208	181	160	244	202	171	148	130
Probable	52	42	35	30	25	25	21	18	15	13
Total Proved Plus Probable	343	285	243	210	185	269	223	189	163	144

WYOMING⁽¹⁾ (MHA Report)
Proved
Developed Producing	3	2	2	2	2	2	2	2	1	1
Developed Non-Producing	-	-	-	-	-	-	-	-	-	-
Undeveloped	-	-	-	-	-	-	-	-	-	-
Total Proved	3	2	2	2	2	2	2	2	1	1
Probable	7	5	5	4	4	4	4	3	3	2
Total Proved Plus Probable	9	8	7	6	6	6	5	5	4	4

AGGREGATE
Proved
Developed Producing	441	378	332	297	270	392	335	294	263	239
Developed Non-Producing	13	11	9	8	7	11	9	7	6	5
Undeveloped	76	60	48	40	33	60	47	38	31	26
Total Proved	530	449	390	345	310	463	391	340	301	270
Probable	172	127	100	81	68	110	77	62	51	42
Total Proved Plus Probable	703	576	489	426	377	573	471	402	351	313

(a)

Oklahoma and Wyoming NPV converted to Cdn$ at an exchange rate of Cdn$1.00=US$0.87.

Undiscounted Future Net Revenue
Forecast Prices as of December 31, 2006
Total Reserves


Reserves Category	Revenue	Royalties Net of ARTC	Operating Costs	Capital Development Costs		Abandon-ment Costs	Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
	MM$	MM$	MM$	MM$		MM$	MM$		MM$		MM$
CANADA (McDaniel Report)
Total Proved	538	96	176	8	22		236	19		217
Total Proved plus Probable	765	140	239	14	23		350	52		298

OKLAHOMA⁽¹⁾ (Haas Report)
Total Proved	577	138	142	3	2		292	47		244
Total Proved plus Probable	668	160	158	3	3		343	74		269

WYOMING⁽¹⁾ (MHA Report)
Total Proved	7	1	2	0	1		3	1		2
Total Proved plus Probable	23	4	8	0	1		9	3		5

AGGREGATE
Total Proved	1,123	236	320	11	25		530	67		463
Total Proved plus Probable	1,455	304	404	18	27		703	129		572

(a)

Oklahoma and Wyoming NPV converted to Cdn$ at an exchange rate of Cdn$1.00=US$0.87.

Oil and Gas Reserves and Net Present Values
by Production Group

Forecast Prices as of December 31, 2006
Total Reserves


	Future Net Revenue Before
	Income Taxes and
	Discounted at 10%


Reserves Category	Canada $MM	Oklahoma $MM	Wyoming $MM	Total $MM
Proved
Light and Medium Crude Oil⁽¹⁾	75	67	-	142
Heavy Oil	10	--	-	10
Natural Gas	95	241	2	339
Total⁽²⁾	180	308	2	490

Proved Plus Probable
Light and Medium Crude Oil⁽¹⁾	101	68	-	168
Heavy Oil	13	-	-	13
Natural Gas	126	258	7	391
Total⁽²⁾	240	326	7	573

(a)

Including by-products

(b)

Excludes ARTC.

Pricing Assumptions⁽¹⁾Constant Prices and Costs


		Edmonton	Bow River	Cromer	U.S.	U.S.	Alberta	NGL	U.S./CAN
	WTI at	Par Price	Medium	Medium	Henry Hub	Actual	Average	FOB	Exchange
Year	Cushing	40°API	25°API		Gas Price	Gas Price	Plant gate Price	Edmonton	Rate
	[$US/bbl]	[$Cdn/bbl]	[$Cdn/bbl]	[$Cdn/bbl]	$US/MMBtu	$US/MMBtu	[$Cdn/MMBtu]	[$Cdn/bbl]	$US/$Cdn
2006(Year end)	61.05	67.06	49.66	58.96	5.634	7.26	5.93	48.1	0.87
(1) Pricing assumptions are the same for the Haas Report, the MHA Report and the McDaniel Report.

Pricing Assumptions
Forecast Prices and Costs

Summary of Price Forecasts

January 1, 2007


Year	WTI Crude Oil $US/bbl	Edmonton Light Crude Oil $C/bbl	Alberta Bow River Hardisty Crude Oil $C/bbl	Alberta Heavy Crude Oil $C/bbl	Sask Cromer Medium Crude Oil $C/bbl	Edmonton NGL $/bbl	U.S. Henry Hub Gas Price $US/MMBtu	Alberta Average Plantgate $C/MMBtu	Bristish Columbia Average Plantgate $C/MMBtu	Inflation %	U.S./Can Exchange Rate $US/$CAN
	(1)	(2)	(3)	(4)	(5)	(6)

2007	62.50	70.80	49.30	39.20	62.20	50.80	7.40	7.00	7.00	2.0	0.870
2008	61.20	69.30	49.60	39.80	60.90	50.10	7.60	7.25	7.25	2.0	0.870
2009	59.80	67.70	49.80	40.20	59.40	49.50	7.95	7.60	7.60	2.0	0.870
2010	58.40	66.10	49.30	40.90	58.00	48.60	8.05	7.70	7.70	2.0	0.870
2011	56.80	64.20	47.90	39.70	56.40	47.60	8.25	7..90	7..90	2.0	0.870

2012	58.00	65.60	48.90	40.60	57.60	48.70	8.50	8.15	8.15	2.0	0.870
2013	59.10	66.80	49.80	41.30	58.70	49.60	8.65	8.30	8.30	2.0	0.870
2014	60.30	68.20	50.80	42.20	59.80	50.60	8.85	8.45	8.45	2.0	0.870
2015	61.50	69.50	51.80	43.00	61.00	51.60	9.00	8.65	8.65	2.0	0.870
2016	62.70	70.90	52.90	43.80	62.20	52.60	9.20	8.80	8.80	2.0	0.870

2017	64.00	72.30	54.00	44.80	63.50	53.70	9.40	9.00	9.00	2.0	0.870
2018	65.30	73.80	55.00	45.70	64.80	54.80	9.55	9.20	9.20	2.0	0.870
2019	66.60	75.30	56.10	46.60	66.10	55.90	9.75	9.35	9.35	2.0	0.870
2020	67.90	76.80	57.20	47.50	67.40	57.00	9.95	9.55	9.55	2.0	0.870
2021	69.30	78.30	58.40	48.50	68.80	58.20	10.15	9.75	9.75	2.0	0.870

Thereafter	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	2.0	0.870

(a)

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

(b)

Edmonton Light Sweet 40 degrees API/0.3% sulphur

(c)

Bow River at Hardisty Alberta (Heavy stream)

(d)

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

(e)

Midale Cromer crude oil 29 degrees API/2.0% sulphur

(f)

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

(g)

Pricing assumptions are McDaniels January 1, 2007 forecast

(h)

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

Reserves Reconciliation

Reconciliation of Net Reserves by Product Type
As of December 31, 2006
Forecast Prices and Costs


	Light and Medium Crude Oil			NGL
	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
Opening balance - December 31, 2005	3,215.7	985.4	4,201.1	985.7	366.9	1,352.6
Extensions	-	-	-	-	-	-
Technical revisions	1,014.9	131.7	1,146.6	(523.4)	(249.2)	(772.6)
Acquisitions	27.0	6.2	33.2	277.1	114.8	391.9
Dispositions	(334.6)	(118.8)	(453.4)	(67.8)	(40.7)	(108.5)
Production	(1,009.7)	-	(1,009.7)	(1,46.7)	-	(1,46.7)
Closing balance - December 31, 2006	2,913.3	1,004.5	3,917.8	524.8	191.9	716.7

UNITED STATES
OKLAHOMA (Haas Report)
Opening balance - December 31, 2005	-	-	-	-	-	-
Extensions	2.0	1.8	3.7	-	-	-
Technical revisions	(615.4)	(20.0)	(635.3)	-	-	-
Acquisitions	2,232.7	181.8	2,414.5	-	-	-
Dispositions	-	-	-	-	-	-
Production	(179.4)	-	(179.4)	-	-	-
Closing balance - December 31, 2006	1,440.0	163.6	1,603.5	-	-	-

WYOMING (MHA Report)
Opening balance - December 31, 2005	-	-	-	-	-	-
Extensions	-	-	-	-	-	-
Technical revisions	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Production	-	-	-	-	-	-
Closing balance - December 31, 2006	-	-	-	-	-	-

AGGREGATE
Opening balance - December 31, 2005	3,215.7	985.4	4,201.1	985.7	366.9	1,352.6
Extensions	2.0	1.8	3.7	-	-	-
Technical revisions	399.5	111.8	511.3	(523.4)	(249.2)	(772.6)
Acquisitions	2,259.7	188.0	2,447.7	277.1	114.8	391.9
Dispositions	(334.6)	(118.8)	(453.4)	(67.8)	(40.7)	(108.5)
Production	(1,189.1)	-	(1,189.1)	(146.7)	-	(146.7)
Closing balance - December 31, 2006	4,353.3	1168.1	5,521.3	524.8	191.9	716.7

Reconciliation of Net Reserves by Product Type
As of December 31, 2006
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
Opening balance - December 31, 2005	33,126.4	11,715.5	44,841.9	1,145.8	364.1	1,509.9
Extensions	-	-	-	-	-	-
Technical revisions	(1,674.3)	(3,169.7)	(4,844.0)	(103.5)	(128.3)	(231.8)
Acquisitions	2,558.4	3,990.7	6,549.1	102.3	37.0	139.3
Dispositions	(4,877.9)	(2,042.9)	(6,920.7)	-	-	-
Production	(5,474.0)	-	(5,474.0)	(185.5)	-	(185.5)
Closing balance - December 31, 2006	23,658.6	10,493.7	34,152.3	959.1	272.8	1,231.9

UNITED STATES
OKLAHOMA (Haas Report)
Opening balance - December 31, 2005	-	-	-	-	-	-
Extensions	2,560.0	2,623.7	5,183.7	-	-	-
Technical revisions	(6,539.4)	1,623.4	(4,916.0)	-	-	-
Acquisitions	54,461.6	3,477.6	57,939.3	-	-	-
Dispositions	-	-	-	-	-	-
Production	(6,834.5)	-	(6,843.5)	-	-	-
Closing balance - December 31, 2006	43,647.7	7,724.7	251,372.4	-	-	-


WYOMING (MHA Report)
Opening balance - December 31, 2005	1,601.0	101.0	1,702.0	-	-	-
Extensions	-	-	-	-	-	-
Technical revisions	(341.3)	1,418.0	1,076.7	-	-	-
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Production	(452.7)	-	(452.7)	-	-	-
Closing balance - December 31, 2006	807.0	1,519.0	2,326.0	-	-	-

AGGREGATE
Opening balance - December 31, 2005	34,727.4	11,816.5	46,543.9	1,145.8	364.1	1,509.9
Extensions	2,560.0	2,623.7	5,183.7	-	-	-
Technical revisions	(8,555.1)	(128.2)	(8,683.3)	(103.5)	(128.3)	(231.8)
Acquisitions	57,020.0	7,468.3	64,488.3	102.3	37.0	139.3
Dispositions	(4,877.9)	(2,042.9)	(6,920.7)	-	-	-
Production	(12,761.2)	-	(12,761.2)	(185.5)	-	(185.5)
Closing balance - December 31, 2006	68,113.3	19,737.4	87,850.7	959.1	272.8	1,231.9

Reconciliation of Changes in
Net Present Values of Future Net Revenue
Discounted at 10% Per Year
Proved Reserves
Constant Prices and Costs

2006 ($M)

Canadian

U.S.

Aggregate

Estimated Future Net Revenue at Beginning of Year After Tax, December 31, 2005

283,965

2,812

286,777

Oil and Gas Sales During the Period Net of Royalties and Production Costs

(88,488)

(46,702)

(135,190)

Changes due to Prices

(71,844)

(1,001)

(72,845)

Actual Development Costs During the Period

17,883

7,735

25,618

Changes in Future Development Costs

(17,906)

(11,183)

(29,089)

Changes Resulting from Extensions, Infill Drilling and Improved Recovery

9,695

Changes Resulting from Discoveries

Changes Resulting from Acquisitions of Reserves

25,405

130,291

155,696

Changes Resulting from Dispositions of Reserves

(25,672)

Accretion of Discount

28,397

281

28,678

Other Significant Factors

Net Changes in Income Taxes

47,917

(8,231)

39,686

Changes Resulting from Technical Reserves Revisions Plus Effects of Timing

(47,326)

47,615

289

Estimated Future Net Revenue at End of Year After Tax, December 31, 2006

152,330

131,313

$ 283,643

Undeveloped Reserves

Our undeveloped reserves were estimated by McDaniels 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 Ferrier, Halkirk, Desan and Cummings Y Unit assets. Canadian proved undeveloped reserves of 2.2 Bcf of natural gas and 29.5 Mbbl of NGL and 110.6 Mbbl of oil represent 5% of the total Canadian proved reserves on a boe basis. In Desan, 6 development wells are planned for 2007/2008 to develop 1.9 Bcf of natural gas and 12.8 Mbbl of NGL (proven plus probable reserves are 5.6 Bcf and 37.9 Mbbl). In the Cummings Y Unit, continued development and optimization of the water flood will develop 83.9 Mbbl or 17% of the Trust’s proved undeveloped reserves with an additional 83.9 Mbbl of probable reserves.

In Oklahoma, there are proved undeveloped reserves of 9.2 Bcf of natural gas and 318.7 Mbbl of oil representing 17% of the total Oklahoma proved reserves and probable undeveloped reserves of 4.6 Bcf of natural gas and 89.0 Mbbl of oil representing 47% 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.

Significant Factors or Uncertainties Affecting Reserves Data

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

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

Future Development Costs

The table below sets out the development costs deducted in the estimation of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only). Note: all future development costs are associated with Canadian assets; there are no future development costs associated with our U.S. assets.


	Constant Prices and Costs				Forecast Prices and Costs
	Proved Reserves				Proved Reserves				Proved Plus Probable Reserves
	Canada (M$)	Oklahoma (M$)	Wyoming (M$)	Total (M$)	Canada (M$)	Oklahoma (M$)	Wyoming (M$)	Total (M$)	Canada (M$)	Oklahoma (M$)	Wyoming (M$)	Total (M$)
Remaining 2007	2,082	-	-	2,082	2,123	-	-	2,123	2,272	-	-	2,272
2008	5,400	-	-	5,400	5,618	-	-	5,618	11,236	-	-	11,236
2009	-	-	-	-	-	-	-	-	-	-	-	-
2010	-	-	-	-	-	-	-	-	-	-	-	-
2011	200	-	-	200	221	-	-	221	221	-	-	221
Remaining Years	38	-	-	38	45	-	-	45	325	-	-	325
Total Undiscounted	7,720	-	-	7,720	8,007	-	-	8,007	14,054	-	-	14,054
Total discounted at 10% per year	6,812	-	-	6,812	7,058	-	-	7,058	12,170	-	-	12,170

Common Infrastructure Costs

Under the farm-in arrangement with Petroflow in Oklahoma, Petroflow 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.


	Constant Prices and Costs				Forecast Prices and Costs
	Proved Reserves				Proved Reserves				Proved Plus Probable Reserves
	Canada (M$)	Oklahoma (M$)	Wyoming (M$)	Total (M$)	Canada (M$)	Oklahoma (M$)	Wyoming (M$)	Total (M$)	Canada (M$)	Oklahoma (M$)	Wyoming (M$)	Total (M$)
Remaining 2007	-	3,448	-	3,448	-	3,448	-	3,448	-	3.448	-	3,448
Remaining Years	-	-	-	-	-		-		-	-	-	3,448
Total Undiscounted	-	3,448	-	3,448	-	3,448	-	3,448	-	3,448	-	3,448
Total discounted at 10% per year	-	3,135	-	3,135	-	3,135	-	3,135	-	3,135	-	3,135

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 2007 capital program with internally generated cash flow.

Oil and Gas Properties

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

Clair, Alberta

The Clair property is located 7 miles north of Grande Prairie, Alberta. Our assets include a 100% working interest in 3,520 acres of land, 23 producing oil wells, 7 injection wells and an oil treating facility. Gas is conserved and processed at the Zenas 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. One additional dually completed Charlie Lake and Halfway gas well also produces. At December 2006 there were 23 oil wells and one gas well producing a combined 1,226 bbl/d of oil and 1,048 Mcf/d of raw solution gas on a working interest basis before royalties. To date, we

have drilled or re-completed 29 wells for oil and 7 wells for water injection. There are no further drilling plans for the pool. The pool is currently under waterflood to optimize the recovery of hydrocarbons.

McDaniel assigned proved plus probable reserves to the Doe Creek ‘A’ (Dunvegan) pool of 1,022 Mbbl of crude oil, 905 MMcf of gas and 66 Mbbl of NGL, as of December 31, 2006. Included in the total net proved reserves of Clair are reserves assigned to the 13-07-073-5W6 Charlie Lake/ Halfway gas well of 196 MMcf of gas and 14 Mbbl of NGL.

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. Our assets include an average working interest of 66% in 53,120 gross acres of land as well as 371 producing oil and gas wells.

Production is obtained primarily from the Dina, Cummings and Belly River formations. Average production for December, 2006 was 1,312 bbl/d of oil and NGL and 1,051 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.

In 2005 and 2006 we and our partners drilled 21 oil wells in the Cummings Y Unit to bring the total number of oil producers to 42, including 5 water injectors. In order to lower operating costs and improve reserve recovery from the Cummings Y pool, we constructed a central facility to ship clean oil and re-inject produced water into the pool. Field performance improvements are expected to result from continued implementation of water flood in 2007.

We continue to look for field rationalization and development opportunities to improve the financial performance for this area. As part of this program, we divested our Hansman Lake property during the first half of 2006. We have also identified 10 to 15 step out development well locations that we expect to pursue.

McDaniel assigned proved plus probable reserves in the Provost-Alliance-Wainwright area of 2,438 Mbbl of oil, 2,060 MMcf of natural gas and 38 Mbbl of NGL, as of December 31, 2006.

Brooks Area

The Brooks area includes oil and gas producing assets at Princess and Tide Lake. Our working interest in the Princess property is 54% in 22,780 acres. Production is primarily from the Sunburst and Pekisko formations. Sunburst production consists of gas and 23° API crude oil. The Pekisko production consists of gas and 27°API crude oil. We also have an average working interest of 50% in 2,560 acres in the Tide Lake area. Production for December 2006 in Brooks was 571 bbl/d of crude oil and NGL and 1,446 Mcf/d of natural gas.

McDaniel assigned total proved plus probable remaining reserves in the Brooks area of 655 Mbbl of crude oil, 2,010 MMcf of natural gas and 19 Mbbl of NGL as of December 31, 2006.

Sylvan Lake

The Sylvan Lake property is located 24 miles west of the town of Red Deer, Alberta. Our assets include an average working interest of 74% in 3,345 gross acres of land as well as 25 producing oil wells. We

completed the development of 40-acre spacing wells in the Pekisko G pool, and drilled four subsequent oil wells on 20 acre spacing. Production for December 2006 was 451 bbl/d of 14˚API crude oil and NGL with 495 Mcf/d of associated natural gas. Production is flow-lined into an operated central treating facility. Non-associated gas is conserved and flow-lined to the Husky Sylvan Lake gas plant. Clean oil is trucked from the facility to sales.

McDaniel has assigned total proved plus probable reserves of 993 Mbbl of crude oil, 940 MMcf of natural gas and 56 Mbbl of NGL, as of December 31, 2006. Studies are being undertaken to optimize the water flood of the field and to improve oil recovery.

Ricinus-Ferrier, Alberta

The Ricinus-Ferrier property is located in West Central Alberta. The productive horizons are multi-zone liquids rich natural gas formations at depths ranging from 2,400 meters to 2,800 meters. The majority of the area has year round access for drilling, seismic and construction projects. The area is mainly developed at two wells per section for gas and four wells per section for oil. We own infield compression and dehydration facilities and pipelines in proportion to our well interests. The raw gas is processed at third party processing facilities to remove NGL, as of July 1, 2006.

We have interests varying from 3.65% to 94.8% in 88 sections of land. Production for December 2006 was 7.0 MMcf/d of natural gas and 242 bbl/d of crude oil and NGL.

McDaniel assigned total proved plus probable reserves in the Ricinus-Ferrier area of 15.4 Bcf of natural gas and 629 Mbbls of crude oil and NGL as of December 31, 2006.

Within the Ricinus area, we have a 50% interest in a deep, prolific Leduc well which began production in August 2006. McDaniel assigned proved plus probable gas reserves of 4.3 Bcf of natural gas to this well. One or two additional drill targets of a similar nature may exist on our lands.

Desan, British Columbia

The Desan property is located approximately 75 miles North East of Fort Nelson, British Columbia. The property is in the center of a well-established gas-producing region commonly referred to as Greater Sierra. The majority of the drilling, seismic and project construction is carried out during the winter months. We are the operator of the property. The primary producing formation is the regional Jean Marie trend, at 1,300 meters, that is being developed with horizontal well bores. Our average net production for this region for December 2006 was 8.0 MMcf/d of natural gas and 52 bbls/d of crude oil and NGL produced from a total of 24 wells.

We expect to acquire 28 square kilometres (11 square miles) of 3-D seismic in the Desan area, as well as purchase additional seismic in the Peggo-Pesh and Sierra areas. Pending drilling rig availability, we may re-enter an existing well to drill a new horizontal lateral. With a greater technical understanding of the Jean Marie play gained through additional seismic, we expect to undertake a more extensive drilling program next winter.

McDaniel assigned total proved plus probable reserves of 22.6 Bcf of natural gas and 154 Mbbl of NGL to the Desan property, as of December 31, 2006.

We also have approximately 70,880 net acres of undeveloped land at Desan and nearby similar properties at Kotcho and Peggo-Pesh.

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 2006 was approximately 258 boe/d from the property near Gillette, Wyoming. Several developing exploitation and exploration plays are located in various parts of the basin. We also hold a significant acreage position in the Oyster Ridge area of South West Wyoming. Some 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 77,000 gross developed and undeveloped acres of land, with an average working interest of 89% at year end 2006, centered in Grant, Lincoln and Logan Counties. The key producing horizon is the Hunton formation. The Hunton formation is a carbonate rock formation which has been largely ignored by the industry because of the high water/hydrocarbon production ratio. Over the last decade, new drilling and production techniques have enabled the profitable development of hydrocarbon production from the Hunton formation. Extensive dewatering lowers pressure allowing the liberation and mobilization of oil and gas from smaller rock pores. In our experience, total gross peak hydrocarbon production rates averaged 150 boe/d per horizontal well within six months after drilling and tie-in. The average proved plus probable reserves are 290,000 boe per horizontal well.

Our average production for 2006 in Oklahoma was 23.4 MMcf/d of natural gas and 614 bbl/d of crude oil and NGL. Haas attributed total proved and probable reserves of 1,999 Mbbl of crude oil and NGL and 63.9 Bcf of natural gas to this area as of December 31, 2006, resulting in a RLI of 7.0 years. December 2006 rates were 25.7 MMcf/d and 701 bbl/d oil. Operating costs on our properties averaged $7.64/boe during 2006. We maintain a fully staffed field office in Carney, Oklahoma about 50 miles North East of Oklahoma City. Our staff complement as of December 31, 2006 is 37 people including a Chief Operating Officer, a Chief Financial Officer, a land manager, and full operational, technical and accounting support.

We have approximately 42,223 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, which we are developing with our strategic partner, Petroflow.

Under a farmout agreement, Petroflow pays 100% of the costs of drilling and completing each well to earn a 70% working interest. The farmout requires Petroflow to drill not less than 30 wells by the end of 2007 and not less than 30 wells during any twenty-month period thereafter. To date, Petroflow is on track to meet that commitment and has spudded 15 wells plus the drilling of 2 salt water disposal wells, with two rigs under contract and a third to be added in July, 2007. We pay 100% of the costs of drilling the required water disposal wells and associated infrastructure, but recover 100% of those costs plus interest over a 3-year period through processing fees charged to Petroflow. We operate all production and have a right of first refusal to purchase Petroflow’s production at a price based on a third-party engineering evaluation.

In Oklahoma, we have identified numerous opportunities to build on our considerable presence and exploit our competitive advantage, including potential acquisitions ranging in size from 250 to 1,000 boe/d. In addition to our portfolio of exploitation and development drilling locations targeting the Hunton formation, we believe our Oklahoma property has significant long-term potential to produce natural gas from the Woodford shale formation, both under our developed lands (held by production in the Hunton), and undeveloped lands.

Oil and Gas Wells

The following table summarizes our interest as at December 31, 2006 in wells that are producing and non-producing:


		Producing				Non Producing
Country	State/ Province	Oil		Gas		Oil		Gas		Grand Total
Country	State/ Province	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Canada	Alberta	454.0	310.0	215.0	74.0	352.0	275.0	122.0	66.0	1143.0	725.0
	British Columbia			26.0	26.0					26.0	26.0
	Total	454.0	310.0	241.0	100.0	352.0	275.0	122.0	66.0	1169.0	751.0
U.S.	Oklahoma			136.0	106.2			16.0	12.4	152.0	118.6
	Wyoming			103.0	79.3			187.0	92.9	290.0	172.1
	Total			239.0	185.5			203.0	105.3	442.0	290.7
Total		454.0	310.0	480.0	285.5	352.0	275.0	325.0	171.3	1611.0	1041.7

Land Holdings

The following table summarizes the gross and net acres of unproved properties in which Enterra has an interest at December 31, 2006:


Area	Gross Acres	Net Acres
Canada	361,769	218,421
U.S.	284,557	179,898
Total	646,326	398,319

The number of net acres in our portfolio that will expire over the upcoming year without further drilling or other action is 55,000 acres in Canada and 8,000 acres in the United States.

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 remediating 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 provide 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. Under 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.

We expect to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed. In 2005 and 2006, expenditures beyond normal compliance with environmental regulations were not material. Late in 2006 and into early 2007, we incurred a significant expense in the remediation of the land surrounding a small pipeline leak. While the failure that did occur in late 2006 was small, other spills by previous owners of this property resulted in significant salt water contamination of the soil. There was also an abandoned flare pit in the area adjacent to the salt water contamination. This flare pit had been abandoned many years ago by a previous owner, but the site had not been reclaimed and was contaminated with old drill cuts, crude oil, among other substances. We spent approximately $1 million in total for the reclamation of these combined areas. Beyond this specific site, we do not anticipate making any material expenditures 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 of which a total of $2.1 million is estimated beyond that discussed above to be incurred in 2007, 2008 and 2009 to abandon approximately 119 wells.

Tax Horizon

Canadian

Current tax expense of $1.3 million relates to income taxes of $1.0 million resulting from the High Point group of assets for the taxation period ended August 17, 2005. The remainder of $0.3 million relates to under-accrual of capital taxes prior to 2006. Under the current structure, otherwise taxable income of the Canadian Operating Subsidiaries is sheltered through interest expense and other current deductions. Cash is transferred to the Trust by way of interest and redemptions of securities to the Trust. The Trust in turn, allocates all of its taxable income to the unitholders. No Canadian income taxes are currently expected to be incurred by the Trust or its Canadian Operating Subsidiaries in 2007.

United States

No U.S. income related cash taxes have been paid by the Trust or its U.S. Operating Subsidiaries for the year ended December 31, 2006. 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, 2006:


		(000’s)
	Canada		United States	Total
Property acquisition costs⁽¹⁾
Proved properties	$25,621		$332,290	$357,911
Unproved properties	$6,736		$26,384	$33,120
Exploration costs	-		-	-
Development costs	$17,883		$7,735	$25,618
Total costs incurred	$50,240		$366,409	$416,649

(a)

Includes costs related to corporate acquisitions.

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, 2006. We did not participate in any exploration wells during 2006. In the farm in arrangement with Petroflow in Oklahoma, we have had no interest in dry holes and have a carried interest in producing wells. In Wyoming we participate in 20 coal-bed methane pilot wells. The carried interest in the producing wells is shown as participated 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	9	1.5	-	-	9	1.5
Natural Gas	19	4.3	15	5.8	34	10.1
Coal-bed Methane	-	-	20	10	20	10
Service	-	-	2	1.5	2	1.5
Dry	-	-	-	-	0	0
Total	28	5.8	37	17.3	65	23.1

Production Volume by Field

The following table discloses for each important field, and in total, the Trust’s production volumes for the financial year ended December 31, 2006 for each product type.


	Crude oil (bbls)	NGL (bbls)	Natural Gas (Mcf)	boe
Clair	523,823	23,319	595,241	646,349
Provost	331,459	5,633	111,372	355,654
Brooks	181,008	4,930	396,088	251,953
Sylvan Lake	165,383	9,624	161,229	201,879
Desan	5,844	8,702	2,569,051	442,721
Ferrier/Ricinus	50,060	122,612	2,521,391	592,904
Other Canadian	208,940	5,240	362,174	274,542
Wyoming	-	-	565,850	94,308
Oklahoma	224,270	-	8,543,187	1,648,135
Total	1,690,787	180,060	15,825,583	4,508,445

Production Estimates

The following table discloses, for each product type, the total volume of production estimated by McDaniel Haas and MHA for 2007 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 2007 Production Estimated
Forecast Prices and Costs


		Light and Medium Crude Oil	Heavy Oil	NGL	Natural Gas	Total
Reserves Category		Gross (bbl/d)	Gross (bbl/d)	Gross (bbl/d)	Gross (Mcf/d)	Gross (boe/d)

CANADA (McDaniel Report)
Proved
	Producing	2,564	526	387	17,104	6,326
	Non-Producing	26	-	6	444	106
	Undeveloped	52	-	10	174	91
Total Proved		2,642	526	403	17,722	6,523
Probable		150	10	20	654	289
Total Proved plus Probable		2,791	536	423	18,376	6,812

OKLAHOMA (Haas Report)
Proved
	Producing	800	-	-	24,395	4,865
	Non-Producing	15	-	-	240	55
	Undeveloped	38	-	-	848	180
Total Proved		852	-	-	25,483	5,100
Probable		47	-	-	1,649	322
Total Proved plus Probable		900	-	-	27,132	5,422

WYOMING (MHA Report)
Proved
	Producing	-	-	-	1,117	186
	Non-Producing	-	-	-	-	-
	Undeveloped	-	-	-	-	-
Total Proved		-	-	-	1,117	186
Probable		-	-	-	838	140
Total Proved plus Probable		-	-	-	1,955	326

United States
Proved
	Producing	800	-	-	25,512	5,052
	Non-Producing	15	-	-	240	55
	Undeveloped	38	-	-	848	180
Total Proved		852	-	-	26,600	5,286
Probable		47	-	-	2,487	462
Total Proved plus Probable		900	-	-	29,087	5,747

AGGREGATE
Proved
	Producing	3,363	526	387	42,616	11,378
	Non-Producing	41	-	6	684	161
	Undeveloped	90	-	10	1,022	270


Total Proved	3,494	526	403	44,322	11,809

Probable	197	10	20	3,141	750
Total Proved plus Probable	3,691	536	423	47,463	12,559

Quarterly Data

The following table discloses, on a quarterly basis for the year ended December 31, 2006, 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 2006
	March 31	June 30	September 30	December 31
Average Daily Production
Oil (bbl/d)	4,722	4,697	4,724	4,388
NGL (bbl/d)	547	545	497	386
Natural Gas (Mcf/d)	28,773	54,582	47,094	42,788
Combined (boe/d)	10,064	14,339	13,070	11,905

Average Prices Received
Oil ($/bbl)	56.89	69.17	66.74	56.83
NGL ($/bbl)	44.90	55.23	57.99	57.65
Natural Gas ($/Mcf)	8.47	6.77	7.47	8.82

Netback
Revenues – combined ($/boe)	52.67	51.59	60.99	51.17
Royalties – combined ($/boe)	11.00	11.33	10.26	10.22
Operating Expenses – combined ($/boe)	9.18	8.22	11.43	19.28
Netback Received - combined ($/boe)	32.49	32.04	39.30	21.67

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. Each Trust Unit entitles the holder thereof to one vote at any meeting of the holders of Trust Units and represents an equal fractional undivided beneficial interest in any distribution from the Trust (whether of net income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding up of the Trust. All Trust Units rank among themselves equally and ratably without discrimination, preference or priority. Each Trust Unit is transferable, is not subject to any conversion or pre−emptive rights and entitles the holder thereof to require the Trust to redeem any or all of the Trust Units held by such holder. See “Capital Structure - Redemption Right”). In addition, in certain circumstances unitholders will have the right to instruct the trustees of EECT with respect to the voting of common shares of EEC held by EECT at meetings of holders of common shares of EEC. See “Capital Structure - Meetings of unitholders”.

The price per Trust Unit is a function of anticipated distributable income generated by the Trust and the ability of the Trust to effect long−term growth in the value of the Trust’s assets. The market price of the Trust Units is sensitive to a variety of market conditions including, but not limited to, interest rates, commodity prices and our ability to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units.

The Trust Units do not represent a traditional investment and should not be viewed by investors as “shares” in either Trust or the Trust Subsidiaries. Unitholders do not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions.

The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation, as it does not carry on or intend to carry on the business of a trust company.

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.

Debentures

The Debentures were issued under a debenture trust indenture (the “Debenture Indenture”) dated as of November 21, 2006 among the Trust, EEC and Olympia Trust Company (the “Debenture Trustee”). An unlimited number of Debentures are authorized for issue. The Debentures are dated as of November 21, 2006 and were issuable only in denominations of $1,000 and integral multiples thereof. The maturity date for the Debentures is December 31, 2011. The Debentures bear interest from the date of issue at 8.0% per annum, which is payable semi-annually in arrears on June 30 and December 31 in each year, commencing June 30, 2007.

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”.

The 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 per Trust Unit, being a conversion rate of 108.1081 Trust Units for each $1,000 principal amount of Debentures. Holders converting their Debentures will receive all accrued and unpaid interest thereon in cash to the date of conversion.

Redemption and Purchase

Our Debentures are not redeemable on or before December 31, 2009. On or after January 1, 2010 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, on or before December 31, 2010, at a Redemption Price of $1,050 per debenture and on or after January 1, 2011 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. The 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.

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 the 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.

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”).

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 the 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.

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, the 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.

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.

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 waived 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.

Enterra US Acqco Exchangeable Shares

On June 1, 2006, all Enterra US Acqco Exchangeable Shares then-outstanding were automatically redeemed. On and after June 1, 2006, the rights of former holders of Enterra US Acqco 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 Enterra US Acqco Exchangeable Shares outstanding.

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 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.

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 May 2006 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 every subsequent three years. 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.

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, 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, advisor 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, advisor 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, advisor 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 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: (i) 90% of the “market price” of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Trust Units are tendered to the Trust for

redemption; and (ii) the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are so tendered for redemption. Where more than one market exists for the Trust Units, the principal market shall mean the market on which the Trust Units experience the greatest volume of trading activity on the date or for the period in question, as applicable.

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 Notes 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 in 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.

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.

Restriction on the Trustee’s Powers

Our Trustee is prohibited from authorizing or approving:

(i)

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;

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

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:

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;

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;

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;

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

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

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 broadened 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. See “Restrictions on the Trustee’s Powers”. Our Trust Indenture permits certain amendments by our Trustee without the approval of unitholders, namely:

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

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;

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;

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;

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;

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

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, retirement 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 consolidated 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 registered unitholders and the unaudited interim consolidated financial statements of the Trust will be mailed to registered unitholders within the periods prescribed by securities legislation. The year-end of the Trust is December 31. The Trust is subject to the continuous disclosure obligations under all applicable securities legislation.

The Trust is subject to the reporting requirements of the 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.

MARKET FOR SECURITIES

Trading Price and Volume

Our Trust Units are listed on the Toronto Stock Exchange (ENT.UN) and the New York Stock Exchange (ENT). Prior to February 9, 2006, the date our Trust Units commenced trading on the New York Stock Exchange, our Trust Units were listed on the NASDAQ under the symbol “EENC”. The following table sets forth the price range and trading volume of our Trust Units as reported by the TSX and the NYSE/NASDAQ for the periods indicated:


	TSX			NYSE/NASDAQ
	High ($)	Low ($)	Volume (000’s)	High (US$)	Low (US$)	Volume
2006
January	22.46	19.05	434,976	19.50	16.48	5,911,700
February	21.89	19.50	287,919	19.10	17.02	3,944,200
March	21.03	15.28	787,545	18.60	13.05	6,947,600
April	18.40	13.85	956,060	15.93	11.72	7,872,300
May	17.23	14.87	574,134	15.55	13.48	4,274,300
June	15.65	13.25	607,537	14.20	12.25	3,507,200
July	15.95	12.52	548,447	13.98	11.76	3,350,200
August	13.94	12.29	610,648	12.30	11.01	3,443,300
September	13.11	10.23	529,540	11.20	9.13	4,978,700
October	10.76	8.57	2,477,613	9.72	7.51	6,168,700
November	11.90	7.75	12,047,753	10.20	6.78	5,894,900
December	10.30	8.94	1,564,946	9.01	7.67	6,772,800
2007
January	9.68	7.82	1,861,213	8.25	6.67	4,917,600
February	8.51	7.25	1,146,700	7.23	6.22	3,050,600
March⁽¹⁾	7.44	5.76	604,863	6.34	4.88	9,962,880

(a)

Information to March 23, 2007.

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


	TSX
	High ($)	Low ($)	Volume
2006
November⁽¹⁾	121.00	107.00	522,340
December	110.00	100.00	121,840
2007
January	104.25	98.00	59,790
February	101.00	93.00	78,890
March⁽²⁾	99.00	94.50	55,830

(a)

From November 20, 2006.

(b)

Information to March 23, 2007.

DISTRIBUTIONS

We make cash distributions on the 15th day of each month or the first business day thereafter to unitholders of record on the immediately preceding distribution record date (or such other payment and/or record date as may be determined by the Trustee on the recommendation of the Board). We currently have set the level of monthly cash distributions at US$0.06 per Trust Unit.

The following table sets forth the amount of monthly cash distributions per Trust Unit that we have declared since our inception. The distributions we declare are currently denominated in U.S. dollars.


Month of record (US$)	2007		2006		2005		2004		2003
January	$	0.06	$	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			$	0.18	$	0.15	$	0.11
May			$	0.18	$	0.15	$	0.11
June			$	0.18	$	0.16	$	0.12
July			$	0.12	$	0.16	$	0.12
August			$	0.12	$	0.16	$	0.12
September			$	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^(a)

(a)

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

GOVERNANCE

Delegation of Authority, Administration and Trust Governance

The Board 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 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.

Directors and Officers

The Board currently consists of six individuals. The directors are elected by EECT at the direction of unitholders by ordinary resolution, and hold office until the next annual meeting of unitholders, currently scheduled for June 14, 2007.

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


Name and Municipality of Residence	Position Held	Date First Elected or Appointed
R. H. Joe Vidal^{(1),(2),(4), (5)*} Saskatoon, Saskatchewan	Director and Chairman of the Board	2006
E. Keith Conrad Calgary, Alberta	Director, President and Chief Executive Officer	2005
Norman W.G. Wallace^{(1),(2), (3)} Saskatoon, Saskatchewan	Director	2003
Peter Carpenter^{(1), (3), (4), (5)} Toronto, Ontario	Director	2006
Roger Giovanetto^{(2), (3)} Calgary, Alberta	Director	2006
W.C. Chip Hazelrig^{(4), (5)} Birmingham, Alabama	Director	2006
Victor Roskey Calgary, Alberta	Senior Vice President and Chief Financial Officer	2006
James (Jim) Tyndall Calgary, Alberta	Senior Vice President Operations and Chief Operating Officer	2006
John F. Reader Calgary, Alberta	Senior Vice President Corporate Development	2005
Kim Booth Edmond, Oklahoma	Vice President and Chief Operating Officer U.S. Operations	2006

(1)

Member of Audit Committee

(2)

Member of Compensation Committee

(3)

Member of Reserves Committee

(4)

Member of Governance and Nominating Committee

(5)

Member of the Special Committee

Denotes Chair

The directors and executive officers of EEC, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 87,058 of our Trust Units, representing approximately 0.15% of our issued and outstanding Trust Units (as of March 1, 2007). Profiles of EEC’s directors and executive officers and the particulars of their respective principal occupations during the last five years are set forth below.

R. H. (Joseph) Vidal, Director and Chairman of the Board

Since 1999, Joseph Vidal has been a senior executive of Bioriginal Food & Science Corp. where he is now President & Chief Executive Officer. He began as Chief Financial Officer at Bioriginal, and was integrally involved in banking relationships, treasury functions and budgeting. Four months after joining Bioriginal, his title was expanded to include Vice President of Operations. Mr. Vidal began his career in public accounting with Peat Marwick, and later was a manager at that firm’s successor, KPMG LLP. Immediately before joining Bioriginal, Mr. Vidal was General Manager of Hitachi Canadian Industries Ltd. where he had senior level responsibility for financial and accounting functions as well as labor and government relations. Mr. Vidal is a Chartered Accountant and holds a Bachelor of Commerce degree from the University of Saskatchewan. Mr. Vidal joined EEC’s Board in April 2006.

E. Keith Conrad, Director, President and Chief Executive Officer

Keith Conrad has over 40 years of business experience, with the last 20 years directly involved with executive management in the oil and gas industry. He has been Chairman of Macon, a private company involved in the management of and investment in private and public companies in the oil and gas industry since 1997. In addition to Macon, Mr. Conrad has been a director or officer of the following companies: Petroflow, Shaker Resources Inc., High Point, Mesquite Exploration Ltd., Draig Energy Ltd., Brigadier Energy Ltd., Serenpet Inc., AM Technologies Limited and Torex Resources Inc. at various times from 1990 to present. Mr. Conrad holds Bachelors of Arts and Law Degrees from the University of Alberta. Mr. Conrad was appointed President & CEO and Director in June 2005.

Norman W.G. Wallace, Director

Norman Wallace has been the owner of Wallace Construction Specialties Ltd. since 1972. He holds a Bachelor of Commerce degree from the University of Saskatchewan. Mr. Wallace joined EEC’s Board in May 2000.

Peter Carpenter, Director

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 in May 2006.

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 in May 2006.

W. Cobb (Chip) Hazelrig, Director

Since graduating university, Chip Hazelrig has been involved in the commercial real estate financing and development business and later became involved in the financing and development of oil and gas projects. Mr. Hazelrig was a founding principal in Altex Resources Inc., as well as a principal in San Antonio Gas and Oil Co. He is President of The Hazelrig Companies, Inc., as well as a director of Southline Steel Industries Inc. and Freeport Steel Co., and is an investor and financer of various other public and private business entities. Mr. Hazelrig joined EEC’s Board in May 2006.

Victor Roskey, Senior Vice President and Chief Financial Officer

Vic Roskey has over 20 years of broad financial experience, including the areas of project finance, investment banking, corporate restructurings, and mergers and acquisitions. He has served as a director of numerous private and public companies, and for the 10 years prior to joining Enterra he managed private equity funds focused on the oil and gas sector, most recently as Managing Director, Private Equity with Scotia Waterous. Mr. Roskey holds a Bachelor of Laws degree from Osgoode Hall Law School. Mr. Roskey joined EEC in June 2006.

James H. (Jim) Tyndall, Senior Vice President Operations and Chief Operating Officer

Jim Tyndall is a Professional Engineer with more than 24 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.

John F. Reader, Senior Vice President 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.

Kim Booth, Vice President and Chief Operating Officer, U.S. Operations

Kim Booth joined EEC in connection with the Trust’s acquisition of producing Oklahoma assets, which conducted business as Altex Resources, Inc. Ms. Booth has been Altex’s CEO since 2001, and has been responsible for managing the land, drilling, production and development activity on the Oklahoma acreage, where more than 130 wells have been drilled. Prior to her appointment as CEO, Ms. Booth was the Operations Manager for Altex Resources. Ms. Booth holds a Bachelor of Science degree in Petroleum Engineering Technology from Oklahoma State University and has been employed in the oil and gas industry for more than 20 years in various engineering, operations and management positions. Ms. Booth joined EEC in March 2006.

Committees

The Board 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 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 and Petroflow as detailed under “Special Committee” below.

Governance and Nominating Committee

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

Compensation Committee

EEC has established a Compensation Committee comprised of 3 non-management members of the Board. The mandate of the Compensation Committee is to review and where appropriate, approve:

overall budget salary increases for employees;

compensation and benefit proposal for officers of EEC, excluding the CEO;

recommendations to the Board regarding compensation of officers other than that the CEO and incentive compensation and equity-based plans that are subject to the approval of the Board;

goals and objectives relevant to CEO compensation; and

compensation disclosure in the information circular.

Reserves Committee

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 evaluator for undertaking each reserves evaluation as the same may be required from time to time;

consider and review the impact of changing independent evaluators; and

review all matters relating to the preparation and public disclosure of estimates of reserves.

Audit Committee

EEC has established an audit committee (the “Audit Committee”) comprised of three members: R.H. Joe Vidal, Peter Carpenter and Norman W.G. Wallace, each of whom is considered “independent” and “financially literate” within the meaning of Multilateral Instrument 52-110 – Audit Committees. Mr. Wallace replaced Mr. Hazelrig on March 22, 2007.

The mandate of the Audit Committee is to satisfy itself on behalf of the Board with respect to the Trust’s internal control systems and to review the quarterly and annual financial statements of the Trust prior to

their submission to the Board for approval. The mandate of the Audit Committee is attached as Appendix “A”.

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


Name of Audit Committee Member	Relevant Education and Experience
R.H. Joe Vidal	Mr. Vidal is the chairman of the Audit Committee. Mr. Vidal is a Chartered Accountant and holds a Bachelor of Commerce degree from the University of Saskatchewan
Peter Carpenter	Mr. Carpenter has been a Senior Partner (Oil and Gas) and Director of financial advisory firm Claridge House Partners, Inc. since 1996.
Norman W.G. Wallace	Norman Wallace has been the owner of Wallace Construction Specialties since 1972. He holds a Bachelor of Commerce degree from the University of Saskatchewan.

External Audit Service Fees

KPMG LLP audited our annual consolidated financial statements for the 2006 and 2005 fiscal years.


(in $ thousands)	2006	2005
Audit fees⁽¹⁾	1,004.4	727.6
Audit-related fees	-	-
Tax fees⁽²⁾	-	40.5
All other fees⁽³⁾	10	-
Total	1,014.4	768.1

Notes:

(b)

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

(c)

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

(d)

All other fees were related to compliance with section 404 of the U.S. Sarbanes-Oxley Act.

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.

Special Committee

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

organize, institute and supervise a process for the development and evaluation of our relationships with Macon and Petroflow and alternatives for the evolution of such relationships (including, without limitation, the amendment, replacement or termination

of one or more arrangements with such entities) in the context of our current circumstances and business plan;

review and consider which, if any, of any and all alternatives as may be proposed is in our best interest and the best interests of the unitholders;

retain, at the expense of EEC, one or more financial advisors for the purpose of assisting the Special Committee in the discharge of its mandate, including (if determined by the Special Committee to be necessary or advisable) an independent financial advisor for the purpose of obtaining a “formal valuation”, within the meaning of the Ontario Securities Commission Rule 61-501 and equivalent provisions of the securities legislation of other provinces, any such financial advisor to be selected, instructed and supervised by the Special Committee; and

report its findings to the Board and make such recommendations as the Special Committee considers appropriate.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

With the exception of the items listed in Appendix “D”, no current 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,

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;

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

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

There are no outstanding legal proceedings or regulatory actions 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.

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 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 directors or officers will be provided to the Trust or the Trust Subsidiaries.

Relationship with JED and JMG

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 if they were exploration properties, and contracted, operated and drilled by JED 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 did not and currently does not own any shares in either JMG or 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 and replaced it with the Joint Services Agreement which provided for the provision of certain limited services as between JED and the Trust.

On September 28, 2006, the Trust terminated the Agreement of Business Principles and amendments thereto, and other related agreements with JED, including the Joint Services Agreement. Concurrent with the termination of the agreements, the Trust settled all amounts owing to JED.

During the term of the Trust’s agreements with JED and JMG, the Chairman of the Trust until March 31, 2006, Reginald 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

Petroflow is one of the Trust’s strategic partners and has farmed into the Trust’s properties in Oklahoma. Mr. Conrad, the President and Chief Executive Officer of EEC, as a founder of Petroflow, through his wholly-owned oil and gas company, Macon, 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 for consideration and 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, remains a significant shareholder of Petroflow owning directly or indirectly approximately 14% of the outstanding common shares. The Board believes that any of the activities undertaken by Mr. Conrad did not and will not interfere, in any material way, with his ability to act with a view to the best interest of either EEC or the Trust.

However, the Board 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, management is required to report on all material matters relating to the business relationship with Petroflow. Day-to-day oversight of the Petroflow farmin, 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 representatives of the Trust, excluding Mr. Conrad.

Relationship with Macon

Mr. Conrad is not our employee. He provides his services as President and Chief Executive Officer of EEC pursuant to a management agreement that we entered into with Macon. Mr. Conrad, through the management agreement with Macon, is eligible to participate in the Trust’s bonus plan, option plan and restricted unit and performance unit incentive plan. Pursuant to the management agreement, we pay fees to Macon in the amount of $33,000 per month and provide office space for approximately 12 employees of Macon during the term of that agreement. Our Special Committee is currently negotiating the termination of the management agreement with Macon, terms of employment with Mr. Conrad and a commitment by Mr. Conrad to deal within 18 months, to the satisfaction with the Board, with the potential conflict of interest relating to Mr. Conrad’s role as President and Chief Executive Officer of EEC and the share position that Macon holds in Petroflow.

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

Other Management and Director Interests

Ms. Kim Booth, our 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 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.

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 “Governance - Delegation of Authority, Administration and Trust Governance”.

Purchase and Sale Agreement among JED, EEC and EPC dated September 13, 2006. See “2006 Property Swap with JED”.

Farmout Agreement between EAC and North American Petroleum Corporation USA dated October 15, 2006. See “Oil and Gas Properties – Oklahoma”.

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”.

Purchase and Sale Agreement between EEC and Frederick G. Wedell dated November 22, 2005. See “General Development of Our Business – Three Year History and Significant Acquisitions – 2006 Acquisition of Oklahoma Assets”.

Purchase and Sale Agreement between EEC and DBS Investments, Ltd. dated November 22, 2005. See “General Development of Our Business – Three Year History and Significant Acquisitions – 2006 Acquisition of Oklahoma Assets”.

Purchase and Sale Agreement between EEC and W. Cobb Hazelrig dated November 22, 2005. See “General Development of Our Business – Three Year History and Significant Acquisitions – 2006 Acquisition of Oklahoma Assets”.

Purchase and Sale Agreement between EEC and Azar Minerals, Ltd. dated November 22, 2005. See “General Development of Our Business – Three Year History and Significant Acquisitions – 2006 Acquisition of Oklahoma Assets”.

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. The Amended and Restated Syndicated Credit Agreement provides our (i) Revolving and Operating Credit Facilities, which are comprised of a $140 million revolving credit facility with a syndicate of lenders, and a $20 million operating facility with the Bank of Nova Scotia as lender, and (ii) Second-Lien Credit Facility, which is a $40 million non-revolving second-lien credit facility with a syndicate of lenders, which has a maturity date of November 20, 2007.

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.

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 discussion and analysis of the Trust for the year ended December 31, 2006.

APPENDIX “A”
AUDIT COMMITTEE MANDATE

Enterra Energy Corp.

Audit Committee Mandate

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.

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;

A-1

(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;

(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.

A-2

(k)

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

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.

A-3

(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.

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.

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.

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(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.

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”

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

To the Board of Directors of Enterra Energy Corp. (the “Company”):

We have evaluated Enterra Energy Corp.’s Canadian reserves data as at December 31, 2006. The reserves data consists of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2006 using constant prices and costs; and

(ii)

the related estimated future net revenue.

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).

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.

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, 2006, and identifies the respective portion hereof that we have evaluated, audited and reviewed and reported on to the Company’s management.


Description and Preparation Data of Audit/ Evaluation/ Review Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate $M)
	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
December 31, 2006	Canada		$239,606		$239,606

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.

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

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

Executed as to our report referred to above.

(signed) “C.B. Kowlaski.”

McDaniel & Associates Consultants Ltd.
Calgary, Alberta

March 30, 2007.

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APPENDIX “B-2”

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

To the Board of Directors of Enterra Energy Corp. (the “Company”):

We have evaluated the Company’s U.S. (Wyoming) reserves data as at December 31, 2006. The reserves data consists of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2006 using constant prices and costs; and

(ii)

the related estimated future net revenue.

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.

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, 2006, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Company’s management.


Description and Preparation Data of Audit/ Evaluation/ Review Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate $MUS)
	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total

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Evaluation of the Natural Gas Reserves Powder River Basin, Wyoming December 31, 2006	U.S.		$6,100		$6,100

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.

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

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

Executed as to our report referred to above.

(signed) “MHA Petroleum Consultants”

MHA Petroleum Consultants
Lakewood, Colorado, U.S.

March 30, 2007.

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APPENDIX “B-3”

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

To the Board of Directors of Enterra Energy Corp. (the “Company”):

We have evaluated the Company’s U.S. (Oklahoma) reserves data as at December 31, 2006. The reserves data consists of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2006 using constant prices and costs; and

(ii)

the related estimated future net revenue.

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.

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, 2006, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Company’s management.


Description and Preparation Data of Audit/ Evaluation/ Review Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate $MUS)
	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
Evaluation of Oil and Natural Gas Reserves of the Hunton Formation in Oklahoma December 31, 2006	U.S.		$211,065		$211,065

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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.

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

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

Executed as to our report referred to above.

(signed) “Haas Petroleum Engineering Services, Inc.”

Haas Petroleum Engineering Services, Inc.
Dallas, Texas

March 30, 2007.

B-11

APPENDIX “C”

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVE DATA AND OTHER INFORMATION

Management of Enterra Energy Corp. (the “Company”), as administrator of Enterra Energy Trust (the “Trust”), is responsible for the preparation and disclosure of information with respect to the Trust’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2006 using constant prices and costs; and

(ii)

the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Trust’s reserves data. The report of the independent qualified reserves evaluator is presented in the Annual Information Form for Enterra Energy Trust effective December 31, 2006.

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

(a)

reviewed the Trust’s procedures for providing information to the independent qualified reserves evaluator;

(b)

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

(c)

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

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

(a)

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

(b)

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

(c)

the content and filing of this report.

C-1

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

/s/ Keith Conrad

E. Keith Conrad
President, Chief Executive Officer

/s/ Victor Roskey

Victor Roskey
Senior Vice President and Chief Financial Officer

/s/ Roger Giovanetto

Roger Giovanetto
Director

/s/ Peter Carpenter

Peter Carpenter

Director

March 30, 2007

C-2

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. Roskey:

Mr. Roskey represented Citibank Canada on the board of Money’s Mushrooms Ltd. until approximately July 2000. In November 2000, its U.S. operation, Money’s Foods U.S. Inc., filed for Chapter 11 protection.

D-1