Annual Information Form

For the year ended December 31, 2009

March 29, 2010

TABLE OF CONTENTS

GENERAL INFORMATION 

Glossary 

Abbreviations, Conventions and Conversions 

Note Regarding Forward-Looking Statements 

STRUCTURE AND ORGANIZATION OF ENTERRA ENERGY TRUST 

Enterra Energy Trust 

Enterra Energy Commercial Trust 

Enterra Energy Corp. 

Enterra Production Partnership 

Enterra Energy Partner Corp. 

Enterra US Acquisitions Inc. 

Enterra Acquisitions Corp. 

Organizational Chart 

GENERAL DEVELOPMENTS OF THE BUSINESS 

History and Significant Acquisitions

Anticipated Developments 

DESCRIPTION OF THE BUSINESS AND PROPERTIES 

The Trust 

Business Strategy During 2009 

Competitive Strengths 

RISK FACTORS 

Risks Related to the Business 

Risks Related to the Trust Structure and the Ownership of Trust Units and Debentures 18

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION 

Disclosure of Reserves Data 

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

Reserves Data – Constant Prices and Costs 

Reserves Reconciliation 

Undeveloped Reserves 

Significant Factors or Uncertainties Affecting Reserves Data 

Future Development Costs 

Oil and Gas Properties 

Oil and Gas Wells 

Land Holdings 

Abandonment and Reclamation Costs 

Tax Horizon 

Costs Incurred 

Exploration and Development Activities 

Production Volume by Field 

Production Estimates 

Quarterly Data 

RESERVE DATA CHANGES SINCE DECEMBER 31, 2008 

CAPITAL STRUCTURE 

The Trust Indenture 

Trust Units and Other Securities 

Income Streams 

Unitholder Limited Liability 

Issuance of Trust Units 

Trustee 

Liability of the Trustee 

Special Voting Rights 

Redemption Right 

Meetings of Unitholders 

Exercise of Voting Rights 

Amendments to the Trust Indenture 

Takeover Bid 

Termination of the Trust 

Reporting to Unitholders 

Description of Debentures 

Exchangeable Shares 

MARKET FOR SECURITIES 

DISTRIBUTIONS 

CORPORATE GOVERNANCE 

Delegation of Authority, Administration and Trust Governance 

Directors and Officers 

Committees 

Cease Trade Orders, Bankruptcies, Penalties or Sanctions 

LEGAL PROCEEDINGS AND REGULATORY ACTIONS 

Legal Proceedings 

Regulatory Actions 

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

TRANSFER AGENT AND REGISTRAR

MATERIAL CONTRACTS 

INTERESTS OF EXPERTS 

AUDIT COMMITTEE 

General

Mandate of the Audit Committee 

Relevant Education and Experience of Audit Committee Members 

Audit Committee Oversight 

ADDITIONAL INFORMATION 

Appendix A – Audit Committee Mandate

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

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

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

Unless otherwise indicated, all of the information provided in this Annual Information Form is as at December 31, 2009.

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GENERAL INFORMATION

Glossary

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

“ABCA” means the Business Corporations Act (Alberta);

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

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

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

“Delaware GCL” means Delaware General Corporation Law;

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

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

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

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

“EECT Units” means trust units of EECT;

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

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

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

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

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

“Exchangeco” means Enterra Exchangeco Ltd., a corporation incorporated under the ABCA and a wholly-owned subsidiary of EECT;

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

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

“Haas Report” means the independent engineering evaluation of certain oil, NGL and natural gas interests of the Trust prepared by Haas dated March 9, 2009 and effective December 31,2009;

“High Point” means High Point Resources Inc., a corporation incorporated under the ABCA;

“JED” means JED Oil Inc., a corporation incorporated under the ABCA;

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

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

 “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 March 4, 2010 and effective December 31, 2009;

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

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

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

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

“Revolving and Operating Credit Facilities” means

(A) a $110.0 million revolving credit facility with a syndicate of lenders, and

(B) a $20.0 million operating facility with Bank of Nova Scotia as lender,

provided pursuant to the second amended and restated syndicated credit agreement dated June 25, 2009;

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

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

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

“Second Amended and Restated Credit Agreement” means

(A) a $110.0 million revolving credit facility with a syndicate of lenders, and

(B) a $20.0 million operating facility with Bank of Nova Scotia as lender,

provided pursuant to the second amended and restated syndicated credit agreement dated June 25, 2009;

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

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

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

“Trust Units” mean units of the Trust;

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

“Unitholders” mean holders from time to time of the Trust Units;

 “US Farmout Agreement” means a farm-out agreement with Petroflow Energy Ltd, and the Trust to fund the drilling and completion costs of the undeveloped lands in Oklahoma (the seven counties).

“US Farmout Partner” means Petroflow Energy Ltd.;

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

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

Abbreviations, Conventions and Conversions

Abbreviations

AECO	Intra Alberta Nova Inventory Transfer Price (NIT net price)	Mboe	thousands of barrels of oil equivalent
API	American Petroleum Institute	mcf	thousand cubic feet of natural gas
°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	mcf/d	thousand cubic feet of natural gas per day
ARTC	Alberta Royalty Tax Credit	Mmcf/d	million cubic feet of natural gas per day
bbl or bbls	barrels of oil	Mmcf	million cubic feet of natural gas
bbls per day or bbl/d	barrels of oil per day	mcf per day	thousands of cubic feet of natural gas per day
Bcf	Billion cubic feet of natural gas	mmbtu	millions of British Thermal Units
boe	barrels of oil equivalent (6 mcf equivalent to 1 bbl)	mmbtu per day	millions of British Thermal Units per day
boe per day or boe/d	barrels of oil equivalent per day	Mwh	Megawatt hours
Cdn$	Canadian dollars	NGL or NGLs	natural gas liquids (ethane, propane, butane and condensate)
FD&A	Finding Development & Acquisition Costs	NI 51-101	National Instrument 51-101
FDC	Future Development Costs	NYMEX	New York Mercantile Exchange
GAAP	Canadian Generally Accepted Accounting Principles	Q1	first quarter of the year - January 1 to March 31
GJ	Gigajoule	Q2	second quarter of the year - April 1 to June 30
GJ/d	gigajoule per day	Q3	third quarter of the year - July 1 to September 30
GORR	Gross overriding royalty	Q4	fourth quarter of the year - October 1 to December 31
LNG	Liquefied Natural Gas	SEC	Securities and Exchange Commission
m3	cubic metres	US$	United States dollars
mbbl	thousand barrels of oil	WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

Conventions

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

The information set out in this AIF is stated as at December 31, 2009 unless otherwise indicated.  Capitalized terms used but not defined in the text are defined in the Glossary.

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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	Cubic metres	28.174
Cubic metres	Cubic feet	35.494
Bbls	Cubic metres	0.159
Cubic metres	Bbls oil	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.4047
Hectares	Acres	2.471

Exchange Rate Information

Except where otherwise indicated, all dollar amounts in this AIF are stated in Canadian dollars.  The following table sets forth the US/Canada exchange rates on the last trading day of the years indicated as well as the high, low and average rates for such years.  The high, low and average exchange rates for each year were identified or calculated from spot rates in effect on each trading day during the relevant year.  The exchange rates shown are expressed as the number of 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 the end of day rate on each trading day (the “Bank of Canada end of day rate”).

		Year Ended December 31
	2009		2008	2007
Year End	0.9514		0.8210	1.0087
High	0.7698		0.7726	1.0905
Low	0.9748		1.0290	0.8506
Average	0.8757		0.9381	0.9309

In the preparation of the reserve tables in the section ‘Statement of Reserves Data and Other Oil and Gas Information” there are certain tables which present the net present value of the future revenue streams of the Oklahoma reserves. In order to combine the reserves from Canada assets with the reserves in the U.S. assets the future cash flows of the Oklahoma assets must be translated into Canadian dollars using a future exchange rate. The Trust used a rate of $0.9500 U.S. to $1.00 Canadian for the forecast price tables and a rate of $0.9514 U.S. to $1.00 Canadian for the Constant price table. These rates are the weighted average of the forecasted future exchange rate of the Trust’s reserves and are consistent with the exchange rates in the McDaniel’s reserve report.

Note Regarding Forward-Looking Statements

Certain information contained herein may contain forward-looking statements including management’s assessment of future plans and operations, drilling plans and timing thereof, expected production increases from certain projects and the timing thereof, the effect of government announcements, proposals and legislation, plans regarding wells to be drilled, expected or anticipated production rates, expected exchange rates, distributions and method of funding thereof, proportion of distributions anticipated to be taxable and non-taxable, anticipated borrowing base under credit facility, maintenance of productive capacity and capital expenditures and the nature of capital expenditures and the timing and method of financing thereof, may constitute forward-looking statements under applicable securities laws and necessarily involve risks.  All statements other than statements of historical facts contained in this MD&A are forward-looking statements.  The words “believe”, “may”, “will”, “estimate”, “continue”, “anticipate,” “intend”, “should”, “plan”, “expect” and similar expressions, as they relate to the Trust, are intended to identify forward-looking statements.  The Trust has based these forward-looking statements on the current expectations and projections about future events and financial trends that the Trust believes may affect its financial condition, results of operations, business strategy and financial needs.

These forward-looking statements are subject to uncertainties, assumptions and a number of risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources.  The recovery and reserve estimates of the Trust’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Trust.  In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Trust operates; the timely receipt of any required regulatory approvals; the ability of the Trust to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator  of the projects which the Trust has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Trust to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisitions, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of the Trust to secure adequate reasonably priced transportation; future commodity oil and gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Trust operates; and the ability of the Trust to successfully market its oil and natural gas products.  Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.  As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.  Additional information on these and other factors could effect the Trust’s operations and financial results are included in reports on file with the Canadian and United States regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or the EDGAR website (www.sec.gov/edgar.shtml), or at the Trust’s website (www.enterraenergy.com).  Furthermore, the forward-looking statements contained herein are made as at the date hereof and the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of the new information, future events or otherwise, except as may be required by applicable securities law.  Other sections of this MD&A may include additional factors that could adversely affect the business and financial performance.  The Trust operates in a very competitive and rapidly changing business environment.  New risk factors emerge from time to time and it is not possible for management to predict all risk factors, nor can the Trust assess the impact of all factors on its business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.  The reader should not rely upon forward-looking statements as predictions of future events or performance.  The Trust cannot provide assurance that the events and circumstances reflected in the forward-looking statements will be achieved or occur.  Although the Trust believes that the expectations reflected in the forward-looking statements are reasonable, the Trust cannot guarantee future results, levels of activity, performance or achievements.

The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses.  Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data.  These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this AIF and in the Trust’s management’s discussion and analysis for the year ended December 31, 2009, which is available through the internet on the Trust’s SEDAR profile at www.sedar.com, on EDGAR at www.sec.gov as part of the annual report on Form 6-K filed with the SEC together with this AIF , and on the Trust’s website at www.enterraenergy.com. Readers are also referred to the risk factors described in this AIF under:”Risk Factors” and in other documents the Trust’s files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the Trust’s or electronically on the internet on the Trust’s SEDAR profile at www.sedar.com on EDGAR at www.sec.gov and on the Trust’s website at www.enterraenergy.com.

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STRUCTURE AND ORGANIZATION OF ENTERRA ENERGY TRUST

Enterra Energy Trust

The 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.  The Trust’s head office is located at Suite 2700, 500 - 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6.  The Trust’s registered office is located at 4300 Bankers Hall West, 888 – 3rd Street S.W., Calgary, Alberta, Canada T2P 5C5.  The Trustee’s head office is located at Suite 2300, 125 - 9th Avenue S.E., Calgary, Alberta, Canada T2G 0P6.

Enterra Energy Commercial Trust

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

Enterra Energy Corp.

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

Enterra Production Partnership

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

Enterra Energy Partner Corp.

EEPC is a corporation incorporated under the ABCA.  EEPC is a holding company wholly owned by EEC which holds an interest in EPP.

Enterra US Acquisitions Inc.

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

Enterra Acquisitions Corp.

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

Altex Energy Corporation

Altex is a corporation incorporated under the Delaware GCL.  Altex is a wholly owned subsidiary of EAC.

Organizational Chart

The following chart illustrates the Corporate structure as at December 31, 2009.

[Missing Graphic Reference]

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

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GENERAL DEVELOPMENTS OF THE BUSINESS

History and Significant Acquisitions

The Enterra Arrangement

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

2004 Acquisition of Rocky Mountain Energy Corp.

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

2005 Acquisition of Rocky Mountain Gas, Inc.

On June 1, 2005, EEC acquired 100% of the issued and outstanding shares of Rocky Mountain Gas, Inc. (“RMG”), an entity with natural gas properties in Montana and Wyoming.  The transaction was valued at approximately $24.0 million and was financed with 736,842 RMG Exchangeable Shares valued at $16.7 million, 275,474 Trust Units valued at $6.3 million and cash of $1.0 million. On June 1, 2006, all of the then-outstanding RMG Exchangeable Shares were redeemed for Trust Units. In 2008 Rocky Mountain Gas Inc., was sold.

2005 Acquisition of High Point Resources Inc.

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

2006 Acquisition of Oklahoma Assets

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

The current and anticipated production from the Oklahoma Assets is primarily from the Hunton Group carbonate formations and is derived through a de-pressuring of the formation via water production followed by hydrocarbon production.  The Hunton Group is exploited at depths of approximately 1,500 metres using long, multi-leg horizontal wells.  The Trust operates all of its related production, gathering and water disposal facilities.  On June 27, 2006, a farm-out agreement was entered into with a U.S. Farmout Partner to exploit the undeveloped Hunton Group prospects.

2006 Property Swap with JED Oil Inc.

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

2007 Acquisition of Trigger Resources Ltd.

On April 30, 2007, the Trust acquired all of the issued and outstanding shares of Trigger Resources Ltd. (“Trigger Resources”).  Trigger Resources shareholders received cash consideration of $63.3 million which was funded by the issuance of $40.0 million of 8.25% convertible Debentures that mature on June 30, 2012 and $29.2 million of Trust Units (4,945,000 trust units).  Trigger Resources’ oil and natural gas property boe/d (58% oil, 42% gas) to the Trust’s production portfolio.  The properties generally have 100% working interest with year round access and relatively low operating costs.

2007 Disposition of Non-core Assets

The Trust regularly evaluates asset acquisition and divestiture candidates.  This practice, in conjunction with the Trust’s debt reduction strategy, led the Trust in 2007 to review and identify assets deemed to be “non-core” to its ongoing operations.  These assets were then publicly marketed in the fall of 2007.  The Trust received numerous proposals for the assets marketed in addition to several unsolicited offers for non-core assets that had not been actively marketed.  During 2007 certain Princess non-operated, Willesden Green and Little Bow properties were sold.

2008 Disposition of Non-core Assets

In 2008 the Trust’s primary goals were debt reduction, increased operational focus and efficiency and replacement of produced reserves.   During 2008 the Trust closed the sale on non-core assets for proceeds of $39.6 million.  Substantially all net proceeds were applied to debt reduction of the Trust.

2009 Acquisition of Additional Working Interest in Oklahoma

In 2009 the Trust purchased approximately 270 boe/d of production from partners in its existing Hunton development operation in Oklahoma for cash consideration of $US 6.0 million and 2.0 million Trust Units for a total value of approximately $9.0 million.  All of the production is from well bores which are operated by the Trust and in which the Trust has an existing interest.  The acquisition also allows for a larger go forward interest in future drilling in this area.

Equity Offerings

2005 Financings

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

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

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

2006 Financings

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

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

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

2007 Financings

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

Anticipated Developments

For a discussion of anticipated developments for 2010, please see the subsequent events and proposed transactions section of the Management’s Discussion and Analysis for the year ending December 31, 2009 (the “MD&A”) which may be found on SEDAR at www.sedar.com.

Implications of Tax Proposals by the Canadian Minister of Finance

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

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

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

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

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

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

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

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

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

On November 28, 2008, Finance tabled a Notice of Ways and Means Motion (“the motion”) in the House of Commons which contained proposed changes to the SIFT conversion provisions under the Tax Act.  On December 4, 2008, Finance released explanatory notes for the Motion which also contained revisions to the Department of Finance "normal growth" guidelines for grandfathered SIFTs.  The revision to the “normal growth” guidelines has accelerated the Trust’s allowance to issue new equity without “undue expansion” and allows the Trust to issue its remaining safe harbour amount after December 4, 2008 without considering the previous timeline set out by Finance.

On January 18, 2010, Enterra Energy Trust announced that the Board of Directors of EEC., on behalf of the Trust, unanimously approved the conversion of the Trust to a corporation to be named Equal Energy Ltd.  The corporate conversion will be subject to receipt of all required regulatory, stock exchange and Court of Queen's Bench of Alberta approvals including approval of at least 66 2/3 percent of the votes by unitholders present in person or by proxy in a duly convened special meeting of the Trust’s unitholders.  All regulatory approvals for The Trust’s conversion to a corporation are scheduled to be in place by late May 2010.

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

DESCRIPTION OF THE BUSINESS AND PROPERTIES

The Trust

The Trust’s portfolio of oil and gas properties is geographically diversified with producing properties located principally in Alberta, British Columbia, Saskatchewan and Oklahoma.  Production during 2009 of 9,878 boe/d was comprised of approximately 50% natural gas, 28% crude oil and 22% natural gas liquids (“NGL”).  For 2010, production is expected to be approximately 26% oil , 27% NGLs and 47% natural gas  The Trust has compiled a multi-year drilling inventory for its properties.

Business Strategy During 2009

In 2009 the Trust’s primary goals have been debt reduction, and increased operational focus and efficiency.   Debt at the year ended December 31, 2008 was $95.5 million and was reduced to $70.0 million by December 31, 2009.  In 2009, the Trust increased its cost discipline in the areas of operating costs, capital spending, and general and administrative expenses.  As well, the Trust has increased the size and its capacity to grow a prospect inventory of exploration, development, and exploitation opportunity.

Competitive Strengths

The Trust has a number of competitive strengths which will enhance the execution of its business strategy.  Its competitive strengths include:

Diversified Production Base

The Trust’s assets are principally located in four areas: north east British Columbia, Alberta, Saskatchewan and Oklahoma.  While each area has different geological, production and infrastructure characteristics, in aggregate they have historically provided a stable source of production.

Large Portfolio of Development Projects

The Trust’s properties contain a number of potential development projects, which supports the strategy of reserving a portion of funds from operations to invest in organic growth opportunities.  Currently, there are a significant number of drilling opportunities on approximately 150,666net acres of undeveloped land.

U.S. Platform Distinguishes the Trust from Other Canadian Oil & Gas Trusts

Based on average production during 2009, approximately55% of the Trust’s production is in the United States.  The Trust’s presence in both countries, in terms of people and assets, provides it with a broader range of opportunity, improves its perspective when evaluating projects or acquisitions, and reduces the dependence on the highly competitive Canadian market.

Commodity Price Hedges

As part of the active risk management program up to 50% of the projected gross production is hedged for up to 24 months in advance, the Trust has entered into a series of collars, fixed price contracts, or physical contracts 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 the 2009 consolidated annual financial statements and in Item 5 A. Operating Results - Commodity Contracts.

Experienced Management Team

In late 2007, the Trust had made several changes to its management team which has resulted in the formation of a strong, experienced and committed management team that has demonstrated its ability to identify and successfully execute the Trust’s business plans.

Personnel

At December 31, 2009, the Trust employed or contracted 39 office personnel and 30 field operations personnel in its Canadian operations and 27 office personnel and 27 field operations personnel in its U.S. operations for a total of 123 employees.

Reorganziation

On January 18, 2010 the Trust announced that the Board of Directors of EEC., on behalf of the Trust, unanimously approved the conversion of the Trust to a corporation to be named Equal Energy Ltd. (“Equal Energy”).  Equal Energy will continue to pursue the exploration and development of its Oklahoma based Hunton Oklahoma natural gas and NGL resource play.  The company will work to further develop opportunities in its Viola, Oklahoma oil play, as well as its oil play in the west central Alberta Cardium formation, and its various other Western Canadian Sedimentary Basin oil and gas prospects.  In addition, the conversion will address the upcoming changes in the Canadian tax law, when the government will start imposing the new tax on income trusts starting in January 2011.

Rationale for reorganization

The Trust must consider converting from a trust model because of imminent tax changes in Canada, and its Board of Directors and executive team considered various strategic alternatives with regard to the Trust’s structure going forward.   The Trust’s management and directors have implemented various strategies to ensure the long-term viability and sustainability of the Trust in a corporate model.

Approvals and timing

The corporate conversion will be subject to receipt of all required regulatory, stock exchange and Court of Queen's Bench of Alberta approvals including approval of at least 66 2/3 percent of the votes by Unitholders present in person or by proxy in a duly convened special meeting of the Unitholders.  It is anticipated that aninformation circular proxy statement in connection with this special meeting will be mailed to Unitholders in late March, and the special meeting will be held in mid May.  All regulatory approvals for the Trust’s conversion to a corporation are expected to be in place by late May.

RISK FACTORS

Risks Related to the 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 the Trust Units or Debentures and the amount of distributions to Unitholders.

The Trust’s business, results of operations, financial condition and future growth are substantially dependent on the prevailing prices for its 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 the Trust’s 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 the Trust’s revenues, operating income, cash flows and borrowing capacity and may require a reduction in the carrying value of the 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 the Trust to operate profitably or make distributions.

The Trust uses financial derivative instruments and other hedging mechanisms to try to limit a portion of the adverse effects resulting from decline in oil and natural gas prices.  In addition, the commodity hedging activities could expose the Trust 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 the 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.

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

The Trust’s Revolving and Operating Credit Facilities may not provide the Trust with sufficient funding for future operations, or the Trust may not be able to obtain additional financing on attractive economic terms, if at all.  On June 25, 2009 the Trust entered into credit facilities with its banking syndicate that includes revolving and operating credit facilities which has a current borrowing capacity of $110.0 million.  The revolving and operating credit facilities are secured with a first priority charge over the assets of the Trust.  Borrowings under the revolving and operating credit facilities at March 29, 2010 were approximately $70.0 million.  The maturity date of the revolving and operating credit facilities is June 25, 2010 and should the lenders decide not to renew the facility, the debt must be repaid on June 25, 2011.

The Trust’s obligations to its lenders may have a material adverse affect on the ability to pay distributions to Unitholders.

The payment of interest and principal, and other costs, expenses and disbursements to the lenders reduces the amounts available for potential distribution to Unitholders.  Variations in interest rates and required principal repayments could result in significant changes to the amount of the funds from operations required to be applied to the debt before payment of any amounts to Unitholders.  The agreement governing the Revolving and Operating Credit Facilities provides that if the Trust is in default of its terms, or if amounts outstanding exceed the amount of the borrowing base, the ability to make distributions to Unitholders may be restricted.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

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

The revolving and operating credit facilities are secured by the Trust’s assets.  A decrease in the amount of production or the price received for it could make it difficult for the Trust to service the debt or may cause the lenders to determine that its assets are insufficient security for the debt.  Repayment of all or a portion of outstanding amounts under the Revolving and Operating Credit Facilities may be demanded on relatively short notice.  If this occurs, the Trust may need to obtain alternate financing.  Any failure to obtain suitable replacement financing may have a material adverse effect on the Trust’s business, or adversely affect the market price of the Trust Units or Debentures.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

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

The Trust does not focus on the exploration for oil and natural gas reserves.  Instead, the Trust adds to its oil and natural gas reserves primarily through development, exploitation and acquisitions.  As a result, future oil and natural gas reserves are highly dependent on success in developing and exploiting existing properties and acquiring additional reserves.  Accordingly, if external sources of capital, including the issuance of additional Trust Units or other securities, become limited or unavailable on commercially reasonable terms, the Trust’s ability to make the necessary capital investments to maintain or expand oil and natural gas reserves will be impaired.  To the extent that the Trust is 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, the Trust cannot guarantee that it will be successful in developing or exploiting additional reserves or acquiring additional reserves on terms that meet its investment objectives.  Without these reserve additions, the Trust’s reserves will deplete and as a consequence, either production from, or the average reserve life of, the properties will decline.  Either decline may result in a reduction in the value of the Trust Units and in a reduction in cash available for potential distributions to Unitholders.

A decline in the Trust’s ability to market its 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 the Trust Units or Debentures.

The Trust’s 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 the Trust’s ability to produce and market oil and natural gas.  If market factors change and inhibit the marketing of the Trust’s production, overall production or realized prices may decline, which could reduce potential distributions to Unitholders.

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

The price that is received for a majority of the Trust’s oil and natural gas is based on United States dollar denominated benchmarks, and therefore the price that is received 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.  The Trust could be subject to unfavourable price changes to the extent that the Trust has engaged, or in the future engages, in risk management activities related to foreign exchange rates, through entry into forward foreign exchange contracts or otherwise.

Distributions, if any, may be reduced during periods in which capital expenditures are made or debt repaid using cash flow.

To the extent that the Trust uses 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 significant capital or other expenditures are made.

The Board of directors of EEC, the administrator and principal operating subsidiary of the Trust, has the discretion to determine the extent to which funds from operations will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under the 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. On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

Actual reserves may 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 the Trust’s 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 the Trust Units and Debentures depends upon, among other things, the reserves attributable to the Trust’s properties.  Estimating reserves is inherently uncertain.  Ultimately, actual reserves attributable to the 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 a portion of the Trust’s production is from geological formations with relatively limited long term production history, 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 the Trust’s control.  If these factors, assumptions and prices prove to be inaccurate, actual results may vary materially from reserve estimates.

In addition, the level of production from the existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond the control of the Trust.  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 the Trust expands its operations beyond conventional oil and natural gas exploration, production and development in Western Canada, it may face new challenges and risks.

The Trust’s operations and expertise were previously focused on the production of conventional oil and gas production and development in the Western Canadian Sedimentary Basin.  In the first quarter of 2006, properties in Oklahoma were acquired.  The Trust has gained significant experience operating in this jurisdiction but will still face operating and business challenges that it cannot foresee and therefore will need to rely on local management.

The Trust Indenture does not limit the Trust’s activities to oil and gas exploration, production and development, and the Trust could acquire other energy related assets, such as oil and natural gas processing plants or pipelines.  Expansion of activities into new areas presents challenges and risks that the Trust may not have faced in the past.  If the Trust does 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 the Trust Units or Debentures and distributions to Unitholders.

The price that the Trust is 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 that are acquired 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 the Trust’s engineers, and these initial assessments may differ significantly from its subsequent assessments.

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

A component of the future growth depends on the Trust’s ability to identify, negotiate, and acquire additional entities and assets that complement or expand the existing operations.  However the Trust may be unable to complete any acquisitions or any acquisitions that may be completed may not enhance the business.  Any acquisitions could subject the Trust 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 the organization effectively.

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

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

The Trust now has reasonable experience operating properties in the United States and has a full complement of local management and local employees.  It is the Trust’s expectation that it will continue to gain more insight into the technical and operational characteristics of each of these properties.

On properties where the Trust is not the operator, it is reliant on the operator for continuing production from the property, and to some extent, the marketing of that production.  During 2009, approximately 11% 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, the Trust’s revenue may be reduced.  Third-party operators also make estimating future capital expenditures more difficult.

Further, the operating agreements which govern the properties not operated by the Trust 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 willful misconduct.

The exploration, development and exploitation of a portion of the Trust’s 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 the Trust Units or Debentures and distributions to Unitholders.

The exploration, development and exploitation of the Trust’s properties and the ultimate amount of reserves recovered are dependant on being able to access technological advancements on a timely basis.  If these technological advancements are not available it may not be possible to maximize the contribution to the market value of the Trust Units or Debentures.  Delays in business operations could adversely affect the distributions to Unitholders.

In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of the 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 the Trust to additional third party credit risks.

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

The market price of the Trust Units is primarily a function of anticipated distributions to Unitholders and the value of the Trust’s properties.  The market price of the 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.

The Trust’s operations are entirely dependent on the Trust’s management and the loss of key management and other personnel could negatively impact the business.

Unitholders are entirely dependent on the Trust’s 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 the oil and natural gas properties and the administration of the Trust.  The loss of the services of key individuals who currently comprise the management team could have a detrimental effect on the Trust.

Management of the Trust may have conflicts of interest.

There are conflicts of interest to which several of the directors and officers are subject in connection with the Trust’s operations.  In particular, certain of the 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 the Trust’s operations.  Additionally, certain of the directors and officers may become involved with entities which may, from time to time, provide financing to, or make equity investments in, the Trust’s competitors.  See “Conflicts of Interest and Interests of Management and Others in Material Transactions”.

The Trust may be unable to successfully compete for resources with other organizations in the industry.

The Trust competes 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 the Trust.  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 the competitors may have greater and more diverse competitive resources to draw on than the Trust.  In addition, to the extent the Trust Units receive a lower market valuation relative to competing entities, there will be 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 the Trust Units or Debentures and distributions to Unitholders.

The industry in which the Trust operates exposes it to potential liabilities that may not be covered by insurance.

The Trust’s 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, 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 the property or the property of others.  The Trust cannot fully protect against all of these risks, nor are all of these risks insurable.  The Trust may become liable for damages arising from these events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons.  Any costs incurred to repair these damages or pay these liabilities would reduce funds available for distribution to Unitholders.

The Trust 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 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 the operations.  In addition, legislation regulating the oil and natural gas industry may be changed to impose higher standards and potentially more costly obligations.  The 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol, was ratified by the Canadian government in December 2002 and would require, among other things, significant reductions in greenhouse gases.  In 2007, the Government of Canada released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan") also known as ecoACTION which includes the regulatory framework for air emissions.  This Action Plan covers not only the oil and natural gas industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy using products.  In 2008, the Government of Canada released "Turning the Corner – Taking Action to Fight Climate Change" (the "Updated Action Plan") which provides some additional guidance with respect to the Government's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.  Additionally in 2008, the Government of Canada and the Province of Alberta released the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force (the “Canada-Alberta ecoEnergy Plan”), which recommends among other things: (i) incorporating carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through competitive process; and (iii) targeting research to lower the cost of technology.  In 2007,

The impacts from the Kyoto Protocol, the Action Plan, the Updated Action Plan and the Canada-Alberta ecoEnergy Plan on the Trust are uncertain and may result in significant additional costs for the Trust’s operations.  Although the Trust records a provision in the financial statements relating to estimated future environmental and reclamation obligations, it cannot guarantee that it will be able to satisfy the actual future environmental and reclamation obligations.

The Trust is 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, the Trust’s 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 the Trust be unable to fully fund the cost of remediating an environmental problem, it might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

Climate change impact

The Trust faces a variety of uncertainties related to climate change.  The oil and gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal legislation in Canada and federal and state laws and regulations in the United States.  These range from potential impacts from emissions restrictions, carbon taxes and other government policy initiatives, to changes in weather patterns that may affect operations.  Both the Alberta provincial government and the Canadian federal government have introduced planned legislative concepts that are intended, among other things, to drive industry towards CO2 emissions reduction and CO2 capture and sequestration in below ground geologic formations.  In early 2008, the British Columbia provincial government announced its intention to introduce a carbon tax on fuels.  Although the Trust is not a large emitter of greenhouse gases, these forms of legislation may have an impact on both revenues and cost structures at a future undetermined time.

Another potential climate change impact on the Trust may result from the direct consequences of weather events.  These may range from extreme cold events, to early break up in winter-only areas and unusual storms.

Lower oil and gas prices increase the risk of impairment of the Trust’s oil and gas property investments.

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

Capitalized costs are depleted and depreciated using the unit-of-production method based on the estimated gross proven oil and natural gas reserves before royalties as determined by independent engineers.  Units of natural gas are converted into barrels of equivalents on a relative energy content basis.  The amounts recorded for depletion, depreciation and the asset retirement obligation are based on these estimates.  The carrying value of the Trust’s petroleum and natural gas properties, which may be depleted against revenues of future periods, is limited to the estimated fair value of these properties (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 the Trust 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.

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 the Trust’s 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 the production and reserves.

Although the Trust conducts 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 the title to the purchased assets.  If such a defect were to occur, the Trust’s entitlement to the production from such purchased assets could be jeopardized and, as a result, distributions to Unitholders may be reduced.

Aboriginal land claims.

The economic impact on the Trust of claims of aboriginal title is unknown.  Aboriginal people have claimed aboriginal title and rights to a substantial portion of Western Canada.  The Trust is unable to assess the effect, if any, that any such claim would have on the business and operations.

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

The Trust’s 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 the Trust tries to purchases electrical power at competitive rates, it cannot guarantee that changes in market conditions and contract renewals will continue to allow operating costs to remain competitive and certain of the key fields profitable.  Under these circumstances the Trust would attempt to seek alternatives including self-generation of its power requirements.  However, it cannot guarantee that self-generation of power using its 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 Trust’s operations are subject to changes in governmental regulations and obtaining required regulatory approvals.

The oil and gas industry operates under federal, provincial, state and municipal legislation and regulation governing such matters as land tenure, prices, royalties, production rates, environmental protection controls, income, the exportation of crude oil, natural gas and other products, as well as other matters.  The industry is also subject to regulation by governments in such matters as the awarding or acquisition of exploration and production rights or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of field and mine sites (including restrictions on production), and possible expropriation or cancellation of contract rights.

Government regulations may be changed from time to time in response to economic or political conditions.  The exercise of discretion by governmental authorities under existing regulations, the implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas, increase  The Trust’s costs and have a material adverse impact on the Trust.

Although not strictly governmental or regulatory in nature, the implementation of International Financial Reporting Standards to replace Canadian GAAP effective January 1, 2011 (and as a potential reporting alternative to U.S. GAAP or resulting in the elimination of the requirement to reconcile to U.S. GAAP) may have an adverse impact on the Trust’s financial results as reporting in its financial statements, and may require the Trust to amend its Revolving and Operating Credit Facilities to address the changes in accounting principles.

The Trust’s operations are subject to credit risks with its commodity purchasers with its commodity contract counterparties.

The Trust sells its production either directly to a refinery, an intermediary or a mid-stream purchaser.  The Trust does not sell all of its production to any one purchaser and in any one month the Trust varies to whom it sells its production depending on several factors including availability of production, availability of capacity and contractual agreements.  Settlements usually occur between 20 to 40 days after the end of the month.  While the Trust reviews the credit ratings of the purchaser on a frequent basis the Trust is exposed to the risk of loss of proceeds of production if the purchaser fails to pay for the production due to financial failure of the purchaser.

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

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

Generally speaking, 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 as defined in the Tax Act (the “TCP Exception”).  Based on the most recent information obtained through the Trust’s transfer agent and financial intermediaries, in March 2009 an estimated 91% of the issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Tax Act).  The Trust is currently able to take advantage of the TCP Exception, and as a result, the Trust does not currently have a specific limit on the percentage of Trust Units that may be owned by non-residents.  The Trust intends to continue to take the necessary measures in order to ensure that it continues to qualify as a mutual fund trust under the Tax Act.  However, the Trust may not be able to take steps necessary to ensure that it maintains its mutual fund trust status.  Even if it is successful in taking such measures, these measures could be adverse to certain holders of Trust Units, particularly non-residents of Canada.  The board of EEC could impose a specific limit on the number of Trust Units that could be beneficially owned by non-residents of Canada, similar to the non-resident ownership restrictions in place for other income funds in Canada, or could implement a dual-class unit structure which would effectively limit the aggregate number of Trust Units that could be owned by non-residents of Canada.  Steps could be taken to ensure that no additional Trust Units are issued or transferred to non-residents, including limiting or suspending the trading of the Trust Units.

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

• The Trust would be subject to a special tax under Part XII.2 of the Tax Act of 36% of its “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” under the Tax Act.  Non-resident holders would then be subject to Canadian tax reporting and payment requirements on any gains realized on a disposition of Trust Units or Debentures held by them;

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

• the Trust 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 the Trust and its Unitholders.  Tax authorities having jurisdiction over the Trust and its Unitholders may disagree with the manner in which it calculates its income for tax purposes or could change their administrative practices to the Trust’s detriment or the detriment of the 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 the Trust.  In response to submissions from and discussions with stakeholders, the Canadian federal government suspended the implementation of those proposed amendments.

On June 12, 2007, federal legislation was enacted implementing a new tax (the “SIFT Tax”) on certain publicly traded income trusts and limited partnerships, referred to as “Specified Investment Flow-Through” (“SIFT”) entities.  For SIFTs in existence on October 31, 2006 (including the Trust), the SIFT Tax will become effective in 2011.  If certain rules related to “undue expansion” are not adhered to (“the normal growth guidelines”), the SIFT Tax will apply prior to 2011.  Under the SIFT Tax, distributions of certain types of income will not be deductible for income tax purposes by SIFTs in 2011 and thereafter and any resultant trust level taxable income will be taxed at a rate that will be approximately equal to corporate income tax rates.  The SIFT Tax rate is currently 26.5 percent in 2011 and 25.0 percent thereafter.  

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

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

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

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

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

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

On November 28, 2008, Finance tabled the Motion in the House of Commons which contained proposed changes to the SIFT conversion provisions under the Tax Act.  On December 4, 2008, Finance released explanatory notes for the Motion which also contained revisions to the Department of Finance "normal growth" guidelines for grandfathered SIFTs.  The revision to the “normal growth” guidelines has accelerated the Trust’s allowance to issue new equity without “undue expansion” and allows the Trust to issue its remaining safe harbour amount after December 4, 2008 without considering the previous timeline set out by the Finance.

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

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

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

The Trust’s Operating Subsidiaries are subject to taxation in their respective taxation years on their respective taxable incomes for the year.  The 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 these 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 the Trust Units.

The cash available for distribution to Unitholders is ultimately sourced from these 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 are received from the 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 the Trust relies for a reduction in withholding taxes on distributions from the 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.  The Trust Indenture provides that an amount equal to the taxable income of the Trust will be payable each year to Unitholders in order to reduce the Trust’s taxable income to zero.  The 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.

It is expected 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 United States federal income tax at a maximum rate of 15 percent provided that, among other things, (a) that the payor of the dividend is not classified as a Passive Foreign Investment Company “PFIC“during the taxable year in which such distribution is paid or the preceding taxable year, (b) that the U.S. Holder has satisfied certain holding period requirements, and (c) that the U.S. Holder has not made an election to treat the dividend as “investment income” for purposes of the investment interest deduction rules.  In addition, the rate reduction will not apply to dividends if the recipient of a dividend is obligated to make related payments with respect to positions in substantially similar or related property.  This disallowance applies even if the minimum holding period has been met.  If the rate reduction is not applicable, the dividends would be subject to United States federal income taxation at ordinary income tax rates.

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

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

Individual retirement accounts, other employee benefit plans and certain organizations that are generally exempt from United States federal income tax are subject to United States federal income tax on unrelated business taxable income, such as certain income from debt financed property, to the extent that such unrelated business taxable income for a taxable year is in excess of $1,000.  The Trust has in the past and may in the 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 Untied 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 the Trust does 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 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 Untied States federal income tax on any dividend that is received in respect of the stock in any such PFIC.

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

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

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

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

The Trust organized under the laws of Alberta, Canada, and EEC’s principal offices are in Canada.  Most of the Trust’s directors and officers are residents of Canada and most of the experts who provide services to the Trust (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 Untied States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the Untied States federal securities laws or the securities laws of any state within the United States.

Rights as a Unitholder differ from those associated with other types of investments.

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in the Trust or the Trust Subsidiaries.  The Trust Units represent an equal fractional beneficial interest in the Trust and, as such, the ownership of the Trust Units does not provide Unitholders with the statutory rights normally associated with ownership of shares of a corporation, including, for example, the right to bring “oppression” or “derivative” actions.  The unavailability of these statutory rights may also reduce the ability of Unitholders to seek legal remedies against other parties on the Trust’s behalf.

The Trust Units are also unlike conventional debt instruments in that there is no principal amount owing to Unitholders.  The Trust Units will have minimal value when reserves from its 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 to Unitholders in connection with 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 the objectives is to continually add to the Trust’s reserves through acquisitions and through development.  At the present time the Trust does reinvest the majority of its cash flow to development and acquisition of reserves however, its success is still, in part, dependent on its ability to raise capital from time to time by selling additional Trust Units.  Unitholders may 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 “Description of Debentures”.

Prior distributions are not reflective of future distributions.

Historical distributions are not reflective of future distributions.  Future distributions will be subject to review by, and are in the discretion of, the board of directors EEC.  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt.

The 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 the Trust’s 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 its 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.

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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, 2009 contained in the McDaniel Report, by Haas with an effective date of December 31, 2009 contained in the Haas Report.  The Reserves Data summarizes the Trust’s 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 and Haas reports have been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101.  Information not required by NI 51-101 has been presented to provide continuity and additional information which the Trust believes is important. The Trust engaged McDaniel and Haas to provide an evaluation of its proved and proved plus probable reserves.

At December 31, 2009 the Trust’s reserves were in Canada, specifically, in the provinces of Alberta, British Columbia, and Saskatchewan and in the United States, specifically in the state of Oklahoma.  McDaniel reviewed the reserves in Canada and Haas reviewed the reserves in Oklahoma.

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 the Trust’s 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 the Trust’s oil, NGL and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated by McDaniel and Haas based on constant and forecast price and cost assumptions.    The data may contain slightly different numbers than the reports due to rounding.  Additionally, the numbers in the tables may not add exactly due to rounding.

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

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Reserves Data – Forecast Prices and Costs

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue

Forecast Prices and Costs as of December 31, 2009

	Remaining Reserves
Reserves Category	Light and Medium Crude Oil		Heavy Oil		Natural Gas Liquids		Natural Gas		Total
	Gross (mbbls)	Net (mbbls)	Gross (mbbls)	Net (mbbls)	Gross (mbbls)	Net (mbbls)	Gross (mmcf)	Net (mmcf)	Gross (mboe)	Net (mboe)
	(3)	(4)	(3)	(4)	(3)	(4)	(3)	(4)	(3)	(4)
CANADA(1)
Producing	1,678.6	1,586.0	571.7	444.0	77.9	56.9	14,199.2	9,965.2	4,694.7	3.747.8
Non-Producing	-	-	-	-	39.0	24.2	5,277.0	3,278.9	918.5	570.7
Proved Undeveloped	8.1	7.7	120.0	76.4	0.7	0.6	74.9	64.8	141.3	95.5
Proved	1,686.7	1,593.7	691.7	520.4	117.6	81.7	19,551.1	13,308.9	5,754.5	4,414.0
Probable	848.1	755.2	357.4	254.4	81.0	59.4	16,457.3	11,228.3	4,029.4	2,940.4
Total Proved plus Probable	2,534.8	2,348.9	1,049.1	774.8	198.6	141.1	36,008.4	24,537.2	9,783.9	7,354.3
OKLAHOMA(2)
Producing	603.5	487.2	-	-	5,499.7	4,400.9	33,657.2	26,883.1	11,712.7	9,368.6
Non-Producing	47.9	38.4	-	-	194.0	154.4	1,793.9	1,428.8	540.9	430.9
Proved Undeveloped	4.7	3.7	-	-	1,774.8	1,419.1	14,503.4	11,600.1	4,196.8	3,356.1
Proved	656.1	529.2	-	-	7,468.5	5,974.5	49,954.5	39,912.0	16,450.4	13,155.7
Probable	26.0	21.5	-	-	2,126.0	1,858.0	16,072.1	14,313.1	4,830.7	4,265.0
Total Proved plus Probable	682.1	550.7	-	-	9,594.5	7,832.2	66,026.6	54,225.1	21,281.0	17,420.7
AGGREGATE
Producing	2,282.1	2,073.2	571.7	444.0	5,577.6	4,457.8	47,856.4	36,848.3	16,407.5	13,116.4
Non-Producing	47.9	38.4	-	-	233.0	178.6	7,070.9	4,707.7	1,459.4	1,001.6
Proved Undeveloped	12.8	11.4	120.0	76.4	1,775.5	1,419.7	14,578.3	11,664.9	4,338.0	3,451.6
Proved	2,342.8	2,122.9	691.7	520.4	7,586.1	6,056.2	69,505.6	53,220.9	22,204.9	17,569.7
Probable	874.1	776.7	357.4	254.4	2,207.0	1,917.4	32,529.4	25,541.4	8,860.0	7,205.4
Total Proved plus Probable	3,216.9	2,899.6	1,049.1	774.8	9,793.1	7,973.6	102,035.0	78,762.3	31,064.9	24,775.1

Note:

(1)   Canada - from McDaniel Report.

(2)   Oklahoma – from Haas Report.

(3)   Gross refers to the Trust’s working interest before royalties

(4)   Net refers to the Trust’s working interest after royalties plus royalty interest reserves

-  -

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue

Forecast Prices and Costs as of December 31, 2009

		Before Income Taxes Discounted at (%/year)					After Income Taxes Discounted at (%/year)
		0	5	10	15	20	0	5	10	15	20
Reserves Category		MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
	Producing	127.7	111.7	100.0	90.9	83.6	127.7	111.7	100.0	90.9	83.6
	Non-Producing	7.6	6.5	5.7	5.1	4.5	7.6	6.5	5.7	5.1	4.5
	Proved Undeveloped	2.6	2.2	2.0	1.8	1.6	2.6	2.2	2.0	1.8	1.6
Proved		137.8	120.5	107.7	97.7	89.7	137.8	120.5	107.7	97.7	89.7
Probable		99.2	72.4	55.4	43.8	35.4	80.0	59.4	46.1	36.9	30.2
Total Proved plus Probable		237.0	192.9	163.1	141.5	125.1	217.8	179.9	153.8	134.6	119.9
OKLAHOMA(2)
	Producing	340.0	255.1	203.0	168.4	144.0	258.7	194.2	154.6	128.4	109.8
	Non-Producing	12.2	9.2	7.2	5.8	4.7	9.4	7.1	5.6	4.5	3.7
	Proved Undeveloped	50.9	24.1	7.5	(3.0)	(9.7)	31.7	14.2	3.2	(3.9)	(8.6)
Proved		403.1	288.4	217.7	171.2	139.0	299.7	215.5	163.4	129.0	105.0
Probable		139.4	95.7	69.2	52.1	40.5	89.6	62.3	45.8	35.1	27.8
Total Proved plus Probable		542.5	384.1	286.9	223.4	179.5	389.3	277.8	209.3	164.1	132.8
AGGREGATE
	Producing	467.7	366.8	302.9	259.3	227.6	386.3	305.9	254.6	219.2	193.4
	Non-Producing	19.8	15.8	12.9	10.8	9.3	17.0	13.7	11.3	9.6	8.2
	Proved Undeveloped	53.5	26.4	9.5	(1.2)	(8.1)	34.2	16.5	5.2	(2.1)	(7.0)
Proved		540.9	408.9	325.4	268.9	228.7	437.5	336.0	271.1	226.7	194.7
Probable		238.6	168.1	124.6	95.9	75.9	169.6	121.7	92.0	72.1	58.1
Total Proved plus Probable		779.5	577.0	450.0	364.8	304.6	607.1	457.7	363.1	298.8	252.7

Note:

(1)   Canada - from McDaniel Report.

(2)   Oklahoma - from Haas Report.

(3)   Oklahoma dollar values have been converted to Cdn$ at 0.9514 exchange rate

-  -

Undiscounted Future Net Revenue

Forecast Prices as of December 31, 2009

Total Reserves

	Revenue	Royalties	Operating Costs	Capital Develop-ment Costs	Abandon-ment Costs	Future Net Revenue Before Income Taxes	Future Income Taxes	Future Net Revenue After Future Income Taxes
Reserves Category	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
Total Proved	338.9	68.1	114.6	1.8	16.5	137.8	-	137.8
Total Proved plus Probable	577.4	122.6	185.0	15.5	17.3	237.0	19.2	217.8
OKLAHOMA(2) (3)
Total Proved	844.5	208.9	165.0	63.3	4.3	403.1	103.4	299.7
Total Proved Plus Probable	1,107.6	273.5	201.4	85.6	4.4	542.5	153.2	389.5
AGGREGATE
Total Proved	1,183.4	277.0	279.6	65.1	20.8	540.9	103.4	437.5
Total Proved Plus Probable	1,685.0	396.1	386.4	101.1	21.9	779.4	172.4	607.3

Note:

(1)   Canada - from McDaniel Report.

(2)   Oklahoma – from Haas Report.

(3)   Oklahoma net present values have been converted to Cdn$ at 0.9514 exchange rate.

Oil and Gas Reserves and Net Present Values by Production Group

Forecast Prices as of December 31, 2009

Total Reserves

	Discounted at 10% (4)
	Canada	Oklahoma	Total
				Unit Value
Reserves Category	MM$	MM$	MM$	$/bbl
		(3)		(2)
Proved
Light and Medium Crude Oil (1)	47.8	22.4	70.1	33.04
Heavy Oil	14.8	-	14.8	28.39
Natural Gas Liquids	3.6	98.6	102.2	16.87
Natural Gas	41.5	96.8	138.3	2.60
Total	107.7	217.7	325.4
Proved Plus Probable
Light and Medium Crude Oil (1)	70.0	23.2	93.2	32.13
Heavy Oil	22.0	-	22.0	28.36
Natural Gas Liquids	5.9	129.3	135.1	16.95
Natural Gas	65.3	134.5	199.8	2.54
Total	163.1	286.9	450.0

Note:

(1)   Including by all by products.

(2)   Unit values are based on net reserve volumes in Cdn$.

(3)   Oklahoma net present values and unit values have been converted to Cdn$ at 0.9514 exchange rate.

(4)   Net Present Values discounted at 10% are before tax.

-  -

Oil and Gas Reserves and Net Present Values by Production Group

Forecast Prices as of December 31, 2009

Total Reserves

Reserves Group by Category	Oil Gross Mbbl		Net Mbbl		Gas Gross Mmcf	Net Mmcf	NGL Gross Mbbl	Net Mbbl	Net Present Value Before Income Tax @ 10% M$	Unit Values $/bbl or $/mcf
									(3)	(3) (4)
CANADA(1)
Light and Medium Oil (including Associated Gas and By-products)
Proved Producing	1,676.0		1,584.0		981.0	781.0	25.0	17.0	55,751.0	35.19
Proved Non-Producing	-		-		-	-	-	-	(3,592.0)	n/a
Proved Undeveloped	8.0		8.0		34.0	32.0	1.0	1.0	284.0	37.13
Total Proved	1,684.0		1,592.0		1,015.0	813.0	26.0	18.0	52,443.0	32.95
Probable	847.0		754.0		690.0	562.0	16.0	12.0	25,299.0	33.53
Total Proved & Probable	2,531.0		2,346.0		1,705.0	1,375.0	42.0	30.0	77,742.0	33.14
Heavy Oil
Proved Producing	572.0		444.0		147.0	125.0	-	-	14,215.0	32.01
Proved Non-Producing	-		-		-	-	-	-	(356.9)	n/a
Proved Undeveloped	120.0		76.0		41.0	33.0	-	-	1,704.0	22.32
Total Proved	692.0		520.0		188.0	158.0	-	-	15,562.1	29.90
Probable	357.0		254.0		99.0	82.0	-	-	7,586.0	29.82
Total Proved & Probable	1,049.0		774.0		287.0	240.0	-	-	23,148.1	29.88
Natural Gas Liquids
Proved Producing		-		-	-	-	-	-	-	n/a
Proved Non-Producing		-		-	-	-	-	-	-	n/a
Proved Undeveloped		-		-	-	-	-	-	-	n/a
Total Proved		-		-	-	-	-	-	-	n/a
Probable		-		-	-	-	-	-	-	n/a
Total Proved & Probable		-		-	-	-	-	-	-	n/a
Natural Gas (including By-products)
Proved Producing	3.0		2.0		13,070.0	9,059.0	53.0	40.0	29,989.0	3.31
Proved Non-Producing	-		-		5,277.0	3,279.0	39.0	24.0	9,660.0	2.95
Proved Undeveloped	-		-		-	-	-	-	-	n/a
Total Proved	3.0		2.0		18,347.0	12,338.0	92.0	64.0	39.649.0	3.21
Probable	1.0		1.0		15,668.0	10,584.0	65.0	48.0	22,541.0	2.13
Total Proved & Probable	4.0		3.0		34,015.0	22,922.0	157.0	112.0	62,190.0	2.71
OKLAHOMA(2) (3)
Light and Medium Oil
Proved Producing	-		-		-	-	-	-	-	n/a
Proved Non-Producing	-		-		-	-	-	-	-	n/a
Proved Undeveloped	-		-		-	-	-	-	-	n/a
Total Proved	-		-		-	-	-	-	-	n/a
Probable	-		-		-	-	-	-	-	n/a
Total Proved & Probable	-		-		-	-	-	-	-	n/a
Heavy Oil
Proved Producing	-		-		-	-	-	-	-	n/a
Proved Non-Producing	-		-		-	-	-	-	-	n/a
Proved Undeveloped	-		-		-	-	-	-	-	n/a
Total Proved	-		-		-	-	-	-	-	n/a
Probable	-		-		-	-	-	-	-	n/a
Total Proved & Probable	-		-		-	-	-	-	-	n/a

Note:

(1)   Canada - from McDaniel Report.

(2)   Oklahoma - from Haas Report.

(3)   Oklahoma net present values and unit values have been converted to Cdn$ at 0.9514 exchange rate

(4)   Unit values are based on net reserve volumes

-  -

Oil and Gas Reserves and Net Present Values by Production Group – Continued

Forecast Prices as of December 31, 2009

Total Reserves

Reserves Group by Category	Oil Gross Mbbl	Net Mbbl	Gas Gross Mmcf	Net Mmcf	NGL Gross Mbbl	Net Mbbl	Net Present Value Before Income Tax @ 10% M$	Unit Values $/bbl or $/mcf
							(3)	(3) (4)
Natural Gas Liquids
Proved Producing	-	-	-	-	-	-	-	n/a
Proved Non-Producing	-	-	-	-	-	-	-	n/a
Proved Undeveloped	-	-	-	-	-	-	-	n/a
Total Proved	-	-	-	-	-	-	-	n/a
Probable	-	-	-	-	-	-	-	n/a
Total Proved & Probable	-	-	-	-	-	-	-	n/a
Natural Gas (including By-products)
Proved Producing	603.5	487.2	33,657.2	26,883.1	5,499.7	4,400.9	202,970.2	7.55
Proved Non-Producing	47.9	38.4	1,793.9	1,428.8	194.0	154.4	7,213.0	5.05
Proved Undeveloped	4.7	3.7	14,503.4	11,600.1	1,774.8	1,419.1	7,539.2	0.65
Total Proved	656.1	529.2	49,954.5	39,912.0	7,468.5	5,974.5	217,722.4	5.46
Probable	26.0	21.5	16,072.1	14,313.1	2,126.0	1,858.0	69,221.1	4.84
Total Proved & Probable	682.1	550.7	66,026.6	54,225.1	9,594.5	7,832.5	286,943.4	5.29
AGGREGATE
Light and Medium Oil (including Associated Gas and By-products)
Proved Producing	1,676.0	1,584.0	981.0	781.0	25.0	17.0	55,751.0	35.20
Proved Non-Producing	-	-	-	-	-	-	(3,592.0)	n/a
Proved Undeveloped	8.0	8.0	34.0	32.0	1.0	1.0	284	35.50
Total Proved	1,684.0	1,592.0	1,015.0	813.0	26.0	18.0	52,443.0	32.94
Probable	847.0	754.0	690.0	562.0	16.0	12.0	25,299.0	33.55
Total Proved & Probable	2,531.0	2,346.0	1,705.0	1,375.0	42.0	30.0	77,742.0	33.14
Heavy Oil
Proved Producing	572.0	444.0	147.0	125.0	-	-	14,215.0	32.01
Proved Non-Producing	-	-	-	-	-	-	(356.9)	n/a
Proved Undeveloped	120.0	76.0	41.0	33.0	-	-	1,704.0	22.32
Total Proved	692.0	520.0	188.0	158.0	-	-	15,562.1	29.90
Probable	357.0	254.0	99.0	82.0	-	-	7,586.0	29.82
Total Proved & Probable	1,049.0	774.0	287.0	240.0	-	-	23,148.1	29.88
Natural Gas Liquids
Proved Producing	-	-	-	-	-	-	-	n/a
Proved Non-Producing	-	-	-	-	-	-	-	n/a
Proved Undeveloped	-	-	-	-	-	-	-	n/a
Total Proved	-	-	-	-	-	-	-	n/a
Probable	-	-	-	-	-	-	-	n/a
Total Proved & Probable	-	-	-	-	-	-	-	n/a
Natural Gas (including By-products)
Proved Producing	606.5	489.2	46,727.2	35,942.1	5,552.7	4,440.9	232,959.2	6.48
Proved Non-Producing	47.9	38.4	7,070.9	4,707.8	233.0	178.4	16,873.0	3.58
Proved Undeveloped	4.7	3.7	14,503.4	11,600.1	1,774.8	1,419.1	7,539.2	0.65
Total Proved	659.1	531.2	68,301.5	52,250.0	7,560.5	6,038.5	257.371.4	4.93
Probable	27.0	22.5	31,740.1	24,897.1	2,191.0	1,906.0	91,762.1	3.69
Total Proved & Probable	686.1	553.7	100,041.6	77,147.1	9,751.5	7,944.5	349,133.4	4.53

Note:

(5)   Canada - from McDaniel Report.

(6)   Oklahoma - from Haas Report.

(7)   Oklahoma net present values and unit values have been converted to Cdn$ at 0.9514 exchange rate

(8)   Unit values are based on net reserve volumes

-  -

Pricing Assumptions (1)

Forecast Prices and Costs

Summary of Price Forecasts

December 31, 2009

Year	WTI Crude Oil $US/bbl	Edmonton Light Crude Oil $/bbl	Alberta Bow River Hardisty Crude Oil $/bbl	Alberta Heavy Crude Oil $/bbl	Sask. Cromer Medium Crude Oil $/bbl	Edmonton NGL Mix $/bbl	U.S. Henry Hub Gas Price $US/ Mmbtu	Alberta Average Plant gate $/Mmbtu	British Columbia Average Plant gate $/Mmbtu	Inflation %	US/CAN Exchange Rate  $US/$
	(2)	(3)	(4)	(5)	(6)	(7)		(8)
2009(8)	61.80	65.90	60.25	55.65	62.85	48.20	3.95	3.95	4.05	2.0	0.880
2010	80.00	83.20	72.30	68.10	76.50	60.30	6.05	5.85	5.85	2.0	0.950
2011	83.60	87.00	73.80	67.60	79.10	63.50	6.90	6.55	6.55	2.0	0.950
2012	87.40	91.00	74.40	68.00	81.80	66.50	7.30	6.95	6.95	2.0	0.950
2013	91.30	95.00	75.80	68.10	85.40	69.40	7.70	7.25	7.25	2.0	0.950
2014	95.30	99.20	79.20	71.10	89.20	72.50	8.15	7.60	7.60	2.0	0.950
2015	99.40	103.5	82.60	74.20	93.10	75.60	8.50	7.95	7.95	2.0	0.950
2016	101.40	105.60	84.30	75.70	94.90	77.20	8.75	8.15	8.15	2.0	0.950
2017	103.40	107.70	85.90	77.20	96.80	78.70	8.90	8.30	8.30	2.0	0.950
2018	105.40	109.80	87.60	78.70	98.70	80.30	9.10	8.45	8.45	2.0	0.950
2019	107.60	112.10	89.40	80.40	100.70	82.00	9.30	8.65	8.65	2.0	0.950
2020	109.70	114.30	91.20	81.90	102.70	83.60	9.45	8.80	8.80	2.0	0.950
2021	111.90	116.50	93.00	83.60	104.80	85.20	9.65	9.00	9.00	2.0	0.950
2022	114.10	118.80	94.80	85.20	106.80	86.90	9.85	9.20	9.20	2.0	0.950
2023	116.40	121.20	96.70	86.90	109.00	88.70	10.05	9.40	9.40	2.0	0.950
2024	118.80	123.70	98.70	88.70	111.20	90.50	10.25	9.60	9.60	2.0	0.950
Thereafter	+2%/yr	+2%/y	+2%/y	+2%/y	+2%/y	+2%/y	+2%/y	+2%/y	+2%/y	+2%/y	+2%/y

Note:

(1)   Pricing assumptions are from McDaniel December 31, 2009 forecast and are the same for the Haas and McDaniel reports

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

(3)   Edmonton Light Sweet 40 degrees API/0.3% sulphur

(4)   Bow River at Hardisty, Alberta (Heavy stream)

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

(6)   Midale Cromer crude oil 29 degrees API/2.0% sulphur

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

(8)   This forecast also applies to direct sales contracts and the Alberta gas reference price used in the crown royalty calculations.

-  -

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, 2009

Total of All Areas

	Light and Medium Crude Oil		Heavy Oil		Natural Gas Liquids		Natural Gas		Total
Reserves Category	Gross (mbbls)	Net (mbbls)	Gross (mbbls)	Net (mbbls)	Gross (mbbls)	Net (mbbls)	Gross (mmcf)	Net (mmcf)	Gross (mboe)	Net (mboe)
	(3)	(4)	(3)	(4)	(3)	(4)	(3)	(4)	(3)	(4)
CANADA(1)
Producing	1,637.1	1,614.1	567.2	445.6	61.2	44.6	11,983.5	8,738.1	4,262.8	3,560.7
Non-Producing	-	-	-	-	31.7	20.8	3,574.3	2,688.3	627.4	468.9
Proved Undeveloped	8.1	7.7	120.0	78.1	0.7	0.6	74.9	64.9	141.3	97.2
Total Proved	1,645.2	1,621.8	687.2	523.7	93.6	66.0	15,632.7	11,491.3	5,031.5	4,126.7
Probable	834.2	795.8	356.8	258.9	36.5	26.7	8,050.0	5,805.1	2,569.2	2,048.9
Total Proved plus Probable	2,479.4	2,417.6	1,044.0	782.6	130.1	92.7	23,682.7	17,296.4	7,600.6	6,175.6
OKLAHOMA(2)
Producing	583.5	471.1	-	-	5,272.5	4,219.4	31,625.3	25,261.2	11,126.9	8,900.7
Non-Producing	46.0	36.8	-	-	153.4	122.2	1,334.7	1,063.6	421.8	336.3
Proved Undeveloped	4.7	3.7	-	-	1,650.9	1,319.9	13,471.3	10,774.4	3,900.8	3,119.4
Total Proved	634.2	511.7		-	7,076.8	5,661.5	46,431.3	37,099.2	15,449.5	12,356.3
Probable	28.8	23.7	-	-	2,021.2	1,770.3	15,042.7	13,442.7	4,557.2	4,034.4
Total Proved plus Probable	663.0	535.4	-	-	9,098.0	7,431.7	61,474.0	50,541.8	20,006.6	16,390.8
AGGREGATE
Producing	2,220.6	2,085.2	567.2	445.6	5,333.7	4,264.0	43,608.8	33,999.3	15,389.6	12,461.4
Non-Producing	46.0	36.8	-	-	185.1	143.0	4,909.0	3,751.9	1,049.2	805.1
Proved Undeveloped	12.8	11.4	120.0	78.1	1,651.6	1,320.5	13,546.2	10,839.3	4,042.1	3,216.6
Total Proved	2,279.4	2,133.5	687.2	523.7	7,170.4	5,727.5	62,064.0	48,590.5	20,480.9	16,483.1
Probable	863.0	819.5	356.8	258.9	2,057.7	1,797.0	23,092.7	19,247.8	7.126.3	6,083.3
Total Proved plus Probable	3,142.4	2,953.0	1,044.0	782.6	9,228.1	7,524.4	85,156.7	67,838.2	27,607.3	22,566.4

Note:

(1)   Canada - from McDaniel Report.

(2)   Oklahoma - from Haas Report.

(3)   Gross refers to the Trust’s working interest before royalties.

(4)   Net refers to the Trust’s working interest after royalties plus royalty interest reserve.

-  -

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue

Constant Prices Case as of December 31, 2009

Total of All Areas

	Before Income Taxes Discounted at (%/year)					After Income Taxes Discounted at (%/year)
Reserves Category	0	5	10	15	20	0	5	10	15	20
	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
Producing	71.7	64.2	58.5	53.9	50.2	71.7	64.2	58.5	53.9	50.2
Non-Producing	(3.5)	(2.9)	(2.5)	(2.1)	(1.8)	(3.5)	(2.9)	(2.5)	(2.1)	(1.8)
Proved Undeveloped	1.7	1.5	1.3	1.1	1.0	1.7	1.5	1.3	1.1	1.0
Total Proved	70.0	62.8	57.3	53.0	49.4	70.0	62.8	57.3	53.0	49.4
Probable	45.2	34.8	28.0	23.2	19.7	45.2	34.8	28.0	23.2	19.7
Total Proved plus Probable	115.2	97.6	85.3	76.2	69.0	115.2	97.6	85.3	76.2	69.0
OKLAHOMA(2) (3)
Producing	165.4	132.8	110.0	95.5	84.0	153.1	119.8	98.1	83.0	72.1
Non-Producing	4.5	3.4	2.7	2.2	1.8	4.7	3.6	2.9	2.3	1.9
Proved Undeveloped	(15.1)	(21.6)	(25.4)	(27.5)	(28.6)	(8.2)	(13.7)	(17.2)	(19.3)	(20.5)
Total Proved	154.7	114.6	88.3	70.1	57.2	149.5	109.7	83.8	66.1	53.4
Probable	51.8	35.9	25.8	19.0	14.4	36.7	25.7	18.8	14.2	11.1
Total Proved plus Probable	206.6	150.6	114.0	89.2	71.6	186.3	135.3	102.6	80.3	64.5
AGGREGATE
Producing	237.1	197.0	169.4	149.4	134.2	224.8	184.0	156.6	137.0	122.3
Non-Producing	1.0	0.5	0.2	0.1	(0.1)	1.2	0.7	0.4	0.2	0.1
Proved Undeveloped	(13.4)	(20.1)	(24.1)	(26.4)	(27.6)	(6.5)	(12.2)	(15.9)	(18.2)	(19.5)
Total Proved	224.7	177.4	145.6	123.1	106.6	219.5	172.5	141.1	119.0	102.8
Probable	97.1	70.8	753.8	42.3	34.0	81.9	60.5	46.8	37.5	30.8
Total Proved plus Probable	321.8	248.2	199.4	165.3	140.6	301.5	232.9	187.9	156.5	133.6

Note:

(1)   Canada - from McDaniel Report.

(2)   Oklahoma - from Haas Report.

(3)   Oklahoma net present values have been converted to CDN$ at 0.9514 exchange rate.

-  -

Total Future Net Revenue (Undiscounted)

Constant Prices as of December 31, 2009

Total Reserves

	Revenue	Royalties	Operating Costs	Capital Development Costs	Abandonment Costs	Future Net Revenue Before Income Taxes	Income Taxes	Future Revenue After Income Taxes
Reserves Category	MM$	MM$	MM$	MM$	MM$	MM$	MM$	MM$
CANADA(1)
Total Proved	206.8	31.3.	89.5	1.7	14.3	70.0	-	70.0
Total Proved plus Probable	311.0	48.9	128.3	4.1	14.5	115.2	-	115.2
OKLAHOMA(2) (3)
Total Proved	439.0	107.6	112.2	60.2	4.3	154.8	5.2	149.6
Total Proved plus Probable	568.5	139.1	136.7	81.5	4.6	206.6	20.3	186.3
AGGREGATE
Total Proved	645.9	138.9	201.7	61.9	18.6	224.8	5.2	219.6
Total Proved plus Probable	879.5	188.0	265.0	85.6	19.1	321.8	20.3	301.5

Note:

(1)   Canada - from McDaniel Report.

(2)   Oklahoma - from Haas Report.

(3)   Oklahoma dollar values have been converted to CDN$ at 0.9514 exchange rate.

Oil and Gas Reserves and Net Present Values by Production Group

Constant Prices as of December 31, 2009

Total Reserves

	Discounted at 10% (4)
	Canada	Oklahoma	Total
				Unit Value
Reserves Category	MM$	MM$	MM$	$/bbl or $/mcf
		(3)		(2)
Proved
Light and Medium Crude Oil (1)	32.0	13.8	45.7	21.43
Heavy Oil	10.6	-	10.6	20.27
Natural Gas Liquids	2.1	45.2	47.3	8.25
Natural Gas	12.7	29.3	42.0	0.86
Total	57.3	88.3	145.6
Proved Plus Probable
Light and Medium Crude Oil (1)	47.3	14.1	61.4	20.81
Heavy Oil	16.0	-	16.0	20.49
Natural Gas Liquids	2.8	58.6	61.4	8.16
Natural Gas	19.2	41.3	60.5	0.89
Total	85.3	114.0	199.4

Note:

(1)   Including all by-products and NGLs

(2)   The unit values are based on net reserve volumes in CDN$.

(3)   Oklahoma net present values and unit values have been converted to CDN$ at 0.9514 exchange rate.

(4)   Net present values discounted at 10% are before tax.

-  -

Pricing Assumptions (1)

Constant Prices and Costs

Year	WTI @ Cushing ($US/bbl)	Edmonton Par Price 40° API ($/bbl)	Bow River Medium 25° API ($/bbl)	Cromer Medium ($/bbl)	US Henry Hub Gas Price ($US/Mmbtu)	Alberta Average Plant gate Price ($/Mmbtu)	Natural Gas Liquids FOB Edmonton ($/bbl)	Exchange Rate ($US/$)
2009	61.18	65.21	59.38	62.02	3.82	3.77	46.84	0.869

Note:

(1)Based on the average first-day-of-the-month price for the 12 months of 2009.

Reserves Reconciliation

Reconciliation of Gross Reserves by Product Type

Forecast Prices and Costs

	Light and Medium Crude Oil			Natural Gas Liquids
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]	[mbbl]
CANADA (1)
Opening balance – December 31, 2008	1,931.6	991.4	2,923.0	107.9	60.7	168.6
Extensions and Improved Recovery	-	-	-	5.1	-	5.1
Technical Revisions	338.2	(143.4)	194.8	34.3	20.3	54.6
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Production	(582.8)	-	(582.8)	(29.3)	-	(29.3)
Closing balance – December 31, 2009	1,687.0	848.0	2,535.0	118.0	81.0	199.0
UNITED STATES (2)
Opening balance – December 31, 2008	1,157.5	165.1	1,322.6	4,790.1	795.9	5,586.0
Extensions and Improved Recovery	3.9	1.1	5.0	40.6	11.9	52.5
Technical Revisions	(388.7)	(142.0)	(530.8)	3,068.7	1,301.0	4,369.7
Acquisitions	34.4	1.8	36.2	326.7	17.2	343.9
Dispositions	-	-	-	-	-	-
Production	(151.0)	-	(151.0)	(757.6)	-	(757.6)
Closing balance – December 31, 2009	656.1	26.0	682.1	7,468.5	2,126.0	9,594.5
AGGREGATE
Opening balance – December 31, 2008	3,089.1	1,156.5	4,245.6	4,898.0	856.6	5,754.6
Extensions and Improved Recovery	3.9	1.1	5.0	45.7	11.9	57.6
Technical Revisions	(50.5)	(285.4)	(336.0)	3,103.0	1,321.3	4,424.3
Acquisitions	34.4	1.8	36.2	326.7	17.2	343.9
Dispositions	-	-	-	-	-	-
Production	(733.8)	-	(733.8)	(786.9)	-	(786.9)
Closing balance – December 31, 2009	2,343.1	874.0	3,217.1	7,586.5	2,207.0	9,793.5

Note:

(1)   Canada - from McDaniel Report.

(2)   United States - from Haas Report.

-  -

Reconciliation of Company Gross Reserves by Product Type

Forecast Prices and Costs

	Associated and Non-Associated Gas			Heavy Oil
	Total Proved	Probable	Total Proved	Total Proved	Probable	Total Proved
	Reserves	Reserves	Plus Probable	Reserves	Reserves	Plus Probable
	[mmcf]	[mmcf]	[mmcf]	[mbbl]	[mbbl]	[mbbl]
CANADA (1)
Opening balance – December 31, 2008	22,832	18,106	40,938	976.4	518.2	1,494.6
Extensions and Improved Recovery	101.4	-	101.4	-	-	-
Technical Revisions	930.2	(1,648.7)	(718.5)	(3.8)	(161.2)	(165.0)
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-
Production	(4,312.5)	-	(4,312.5)	(280.6)	-	(280.6)
Closing balance – December 31, 2009	19,551.1	16,457.3	36,008.4	692.0	357.0	1,049.0
UNITED STATES (2)
Opening balance – December 31, 2008	40,291	9,994	50,285	-	-	-
Extensions and Improved Recovery	369.0	108.0	477.0	-	-	-
Technical Revisions	12,814.9	5,812.6	18,627.5	-	-	-
Acquisitions	2,991.9	157.5	3,149.4	-	-	-
Dispositions	-	-	-	-	-	-
Production	(6,512.3)	-	(6,512.3)	-	-	-
Closing balance – December 31, 2009	49,954.5	16,072.1	66,026.6	-	-	-
AGGREGATE
Opening balance – December 31, 2008	63,123	28,100	91,223	976.4	518.2	1,494.6
Extensions and Improved Recovery	470.4	108.0	578.4	-	-	-
Technical Revisions	13,744.1	4,163.6	17,907.7	(3.8)	(161.2)	(165.0)
Acquisitions	2,991.9	157.5	3,149.4	-	-	-
Dispositions	-	-	-	-	-	-
Production	(10,824.9)	-	(10,824.9)	(280.6)	-	(280.6)
Closing balance – December 31, 2009	69,504.5	32,529.1	102,033.6	692.0	357.0	1,049.0

Note:

(1)   Canada - from McDaniel Report.

(2)   United States - from Haas Report.

Undeveloped Reserves

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

Proved undeveloped and probable undeveloped reserves have been assigned to the Trust’s Canadian and Oklahoma properties.

Canada

Proved undeveloped reserves of 141.3 Mboe (91% oil and NGL) have been assigned in the McDaniel report, representing 2.5% of the Canadian proved reserves on a boe basis.  These proved undeveloped reserves are associated with 3 oil well drilling locations.  Two are located within the Primate, Saskatchewan property, and one is located within the Halkirk, Alberta property.

Probable undeveloped reserves of 1,179 Mboe (22% oil and NGL) have been assigned in the McDaniel report, representing 12% of the Canadian proved plus probable reserves on a boe basis.  These probable undeveloped reserves are associated with 10 additional well locations, in addition to probable reserves assigned to the 3 proved undeveloped wells described above.  Of these 10 additional well locations, one is located within the Primate property, two within the Halkirk property, one within the Princess, Alberta property, and six are located within the Desan, BC property.

In 2009, the Trust drilled 2 undeveloped locations in Canada, resulting in developed reserves of 22 Mboe in the proved category (as of the December 31, 2009 effective date of the McDaniel evaluation).

Oklahoma

Proved undeveloped reserves of 4,197 Mboe (58% natural gas) have been assigned in the Haas report, representing 26% of the Oklahoma proved reserves on a boe basis.  These proved undeveloped reserves represent 24 well locations. All of the locations are in Lincoln County, including twenty-two locations in the established Twin Cities/Central Dolomite area, and one location in the adjacent Alpine area. One location is in the established Goodnight area of Lincoln County.

Probable undeveloped reserves of 1,983 Mboe (58% natural gas) have been assigned in the Haas report, representing 9% of the Oklahoma proved plus probable reserves on a boe basis. The probable undeveloped reserves are associated with 9 well locations.

Four of the probable undeveloped locations are in the Twin Cities/Central Dolomite area in Lincoln County. Of these four locations, none are associated with proved undeveloped reserves at the same locations. Five additional locations are in the adjacent Alpine area.

The Oklahoma assets provide a large inventory of undeveloped opportunity.  As the current undeveloped location inventory is developed, it is anticipated that additional undeveloped locations will be recognized by the Haas evaluators and added to the undeveloped inventory.

Significant Factors or Uncertainties Affecting Reserves Data

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

	Canada	Oklahoma	Total
	M$	M$	M$
		(1) (2)
Constant Prices and Costs – Proved Reserves (1)
2010	1,484	17,500	18,984
2011	-	27,840	27,840
2012	-	16,074	16,074
2013	-	260	260
2014	-	31	31
Remaining Years	200	-	200
Total Undiscounted	1,684	61,880	63,389
Total Discounted at 10% per Year	1,608	56,381	58,042
Forecast Prices and Costs – Proved Reserves (2)
2010	1,555	17,623	19,178
2011	-	28,624	28,624
2012	-	16,810	16,810
2013	-	245	245
2014	-	-	-
Remaining Years	225	-	225
Total Undiscounted	1,780	63,303	65,308
Total Discounted at 10% per Year	1,754	57,722	59,476
Forecast Prices and Costs – Proved Plus Probable Reserves (2)
2010	15,139	19,572	34,711
2011	104	40,161	40,265
2012	-	25,423	25,423
2013	-	387	387
2014	-	-	-
Remaining Years	225	33	258
Total Undiscounted	15,468	85,610	101,303
Total Discounted at 10% per Year	15,433	77,401	92,834

Note:

(1)   Oklahoma constant present values have been converted to CDN$ at 0.9514 exchange rate.

(2)   Oklahoma forecast present values have been converted to CDN$ at 0.9514 exchange rate.

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

The Trust expects to fund its total 2010 capital program with internally generated cash flow.

Other Oil & Gas Information

Principal Properties

The following is a description of the Trust’s material oil and natural gas properties as at December 31, 2009.  Production stated is sales production before deduction of royalties and includes royalty interests to the Trust and, unless otherwise stated, is the average daily production for December 2009.  Reserve amounts are total proved plus probable reserves based on forecast prices and costs, stated before deduction of royalties and include royalty interests as at December 31, 2009 based on forecast prices and costs as evaluated in the McDaniel and Haas reports (see “Reserve Data”).  The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as for all properties, due to the effects of aggregation.  Unless otherwise specified, gross and net acres and well count information are as at December 31, 2009.

Overview

The Trust’s production comes from Canadian and U.S. based operations.  The Canadian core areas lie in western Canada and include a variety of assets in the provinces of British Columbia, Alberta and Saskatchewan.  In northeastern British Columbia the Trust has a significant producing area at Desan.  The principal producing areas in Alberta are:  Clair, Provost-Halkirk-Alliance-Wainwright, Princess and Ricinus.  Saskatchewan production is located principally in the West-central region of the province at Primate and the Southwest region of the province at Liebenthal.  The U.S. core area assets are located mainly in the Grant, Lincoln and Logan counties of Oklahoma.  The Trust also has an inventory of minor producing assets, minor royalty interests, and various exploration and exploitation prospects on undeveloped lands in Alberta, British Columbia, Saskatchewan and Oklahoma.

British Columbia

Desan

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

Daily average production in Desan for December 2009 was 2.4 mmcf/d of natural gas and 27 bbl/d of natural gas liquids from a total of 18 producing wells.  Desan production is 100% working interest.  McDaniel has assigned total proven plus probable reserves of 12.9 Bcf of natural gas and 80 Mbbl of NGLs to the Desan property as of the December 31, 2009 effective date.

The Trust has 45 square kilometres (17 square miles) of 3D seismic and 61 kilometres (38 miles) of trade 2D seismic over the Desan area.  The Trust’s technical assessment of the seismic data currently indicates six potential Jean-Marie locations and three potential Debolt locations.  At year-end, the Trust held 24,590 net undeveloped acres in the Desan area.

Alberta

Clair

The Clair property is located North of Grande Prairie area of Alberta.  The Trust’s assets include a 100% working interest in 3,520 acres of land (480 net undeveloped acres), 16 producing wells, 5 water injection wells, and a profit sharing interest in an oil blending facility.  Gas is conserved and processed at the Encana Sexsmith gas plant.  Oil is delivered into the Pembina Peace Pipeline System.

Oil and gas production is primarily from the Doe Creek (Dunvegan) formation.  The Doe Creek oil pool produces light (41 API) oil along with solution gas and is currently under water flood to maximize oil recovery.  There is also gas production from one Charlie Lake well.  Average working interest production for December 2009 was 338 bbl/d of oil and 1,137 mcf/d of natural gas.  At year-end, the Trust held 1,340 net undeveloped acres in the Clair area.

McDaniel has assigned total proved plus probable reserves of 420 mbbl of crude oil, 0.7 Bcf of natural gas, and 35 mbbl of NGL to the Clair property as of the December 31, 2009 effective date.

Ricinus

Ricinus is located in the Rocky Mountain foothills, approximately 80 miles northwest of Calgary.  At Ricinus, the Trust holds a 45% working interest in a 2,800m (9,200 ft) high-rate, Leduc reef, sour gas well.  Production at Ricinus was shut-in July 2009 due to low gas prices coupled with uneconomic third-party processing fees.  Subsequent to year-end, the Trust has acquired a working interest in the connected gas processing facility and anticipates that production will resume in the second quarter of 2010.  At the time of shut-in, production net to The Trust totalled 450 boe/d.  This well has the capability to produce at higher rates but has been limited to maximize reserve recovery.

McDaniel assigned proved plus probable reserves of 8.2 Bcf of natural gas and 22 mbbl of NGLs as of the December 31, 2009 effective date.

Provost-Hallkirk-Alliance-Wainwright

The Trust’s assets in the Provost-Hallkirk-Alliance-Wainwright producing area of east central Alberta include production from the areas of:  Alliance, Sounding Lake, Soapy Lake, Halkirk, Monitor, Provost and Wainwright.  The Trust currently has 178 producing oil and gas wells in this area.  Net undeveloped acreage totalled 6,181 acres at year-end.

Production is obtained primarily from the Dina, Cummings, Sparky and Belly River formations.  Average working interest production for December 2009 was 715 bbl/d of oil and NGLs and 876 mcf/d of natural gas.  The Trust continues to optimize well pumping systems and upgrade or consolidate oil batteries and water injection facilities to handle produced fluid volumes more efficiently.  Solution gas is conserved at most of the oil batteries.

McDaniel has assigned total proved plus probable reserves of 1,810 mbbl of oil, 1.9 Bcf of natural gas and 46 mbbl of NGLs in the Provost-Hallkirk-Alliance-Wainwright area as of the December 31, 2009 effective date.

Princess

Princess is located approximately 100 miles southeast of Calgary.  The primary production is crude oil (27 API) from the Pekisko formation.  Much of the Trust’s land is covered by 3D seismic with detailed geological and geophysical studies outlining new development drilling opportunities.  Additionally, significant potential lies in the Bow Island and Sunburst formations.  At year-end, The Trust had 23 producing wells in the Princess area with average working interest production of  332 bbl/d of crude oil and NGL and 747 mcf/d of natural gas.  Net undeveloped acreage totalled 1,222 acres at year-end.

McDaniel assigned total proved plus probable reserves in the Princess area of 495 Mbbl of crude oil, 1.0  Bcf of natural gas and 16 mbbl of NGLs  in the Princess area as of December 31, 2009 effective date.

Saskatchewan

The Trust’s assets in west central Saskatchewan are focused in the Primate and Liebenthal areas.

Primate

The Primate heavy oil field is the main producing asset in the Primate area and the Trust holds a 100% working interest in this property.  Oil and gas production comes primarily from the McLaren and Mannville formations respectively.  Despite the oil’s gravity, 11 API, the gas saturation of the reservoir allows cold production of the oil under a primary recovery scheme.  The Trust is studying secondary recovery opportunities in the main Primate oil pool to further enhance recovery.  At year-end, the Trust had 25 producing wells in the Primate area

Average December 2009 production from the Primate area was 571 bbls/day of crude oil and 1,550 mcf/day of natural gas.  McDaniel assigned total proved plus probable reserves in Primate of 740 mbbl of crude oil and 2.0 Bcf of natural gas as of December 31, 2009 effective date.

Liebenthal

Gas production from the Liebenthal area comes from the Viking formation.  The Trust holds a 100% working interest in two prolific wells in the pool.  Seismic indicates that the pool is structurally controlled.  Average December 2009 production from the Liebenthal area was 3,495 mcf/day of natural gas.

Oklahoma

In Oklahoma the key producing horizon is the Hunton formation.  The Hunton is a carbonate rock formation which has been largely ignored by the industry in areas with high water/hydrocarbon production ratios.  Over the last decade, new drilling and production techniques have enabled profitable development of the Hunton formation.  Extensive dewatering lowers reservoir pressure allowing the liberation and mobilization of oil, natural gas liquids and gas from smaller rock pores.  Typical peak hydrocarbon production rates average 150 boe/d per horizontal well and are generally observed within six months of production commencement.

Average production for December 2009 in Oklahoma was 15.4 Mmcf/d of natural gas and 3,137 bbl/d of crude oil and NGLs.  Haas has attributed total proved and probable reserves of 682 Mbbl of crude oil, and 66 Bcf of natural gas and 9,595 mbbl of NGLs to Oklahoma as of the December 31, 2009 effective date.  The Trust maintains a U.S. office located in Oklahoma City and a field office in Carney, Oklahoma.

In Oklahoma there are approximately 45,480 net undeveloped acres of land, at year end 2009. This acreage is centered in Alfalfa, Grant, Lincoln, Logan and Jefferson counties.

On December 14, 2009 the Trust provided notice of termination of the farm-out agreement to its partner as a result of their non-performance under the agreement to develop the Hunton formation.  As a result, the Trust will increase its working interest in future Hunton wells to approximately 85% with incidental partners participating for the balance.

Oil and Gas Wells

The following table summarizes the Trust’s interest as at December 31, 2009 in wells that are producing and non-producing:

	Producing				Non-Producing
	Oil		Gas		Oil		Gas		Grand Total
State/Province	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	242	154.8	20	12.7	318	229.3	80	57.7	660	454.5
British Columbia	-	-	23	23.0	-	-	17	17.0	40	40.0
Saskatchewan	14	14.0	13	13.0	4	4.0	16	16.0	47	47.0
Total	256	168.8	56	48.7	322	233.3	113	90.7	747	541.5
Oklahoma	-	-	154	95.8	-	-	53	36.9	207	132.7
Grand Total	256	168.8	210	144.5	322	233.3	166	127.6	954	674.2

- Note this table does not include service/disposal wells.

Land Holdings

The following table summarizes land holdings in which the Trust has an interest at December 31, 2009.

Area	Gross Acres	Net Acres
Canada	307,756	153,056
United States	137,473	77,369
Total	445,229	230,425

The acreage to expire in 2010 in Canada is 4,349.9 (net) and in the U.S. 9,496.6 (net).

Environmental Protection

The Trust’s 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 the Trust to remove or remedy the effect of its activities on the environment at present and former operating sites, including dismantling production facilities and remediating damage caused by the use or release of specified substances.  The applicable regulatory agencies review the Trust’s compliance with applicable laws and regulations.  Monitoring and reporting programs, as wells as inspections and assessments for environment, health and safety performance in day-to-day operations, 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.

The Trust currently owns or leases, and has in the past owned or leased, properties that have been used for oil and natural gas exploration and production activities for many years.  Although operating and disposal practices have been used 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 the Trust.  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 the Trust’s 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, the Trust could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination. The Trust is currently involved in several remediation projects but it does not believe these costs to be material to the Trust’s operations or financial position.

During 2009, the Trust during normal operating procedures had reportable occurrences of oil and water spills that have all been identified and have been or are currently being remedied as per the legislative regulations and requirements.

Abandonment and Reclamation Costs

Well abandonment costs are estimated 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 are $21.7 million and the next three years of estimated abandonment costs included in the Reserve Reports under the proved reserves category is as follows.

	3 Year Abandonment
Area	Undiscounted	Discounted at 10%
Canada	4.3	3.7
United States	0.3	0.3
Total	4.6	4.1

Tax Horizon

Canadian

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

United States

The income from U.S. operations is subject to United States income tax under U.S. income tax rules and regulations.  As a result, the Trust’s U.S. operations may incur cash U.S. income taxes in the future but there is no current tax in 2009.  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 the Trust for the year ended December 31, 2009:

	(millions of dollars)
	Canada		United States		Total
Property acquisition costs(1)
Proved		-		9.0		9.0
Unproved		3.2		5.2		8.4
Exploration costs		0.4		-		0.4
Development costs		5.5		1.6		7.1
Total costs incurred		9.1		15.8		24.9

(1) Includes costs related to corporate acquisitions.

-  -

Exploration and Development Activities

The following table sets forth the gross and net development wells that were participated in during the year ended December 31, 2009. In the farm-in arrangement with the U.S. Farmout Partner in Oklahoma, the Trust has a carried interest in producing wells.  The carried interest in the producing wells is shown in this table for wells associated with this arrangement.

	Exploration Wells				Development Wells				Total Wells
	Canada		United States		Canada		United States
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Light and Medium Oil	-	-	-	-	-	-	-	-	-	-
Natural Gas	-	-	-	-	1.0	1.0	3.0	0.7	4.0	1.5
Service	-	-	-	-	-	-	1.0	1.0	1.0	1.0
Dry	1.0	0.8	-	-			-	-	1.0	1.0
Total	1.0	0.8	-	-	1.0	1.0	4.0	1.7	6.0	3.5

Production Volume by Field

The following table discloses for each major field, and in total, the Trust’s production volumes for the financial year ended December 31, 2009 for each product type.

	Light and Medium Crude Oil (bbls)	Heavy Oil (bbls)	Natural Gas Liquids (bbls)	Natural Gas (mcf)	Total (boe)
Clair	127,692	-	7,534	263,349	179,118
Provost	296,197	42,517	12,034	353,138	409,604
Brooks	114,101	-	3,722	224,434	155,229
Desan	2,469	-	4,980	1,133,543	196,372
Saskatchewan	9,024	237,664	-	1,811,330	548,576
Ricinus	13	-	816	516,107	86,846
Other Canadian	33,718	-	216	10,644	35,710
Oklahoma	150,992	-	757,558	6,512,333	1,993,938
	734,206	280,181	786,860	10,824,878	3,605,393

Production Estimates

The following table discloses, for each product type, the total volume of production estimated by McDaniel and Haas for 2010 in the estimates of future net revenue from proved reserves disclosed 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 2010 Production Estimated

Forecast Prices and Costs

	Light and				Natural
	Medium				Gas		Natural
	Crude Oil		Heavy Oil		Liquids		Gas		Total
	Gross		Gross		Gross		Gross		Gross
Reserve Category	[mbbl]		[mbbl]		[mbbl]		[mmcf]		[mBOE]
CANADA (McDaniel Report)
Proved
Producing		541.8		184.5		24.2		3,679.9		1,363.8
Non-Producing		-		-		1.9		523.7		89.2
Undeveloped		17.6		1.2		0.1		12.1		20.9
Total Proved		559.4		185.7		26.2		4,215.7		1,473.9
Probable		51.1		17.2		3.7		471.0		150.5
Total Proved plus Probable		610.5		202.9		29.9		4,686.7		1,624.4
OKLAHOMA (Haas Report)
Proved
Producing		102.0		-		775.3		4,907.6		1,695.2
Non-Producing		0.9		-		6.5		68.9		18.9
Undeveloped		0.1		-		2.7		18.3		5.9
Total Proved		103.0		-		784.5		4,994.8		1,720.0
Probable		1.5		-		64.6		371.5		128.1
Total Proved plus Probable		104.5		-		849.2		5,366.4		1,848.1
AGGREGATE
Proved
Producing		643.8		184.5		799.5		8,587.5		3,059.0
Non-Producing		0.9		-		8.4		592.6		108.1
Undeveloped		17.7		1.2		2.8		30.4		26.8
Total Proved		662.3		185.7		810.7		9,210.5		3,193.9
Probable		52.6		17.2		68.3		842.5		278.6
Total Proved plus Probable		715.0		202.9		879.1		10,053.1		3,472.5

Quarterly Data

The following table discloses, on a quarterly basis for the year ended December 31, 2009, the Trust’s 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 2009
	March 31	June 30	September 30	December 31
Average Daily Production
Oil (bbl/d)	3,126	2,786	2,682	2,530
NGL (bbl/d)	1,058	2,039	2,729	2,749
Natural Gas (Mcf/d)	34,557	31,407	26,977	25,815
Combined (BOE/d)	9,968	10,059	9,907	9,582
Average Prices Received
Oil ($/bbl)	54.99	63.48	63.68	69.81
NGL (bbl/d)	31.12	28.63	25.67	41.63
Natural Gas ($/Mcf)	4.78	3.43	3.30	4.01
Netback
Revenues – combined ($/boe)(1)	46.69	34.09	33.30	42.04
Royalties – combined ($/boe)	7.25	5.92	6.69	9.70
Operating Expenses – combined ($/boe)	12.61	12.19	8.56	10.25
Transportation Expenses – combined ($/boe)	0.54	0.78	0.77	0.59
Operating Netback Received - combined ($/boe)	26.29	15.20	17.28	21.50

Note:

(1)   Prior to unrealized mark-to-market

RESERVE DATA CHANGES SINCE DECEMBER 31, 2009

On January 28, 2010, the Trust entered into a definitive purchase and sale agreement to acquire an interest in the Caroline Swan Hills Gas Unit # 1 and associated processing facilities. The acquisition closed on March 8, 2010. The acquisition increases the Trust’s reserves by approximately 830 mboe liquids rich gas reserves on a proved plus probable basis (2.6% of current proven plus probable reserves). The purchase price was $12.7 million with adjustments to the effective date of the transaction which was November 1, 2009.

CAPITAL STRUCTURE

The Trust Indenture

The Trust’s 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 its Unitholders on a monthly basis at the discretion of the Trust.

Trust Units and Other Securities

Trust Units

An unlimited number of trust units may be created and issued pursuant to the Trust Indenture.  Each trust unit entitles the holder thereof to one vote at any meeting of the holders of trust units and represents an equal fractional undivided beneficial interest in any distribution from the Trust (whether of net income, net realized capital gains or other amounts) and in any net assets of the Trust in the event of termination or winding up of the Trust.  All trust units rank among themselves equally and 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 "Redemption Right”) and to one vote at all meetings of Unitholders for each trust unit held.  In addition, in certain circumstances Unitholders will have the right to instruct the trustees of EEC Trust with respect to the voting of shares of Enterra held by EEC Trust at meetings of holders of shares of Enterra.

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

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

The trust units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and 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 the Trust’s 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 the Trust to the Operating Subsidiaries or as principal repayments are made on the notes.  Interest for each month is payable monthly in arrears on the 15th 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. In 2009 the interest rate was adjusted but this interest rate has no effect on the unitholders.

Income Streams

A portion of the cash flows generated by the assets held, directly or indirectly, by the Trust is distributed to its Unitholders.  The Trustee may, upon the recommendation of the board of EEC in respect of any period, declare payable to the 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

The Trust Indenture provides that no Unitholder, in its capacity as such, shall incur or be subject to any liability in contract or in tort 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 the Trust Indenture, the Trust will indemnify and hold harmless each Unitholder from any costs, damages, liabilities, expenses, charges or losses suffered by a Unitholder from or arising as a result of such Unitholder not having such limited liability.

The Trust Indenture provides that all contracts signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Unitholders personally.  Notwithstanding the terms of the Trust Indenture, Unitholders may not be protected from liabilities of the Trust to the same extent a shareholder is protected from the liabilities of a corporation.

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 the Unitholders for claims against the Trust 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

The Trust Indenture provides that Trust Units, including rights, warrants (including so called “special warrants” which may be exercisable for no additional consideration) and other securities to purchase, to convert into or to exchange into Trust Units, may be created, issued, sold and delivered on such terms and conditions and at such times as the Trustee may determine, including, without limitation, instalment or subscription receipts.  The Trust Indenture also provides that the 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 the 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 the Unitholders. The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions as trustee honestly, in good faith and in the best interests of the Trust and the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

The initial term of the Trustee’s appointment was until the third annual meeting of Unitholders in May, 2006.  At the June 2007 annual meeting, the Unitholders re-appointed Olympia Trust Company as Trustee for an additional three year term, and thereafter, the Unitholders shall reappoint or appoint a successor to the Trustee at the annual meeting of Unitholders three years following the reappointment or appointment of the successor to the Trustee. The Trustee may also be removed by special resolution of Unitholders.  Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

Liability of the Trustee

The Trustee, its directors, officers, employees, shareholders and agents are not liable to any Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to the Trust or the property of the Trust, arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, any action taken or not taken in good faith in reliance on any documents that are, prima facie, properly executed, any depreciation of, or loss to, the property of the Trust incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by any other appropriately qualified person, any reliance on any such evaluation, any action or failure to act of EEC, or any other person to whom the Trustee has, with the consent of EEC, delegated any of its duties hereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by EEC to perform its duties under or delegated to it under the Trust Indenture or any other contract), unless such liabilities arise out of the gross negligence, wilful default or fraud of the Trustee or any of its directors, officers, employees or shareholders. If the Trustee has retained an appropriate expert, adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture, the Trustee may act or refuse to act based on the advice of such expert, adviser or legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based on the advice of any such expert, adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the property of the Trust. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee.

Special Voting Rights

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

Holders of Special Voting Rights are not entitled to any distributions of any nature whatsoever from the Trust.  Each holder is entitled to attend and vote at meetings of Unitholders according to the terms of the instrument pursuant to which the Special Voting Rights are issued.  Each holder of outstanding Special Voting Rights is entitled to that number of votes equal to the number of votes attached to the Trust Units for which the securities relating to such Special Voting Rights held by such holder are exchangeable, exercisable or convertible.  Holders of Special Voting Rights are also entitled to receive all notices, communications or other documentation required to be given or otherwise sent to Unitholders. Except for the right to attend and vote at meetings of Unitholders and receive notices, communications and other documentation sent to Unitholders, the Special Voting Rights do not confer upon the holders thereof any other rights.

Redemption Right

The 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 the 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.

For the purposes of this calculation, “market price” is an amount equal to the simple average of the closing price of the Trust Units for each of the trading days on which there was a closing price; provided that, if the applicable exchange or market does not provide a closing price but only provides the highest and lowest prices of the Trust Units traded on a particular day, the market price shall be an amount equal to the simple average of the average of the highest and lowest prices for each of the trading days on which there was a trade; and provided further that if there was trading on the applicable exchange or market for fewer than five of the 10 trading days, the market price shall be the simple average of the following prices established for each of the 10 trading days: the average of the last bid and last ask prices for each day on which there was no trading; the closing price of the Trust Units for each day that there was trading if the exchange or market provides a closing price; and the average of the highest and lowest prices of the Trust Units for each day that there was trading, if the market provides only the highest and lowest prices of Trust Units traded on a particular day. The closing market price is: an amount equal to the closing price of the Trust Units if there was a trade on the date; an amount equal to the average of the highest and lowest prices of the Trust Units if there was trading and the exchange or other market provides only the highest and lowest prices of Trust Units traded on a particular day; and the average of the last bid and last ask prices if there was no trading on the date.

The Trust 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 the Trust may, at its sole discretion, waive such limitation in respect of any calendar month. If this limitation is not so waived, the Market Redemption Price payable by the Trust in respect of Trust Units tendered for redemption in such calendar month will be paid on the last day of the following month as follows: (i) firstly, by the Trust distributing Series Notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the Trust Units tendered for redemption, and (ii) secondly, to the extent that the Trust does not hold Series 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 the 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) the outstanding Trust Units are not listed for trading on the Toronto Stock Exchange or New York Stock Exchange and are not traded or quoted on any other stock exchange or market which EEC considers, in its sole discretion, provides representative fair market value price for the Trust Units, or (ii) trading of the outstanding Trust Units is suspended or halted on any stock exchange on which the Trust Units are listed for trading or, if not so listed, on any market on which the Trust Units are quoted for trading, on the date such Trust Units are tendered for redemption or for more than five trading days during the 10 trading day period, commencing immediately after the date such Trust Units were tendered for redemption then such Unitholder shall, instead of the Market Redemption Price, be entitled to receive a price per Trust Unit (the “Appraised Redemption Price”) equal to 90% of the fair market value thereof as determined by 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 cash payment; or (ii) 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 the Trust Units to dispose of their Trust Units. Series Notes or Redemption Notes, which may be distributed in specie to Unitholders in connection with 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

The Trust Indenture provides that meetings of the Trust’s Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of the auditors, the approval of amendments to the Trust Indenture (except as described under “Amendments to the Trust Indenture”), the sale of the property of the Trust as an entirety or substantially as an entirety, and the commencement of winding up the affairs of the Trust.

A meeting of the Unitholders may be convened at any time and for any purpose by the Trustee and must be convened, except in certain circumstances, if requisitioned in writing by: (i) EEC; or (ii) the holders of Trust Units and Special Voting Rights holding in aggregate not less than 5% of the votes entitled to be voted at a meeting of the 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.

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

Exercise of Voting Rights

 The Trustee is prohibited from authorizing or approving:

•   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 toin the first bulleted paragraph above;

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

In addition, the Trustee is prohibited from authorizing 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 the Trust’s Unitholders by Special Resolution at a meeting of Unitholders called for that purpose.

Finally, the 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 the Trust’s Unitholders by ordinary resolution or special resolution, as the case may be.

Amendments to the Trust Indenture

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

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

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

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

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

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

Takeover Bid

The Trust Indenture contains provisions to the effect that if a takeover bid is made for the Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Unitholders who did not accept the take-over bid on the terms offered by the offeror.  In the event of a take-over bid for the 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 the 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 the Unitholders.

Unless the Trust is earlier terminated or extended by vote of the 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, the Trustee will sell and convert into money the property of the Trust in one transaction or in a series of transactions at public or private sale and do all other acts appropriate to liquidate the property of the Trust in accordance with any applicable laws or requirements of any governmental agency or authority, and shall in all respects act in accordance with the directions, if any, of the Unitholders in respect of 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, the 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 the Unitholders in accordance with their pro rata interests.

Reporting to Unitholders

An independent recognized firm of chartered accountants audits the financial statements of the Trust annually.  The audited consolidated financial statements of the Trust, together with the report of such chartered accountants, will be mailed by the Trustee to Unitholders and the unaudited interim financial statements of the Trust will be mailed to Unitholders within the periods prescribed by securities legislation. The year-end of the Trust is December 31.  The Trust is subject to the continuous disclosure obligations under all applicable securities legislation.

The Trust is subject to the reporting requirements of the U.S. Exchange Act applicable to foreign private issuers, and in connection therewith will file or submit reports, including annual reports and other information with the SEC.  Such reports and other information can be inspected and copied at the public reference facilities maintained by the SEC at 450 Fifth Street, N.W., Room 1024, Judiciary Plaza, Washington, D.C. The Trust’s SEC filings and submissions are also available to the public on the SEC’s web site at www.sec.gov.

Description of Debentures

General

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

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

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

The principal amount of the Debentures is payable in lawful money of Canada or, at the Trust’s option and subject to applicable regulatory approval, by payment of Trust Units as further described under “Payment upon Redemption or Maturity” and “Redemption and Purchase”. The interest on these Debentures is payable in lawful money of Canada including, at the Trust’s 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 the Trust from incurring additional indebtedness or liabilities or from mortgaging, pledging or charging its properties to secure any indebtedness.

Conversion Privilege

The Trust’s 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 the Trust for redemption of the Debentures, at a conversion price of $9.25 and $6.80 per Trust Unit respectively, being a conversion rate of 108.1081 and 147.0588 Trust Units for each $1,000 principal amount of Debentures respectively. Holders converting their Debentures will receive all accrued and unpaid interest thereon in cash to the date of conversion.

Subject to the provisions thereof, the Debenture Indenture provides for the adjustment of the conversion price in certain events including: (a) the subdivision or consolidation of the outstanding Trust Units; (b) the distribution of the Trust Units to holders of Trust Units by way of distribution or otherwise other than an issue of securities to holders of Trust Units who have elected to receive distributions in securities of the Trust in lieu of receiving cash distributions paid in the ordinary course; (c) the issuance of options, rights or warrants to all or substantially all of the holders of the Trust Units entitling them to acquire Enterra’s Trust Units or other securities convertible into the Trust Units at less than 95% of the then current market price (as defined below) of the Trust Units; and (d) the distribution to all or substantially all of the holders of  Trust Units of any securities or assets (other than cash distributions and equivalent distributions in securities paid in lieu of cash distributions in the ordinary course). There will be no adjustment of the conversion price in respect of any event described in (b), (c) or (d) above if the holders of the Trust’s Debentures are allowed to participate as though they had converted their Debentures prior to the applicable record date or effective date.  The Trust is not required to make adjustments in the conversion price unless the cumulative effect of such adjustments would change the conversion price by at least 1%.

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

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

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

Redemption and Purchase

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

In the case of redemption of less than all of the 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.

The Trust has the right to purchase the Debentures in the market, by tender or by private contract.

Payment upon Redemption or Maturity

On redemption or at maturity, the Trust will, subject to the Trust’s option to make such repayment in Trust Units as described below, repay the indebtedness represented by these 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.  The Trust may, at its option, on not more than 60 and not less than 40 days prior notice and subject to applicable regulatory approval, elect to satisfy the 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 tradable 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 the 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 the Trust 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, the Trust’s Debentures is subordinated in right of payment, as set forth in the Debenture Indenture, to the prior payment in full of all of the Senior Indebtedness and indebtedness to the Trust’s 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 the Trust’s indebtedness (whether outstanding as at the date of the Debenture Indenture or thereafter incurred), other than indebtedness evidenced by the 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, the Trust’s 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 the other present and future subordinated and unsecured indebtedness except for sinking provisions (if any) applicable to different series of Debentures or similar types of obligations.

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

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

Priority over Trust Distributions

The Trust Indenture provides that certain expenses of the Trust must be deducted in calculating the amount to be distributed to the Unitholders.  Accordingly, the funds required to satisfy the interest payable on the Debentures, as well as the amount payable upon redemption or maturity of the 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 the 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 the Trust Units (a “Change of Control”), the Trust is required to make an offer in writing to purchase all of the 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 the Trust 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 the Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to the Trust pursuant to the Offer, the Trust will have the right and obligation to redeem all the remaining Debentures at the Offer Price. Notice of such redemption must be given by the Trust 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 the Debentures not tendered pursuant to the Offer.

Interest Payment Option

The Trust may elect, from time to time, to satisfy its obligation to pay interest on the 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 the Trust of the Trust Units, (b) accept bids with respect to, and consummate sales of, such Trust Units, at the Trust’s 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.

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

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

Events of Default

The Debenture Indenture provides that an event of default (“Event of Default”) in respect of the Trust’s Debentures will occur if any one or more of the following described events has occurred and is continuing with respect to the Debentures: (a) failure for 10 days to pay interest on the Debentures when due; (b) failure to pay principal or premium, if any, when due on the Debentures, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of 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 the Trust specifying such default and requiring the Trust 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 the Trust’s Debentures which is a take-over bid for the Debentures within the meaning of the Securities Act (Alberta) and not less than 90% of the 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 the 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 the 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 the Trust shall not issue additional convertible Debentures of equal ranking if the principal amount of all of the 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 the Trust’s issued and outstanding Debentures which are convertible at the option of the holder into Trust Units plus the amount obtained by multiplying the number of issued and outstanding Trust Units by the current market price of the Trust Units on the relevant date.

Book-Entry System for Debentures

The Trust’s 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 the Debentures are made only through the depository service of CDS.

Except as described below, a purchaser acquiring a beneficial interest in the 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.

The Trust assumes no liability for: (a) any aspect of the records relating to the beneficial ownership of the Debentures held by CDS or the payments relating thereto; (b) maintaining, supervising or reviewing any records relating to the 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 the Debentures paid by the Trust or on the Trust’s behalf to CDS.

The Debentures are issued to Beneficial Owners in fully registered and certificate form (the “Debenture Certificates”) only if: (a)are required to do so by applicable law; (b) the book-entry only system ceases to exist; (c)or CDS advises the Debenture Trustee that CDS is no longer willing or able to properly discharge its responsibilities as depositary with respect to the Debentures and the Trust unable to locate a qualified successor; (d) the Trust, at its option, decides 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 the Debentures and receipt of instructions from CDS for the new registrations, the Debenture Trustee will deliver the Debentures in the form of Debenture Certificates and thereafter the Trust will recognize the holders of such Debenture Certificates as Debenture holders under the Debenture Indenture.

Interest on the 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 the 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 the Trust Units if applicable, and interest due, at maturity or on a redemption date, will be paid upon surrender thereof at any office of the Debenture Trustee or as otherwise specified in the Debenture Indenture.

Exchangeable Shares

EEC Exchangeable Shares

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

RMAC Exchangeable Shares

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

RMG Exchangeable Shares

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

MARKET FOR SECURITIES

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

	Toronto Stock Exchange						New York Stock Exchange
	High ($)		Low ($)		Volume (000’s)		High (US$)		Low (US$)		Volume
2009
January		0.91		0.57		533,300		0.77		0.44		3,270,100
February		0.73		0.53		576,800		0.65		0.43		1,973,500
March		0.92		0.55		914,600		0.71		0.43		2,945,700
April		1.56		0.74		2,612,100		1.35		0.59		6,452.500
May		1.68		1.20		1,258,900		1.53		1.20		6,458,900
June		1.96		1.44		1,120,300		1.79		1.58		6,811,000
July		1.25		1.19		472,600		1.35		1.00		3,583,900
August		1.50		1.25		284,600		1.39		1.14		3,577,900
September		1.43		1.21		620,300		1.35		1.09		4,123,100
October		1.91		1.22		939,900		1.84		1.14		7,538,100
November		1.69		1.50		417,800		1.71		1.28		3,912,100
December		2.25		1.50		1,365,900		2.16		1.48		9,596,600
2010
January		2.88		1.84		5,536,700		2.42		1.72		7,984,500
February		3.04		1.92		2,312,900		2.94		1.79		9,563,100
March(1)		3.03		2.55		4,743,430		2.95		2.51		6,080,889

(1)   Information to March 25, 2010.

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

	Toronto Stock Exchange (ENT.DB)						Toronto Stock Exchange (ENT.DB.A)
	High ($)		Low ($)		Volume		High ($)		Low ($)		Volume
2009
January		66.00		55.00		3,550		70.00		55.00		1,520
February		65.01		55.00		10,300		65.00		58.00		1,100
March		68.25		50.00		2,210		62.50		59.00		730
April		69.00		62.90		9,420		69.00		59.00		10,900
May		75.00		65.00		1,470		78.00		66.50		10,770
June		79.00		61.00		10,750		82.00		73.50		4,640
July		87.86		74.55		4,890		85.00		80.00		16,940
August		86.00		81.00		20,770		83.50		78.00		16,280
September		81.30		84.00		2,510		83.50		82.00		1,830
October		84.00		93.00		24,270		95.00		83.25		20,710
November		95.00		91.01		14,040		96.00		90.51		9,280
December		96.25		92.60		14,770		96.00		95.25		12,670
2010
January		100.49		95.02		18,730		99.75		95.79		25,550
February		100.00		98.00		24,240		100.49		98.00		20,300
March(1)		100.99		99.00		50,550		101.00		99.25		23,060

(1)   Information to March 25, 2009.

DISTRIBUTIONS

Cash distributions are made on the 15th day of each month or the first business day thereafter to Unitholders of record on the immediately preceding distribution record date (or such other payment and/or record date as may be determined by the Trustee on the recommendation of the board of EEC).  On September 17, 2007 the Trust suspended its monthly distributions in order to redirect its cash flow to the repayment of its outstanding debt. In 2008 no distributions were made.

The following table sets forth the amount of monthly cash distributions per Trust Unit that has been paid since inception.

Month of record (US$)	2009		2008		2007		2006		2005		2004		2003
January		-		-	$	0.12	$	0.18	$	0.14	$	0.10
February		-		-	$	0.06	$	0.18	$	0.14	$	0.10
March		-		-	$	0.06	$	0.18	$	0.15	$	0.11
April		-		-	$	0.06	$	0.18	$	0.15	$	0.11
May		-		-	$	0.06	$	0.18	$	0.15	$	0.11
June		-		-	$	0.06	$	0.18	$	0.16	$	0.12
July		-		-	$	0.06	$	0.18	$	0.16	$	0.12
August		-		-	$	0.06	$	0.12	$	0.16	$	0.12
September		-		-	$	0.06	$	0.12	$	0.17	$	0.13
October		-		-		-	$	0.12	$	0.17	$	0.13
November		-		-		-	$	0.12	$	0.17	$	0.13
December		-		-		-	$	0.12	$	0.18	$	0.14	$0.10(1)

Note:

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

The distributions were denominated in U.S. dollars.   

CORPORATE GOVERNANCE

Delegation of Authority, Administration and Trust Governance

The board of directors of EEC has generally been delegated the significant management decisions. In particular, pursuant to the Trust Indenture, the Trustee has delegated to EEC responsibility for any and all matters relating to the following: (i) offering of the Trust’s securities; (ii) ensuring compliance with all applicable laws, including in relation to an offering of the Trust’s 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 the Trust’s material contracts; (v) all matters concerning any underwriting or agency agreement providing for the sale of Trust Units or rights to Trust Units; (vi) all matters relating to the redemption of Trust Units; and (vii) all matters relating to the voting rights on any investments held by us, other than the units of EECT.

In addition, pursuant to an administration agreement dated November 25, 2003 (the “Administration Agreement”); EEC has been appointed the Trust’s administrator and is responsible for the administration and management of all of the 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 of directors of EEC currently consists of six individuals.  The directors are elected by EEC at the direction of Unitholders by ordinary resolution, and hold office until the next annual meeting of Unitholders, which is currently scheduled for May 12, 2010.

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

Name and Municipality of Residence	Position with Enterra	Principal Occupation	Trust Units Controlled or Beneficially Owned (6)
Peter Carpenter (3) (5) Toronto, Ontario	Director (since 2006) and Chairman	Senior Partner & Director Claridge House Partners, Inc.	6,929
John Brussa Calgary, Alberta	Director (since May 2009)	Partner Burnet, Duckworth and Palmer	-
Roger Giovanetto (1) (2) (3) (4) Calgary, Alberta	Director (since 2006)	Business Consultant	30,747
Michael Doyle (1) (2) (4) (5) Calgary, Alberta	Director (since 2007)	Principal CanPetro International Ltd.	10,100
Victor Dusik (1) (2) (3) (4) (5) Vancouver, British Columbia	Director (since 2008)	Chief Financial Officer Run of River Power Inc.	5,630
Don Klapko Calgary, Alberta	President and Chief Executive Officer Director (since 2008)	President and Chief Executive Officer Enterra Energy Corp.	223,443
John F. Reader Calgary, Alberta	Senior Vice President Corporate Development (since 2005) and Chief Operating Officer	Sr. VP Corporate Development Enterra Energy Corp. and Chief Operating Officer Enterra Energy Corp.	72,021
Blaine Boerchers Calgary, Alberta	Senior Vice President  Finance and Chief Financial Officer (since 2007)	Sr. VP Finance and Chief Financial Officer Enterra Energy Corp.	87,360
John Chimahusky Oklahoma City, Oklahoma	Senior Vice President and Chief Operating Officer U.S. Operations (since December 2007)	Sr. VP and Chief Operating Officer US Operations	52,994
Shane Peet Canmore, Alberta	Senior Vice President, Engineering (Since January 2010)	Sr. VP Engineering Enterra Energy Corp.	12,914

Notes:

(1)      Member of Audit Committee

(2)      Member of Compensation Committee

(3)      Member of Reserves Committee

(4)      Member of Corporate Governance Committee

(5)      Member of the Health Safety Regulatory Compliance and Environmental Committee

(6)      As at March 25, 2010 and excluding Trust Units issuable upon the exercise of outstanding options, rights or deferred entitlement units

The directors and officers of EEC, as a group, beneficially owned, directly or indirectly, or exercised control or direction 502,138 of Trust Units, representing approximately 0.67% of the issued and outstanding Trust Units (as of March 25, 2010).  Profiles of EEC’s directors and officers and the particulars of their respective principal occupations during the last five years are set forth below.

Peter Carpenter, Director and Chairman

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

John Brussa, Director

John Brussa is a Senior partner of Burnet, Duckworth & Palmer LLP, a Calgary-based law firm, specializing in the area of taxation. Mr. Brussa attended the University of Windsor where he received his law degree in 1981. He has been with Burnet Duckworth & Palmer LLP since 1982 and his current practice includes structured finance, taxation of international energy operations, corporate and income trust restructuring and reorganization, dispute resolution and acquisitions and divestitures. He has lectured extensively to the Canadian Tax Foundation, the Canadian Petroleum Tax Society and Insight. Mr. Brussa is also a director of a number of energy and energy-related corporations and income funds. In addition, Mr. Brussa is a past Governor of the Canadian Tax Foundation and is a director or trustee of a number of charitable or non-profit organizations. Mr. Brussa joined the EEC board of directors in May 2009.

Roger Giovanetto, Director

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

Michael Doyle, Director

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

Victor Dusik, Director

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

Don Klapko, President and Chief Executive Officer

Don C. Klapko, President and Chief Executive Officer - Don Klapko has over 30 years of oil and gas industry experience with the last nine years directly involved at the executive management level, most recently as President and Director of Trigger Resources Ltd., a private exploration and production company, and prior to that at Rio Alto Exploration Ltd. as Vice President of Operations. Earlier, Mr. Klapko worked in various technical and supervisory positions in oil and gas facilities, mechanical and operations functions. Mr. Klapko holds a Mechanical Engineering Technology Diploma from Kelsey Institute in Saskatchewan. He was appointed President and CEO in June 2008.

John F. Reader, Senior VP Corporate Development and Chief Operating Officer

John Reader is a Professional Geological Engineer with over 30 years of resource industry experience.  Recently he culminated an 18-year career with Chevron 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 and appointed Chief Operating Officer in August 2009.  Mr. Reader holds a Bachelor of Applied Science degree from the University of British Columbia and a Master of Business Administration from the University of Calgary.

Blaine Boerchers, Senior Vice President and Chief Financial Officer

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

John Chimahusky, Senior VP and COO, U.S. Operations

John Chimahusky is a petroleum geologist with over 25 years of domestic and international oil and gas industry experience. Most recently, he was President of Kirkpatrick Oil Company, Inc., a private exploration and production company based in Oklahoma City which has assets primarily in the Mid-Continent and Permian Basin. Prior to that Mr. Chimahusky had a 25-year career with ConocoPhillips and its predecessor, Phillips Petroleum Company. He held various senior positions in Oklahoma, Texas and Norway, culminating as Exploration Manager, Former Soviet Union. He holds a Bachelor of Science degree in Environmental Geology from the University of Mississippi and a Masters degree in Geology from Memphis State University. Mr. Chimahusky joined Enterra in December 2007.

Shane Peet, Senior Vice President, Engineering

Shane Peet is a Professional Engineer with over 15 years of industry experience. Mr. Peet was acting as Manager of Acquisitions and Divestitures at Enterra Energy Trust. Previously, Mr. Peet was the Vice President of Engineering and COO of Wild River Resources from September 2007 to July 2009. Mr. Peet was the Vice President of Engineering of Prairie Schooner Energy Ltd. from August 2004 to September 2006 and the Engineering Manager of Great Northern Exploration from January 2002 through to its sale in June 2004. Prior thereto Mr. Peet held various positions with Bonavista, Rio Alto Exploration, Canadian Hunter, Talisman and Wascana Energy. Mr. Peet holds a Bachelor of Science degree in Petroleum Engineering from the University of Alberta.

Committees

The board of directors of EEC has constituted five committees for the purpose of discharging specific mandates in relation to the stewardship of EEC, including the administration and management of the Trust, being the Corporate Governance and Nominating Committee, the Audit Committee, the Compensation Committee, the Health Safety Regulatory Compliance and Environmental Committee and the Reserves Committee.  In addition, an independent committee (the “Special Committee”) was constituted for the purpose of addressing issues related to Macon Resources Ltd. and Petroflow and was disbanded after Don Klapko assumed the role of President and Chief Executive Officer. The Special Committee was dissolved June 2008.

Corporate Governance and Nominating Committee

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

-  -

Audit

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

Compensation

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

•   executive compensation policies, practices and overall compensation philosophy;

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

•   bonus, restricted units and trust unit options;

•   major changes in benefit plans; and

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

Reserves

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

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

•   consider and review the impact of changing independent engineering firms;

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

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

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

With the exception of the items listed in Appendix “D”, no director or executive officer of EEC is, as at the date hereof, or has been, within the 10 years prior to the date hereof, a director or executive officer of any company that, while that person was acting in that capacity,

(e)   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;

(f)   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

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

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

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

Legal Proceedings

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

Regulatory Actions

There are not any outstanding regulatory actions material to the Trust to which the Trust are is a party nor are there any such proceedings known to be contemplated.

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

In accordance with Business Corporations Act (Alberta), a director or officer who is a party to a material contract or proposed material contract with the Trust or the Trust Subsidiaries or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with the Trust or the Trust Subsidiaries shall disclose to EEC the nature and extent of the director’s or officer’s interest. In addition, a director shall not vote on any resolution to approve a contract of the nature described except in limited circumstances.

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

TRANSFER AGENT AND REGISTRAR

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

MATERIAL CONTRACTS

Agreements that may be considered material are set out below:

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

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

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

•   Farmout Agreement EAC and North American Petroleum Corporation USA dated January 13, 2006. See “Oil and Gas Properties – Oklahoma. The Farmout Agreement between EAC and North American Petroleum Corporation was cancelled on December 15, 2009.

•   Trust Indenture among the Trust, EEC and Olympia Trust Company providing for the issue of Debentures dated November 21, 2006 and the first supplemental indenture thereto dated April 27, 2007.  See “Trust Units and Other Securities – Description of Debentures”.

•   Second Amended and Restated Credit Agreement dated June 25, 2008 among EEC and the Bank of Nova Scotia and a syndicate of lenders including Bank of Nova Scotia.

INTERESTS OF EXPERTS

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

AUDIT COMMITTEE

General

EEC has established an Audit Committee (the “Audit Committee”) comprised of three members:  Victor Dusik, Roger Giovanetto and Michael Doyle, each of whom is considered “independent” and “financially literate” within the meaning of Multilateral Instrument 52-110 – Audit Committees.

Mandate of the Audit Committee

The mandate of the Audit Committee is to assist the board of EEC in its oversight of the integrity of the financial and related information, including the financial statements, internal controls and procedures for financial reporting and the processes for monitoring compliance with legal and regulatory requirements.  In doing so, the Audit Committee oversees the audit efforts of the external auditors and, in that regard, is empowered to take such actions as it may deem necessary to satisfy itself that the external auditors are independent of the Trust.

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

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

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

Relevant Education and Experience of Audit Committee Members

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

Name of Audit Committee Member	Relevant Education and Experience
Victor Dusik	Mr. Dusik is a Chartered Accountant, Chartered Business Valuator and Certified Corporate Director with extensive experience including the areas of corporate finance, acquisitions and divestitures, public reporting and compliance. He spent more than 30 years in various progressive positions with Ernst & Young LLP providing public accounting and consulting services to a wide variety of companies and industry sectors.
Michael Doyle	Mr. Doyle is a Professional Geophysicist and Certified Corporate Director with more than 35 years of experience.  He has served as a director of a number of companies principally in the petroleum sector, and has served on professional and technical committees, including Audit Committees.  Mr. Doyle holds a Bachelor of Science (Math and Physics) from the University of Victoria.
Roger Giovanetto	Mr. Giovanetto holds a B.Sc. in Metallurgical Engineering from the University of Alberta and is a member of APEGGA and other professional oil and gas organizations.  He has many years of business experience and has most recently been President of R&H Engineering Ltd. and has previously served on audit committees.

-  -

External Auditor Service Fees

KPMG LLP audited the annual financial statements for the 2009 and 2008 fiscal year.

(in $ thousands)	2009		2008
Audit fees (1)		456.9		530.1
Audit-related fees (2)		76.2		75.0
Tax fees (3)		-
All other fees (4)		55.8		10.2
Total		588.9		615.3

Notes:

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

(2) Audit-related fees are fees charged by KPMG LLP for reviews of the Trust’s interim financial statements and the Trust’s 20-F.

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

(4) All other fees related to advisory for International Financial Reporting Standards, SOX-404 compliance and document translation.

Audit Committee Oversight

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

ADDITIONAL INFORMATION

Additional information relating to the Trust may be found on SEDAR at www.sedar.com.  Additional information related to the remuneration and indebtedness of the directors and officers of EEC, the principal holders of Trust Units, the Trust Units authorized for issuance equity compensation plans and corporate governance disclosure, is contained in the management information circular in respect of the next annual meeting of Unitholders of the Trust.  Additional financial information is provided in the audited financial statements and management’s discussion and analysis of the Trust for the year ended December 31, 2009.

-  -

APPENDIX “A”

AUDIT COMMITTEE MANDATE

1.   Role and Objective

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

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

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

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

c.To monitor the independence and performance of the external auditors;

d.To provide better communication between directors and external auditors;

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

2.   Composition

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. )

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

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

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.

3.Meetings

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.

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.

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

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

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.

4.      Mandate and Responsibilities of the Committee

Review Procedures

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

1.   identifying, monitoring ,mitigating and reporting, material financial risks;

2.   ensuring compliance with legal, ethical and regulatory requirements;

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:

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

b)   reviewing significant accruals, reserves or other estimates;

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

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

e)   reviewing the adequacy of the asset retirement obligations;

f)   reviewing disclosure requirements for commitments and contingencies;

g)   obtaining reasonable explanations of significant variances with comparable reporting periods;

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

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

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

k)   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.

l)   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.

m)   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.

n)   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.

o)   The performance of the Committee shall be evaluated annually by the Board against criteria defined in the Committee and Board Mandates.

External Auditors

a.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.

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

c.To review and obtain a written statement from  the external auditor on a periodic basis a formal written statement detailing all relationships between the external auditors and Enterra.

Other

a.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.

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

c.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.

d.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.

e.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.

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

g.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.

4.Reporting Obligations and Authority

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.

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

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

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 March 25, 2010.

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APPENDIX “B-1”

FORM 51-101F2

REPORT ON RESERVES DATA BY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

1.   We have evaluated the Company’s Canadian reserves data as at December 31, 2009.  The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009 estimated using forecast prices and costs.

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

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

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

4.   The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2009, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Company’s management.

		Net Present Value of Future Net Revenue (before income taxes 10% discount rate )
Preparation Date of  Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited		Evaluated		Reviewed		Total
March 4, 2010	Canada		-		163,080		-		163,080

5.   In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6.   We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after preparation date.

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

Executed as to our report referred to above:

McDaniel & Associates Consultants Ltd., Calgary, Alberta, Canada, March 4, 2010

Signed “P. A. Welch”                             .

P. A. Welch, P. Eng

President & Managing Director

Calgary, Alberta

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APPENDIX “B-2”

FORM 51-101F2

REPORT ON RESERVES DATA BY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

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

1.   We have evaluated the Company’s U.S. Oklahoma reserves data as at December 31, 2009.  The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009 estimated using future prices and costs and proved reserves and related future revenue as at December 31, 2009, estimated using constant prices and costs.

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

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

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

4.   The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2009, and identifies the respective portion thereof that we have evaluated, audited and reviewed and reported on to the Company’s management.

Preparation Date of  Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes 10% discount rate  US$M)
		Audited	Evaluated	Reviewed	Total
March 9, 2010	U.S. Oklahoma	-	$272,998	-	$272,998

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

6.   We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

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

Executed as to our report referred to above:

Haas Petroleum Engineering Services, Inc., Dallas, Texas, U.S., March 12, 2010

Signed “Robert W. Haas”                             .

Robert W. Haas, P.Eng

President

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APPENDIX “C”

FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVE DATA AND OTHER INFORMATION

Management of Enterra Energy Corp. (the “Company”), is responsible for the preparation and disclosure of information with respect to the oil and gas activities of the Company in accordance with securities regulatory requirements.  This information includes reserves data which are (a) estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2009, estimated using forecast prices and costs and (b) proved reserves and related future net revenues as at December 31, 2009, estimated using constant prices and costs.

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

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

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

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

(c)   reviewed the reserves data with management and the independent qualified reserves evaluators.

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

(a)   the content and filing with securities regulatory authorities of Form 51-101F containing reserves data and other oil and gas information;

(b)   the filing of Form 51-101F2  which is the report of the independent qualified reserves evaluators on the reserves data; and

(c)   the content and filing of this report.

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

Signed “Don Klapko”

Don Klapko

Chief Executive Officer

Enterra Energy Corp.

Signed “Blaine Boerchers”

Blaine Boerchers

Chief Financial Officer

Enterra Energy Corp.

Signed “Roger Giovanetto ”

Roger Giovanetto

Director

Enterra Energy Corp.

March 25, 2010

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APPENDIX “D”

CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS

Roger Giovanetto

On March 20, 2000, Niaski Environmental Inc., which Mr. Giovanetto was then a director and insider of, made a proposal to its creditors under the Bankruptcy Act, which was approved by the creditors on April 13, 2000.  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, British Columbia and Saskatchewan Securities Commissions against Niaski Environmental Inc., which Mr.  Giovanetto was then a director and insider of, for failure to file financial statements.  The deficiencies were rectified and the cease trade orders lifted.

Michael Doyle

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

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