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.


-  -







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 equivalentAPI
            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 dayARTC
            Alberta
      Royalty Tax Credit
            
            Mmcf/d
            million
      cubic feet of natural gas per daybbl
      or bbls
            barrels
      of oil
            
            Mmcf
            million
      cubic feet of natural gasbbls
      per day or bbl/d
            barrels
      of oil per day
            
            mcf
      per day
            thousands
      of cubic feet of natural gas per dayBcf
            Billion
      cubic feet of natural gas
            
            mmbtu
            millions
      of British Thermal Unitsboe
            barrels
      of oil equivalent (6 mcf equivalent to 1 bbl)
            
            mmbtu
      per day
            millions
      of British Thermal Units per dayboe
      per day or boe/d
            barrels
      of oil equivalent per day
            
            Mwh
            Megawatt
      hoursCdn$
            Canadian
      dollars
            
            NGL
      or NGLs
            natural
      gas liquids (ethane, propane, butane and condensate)FD&A
            Finding
      Development & Acquisition Costs
            
            NI
      51-101
            National
      Instrument 51-101FDC
            Future
      Development Costs
            
            NYMEX
            New
      York Mercantile ExchangeGAAP
            Canadian
      Generally Accepted Accounting Principles
            
            Q1
            first
      quarter of the year - January 1 to March 31GJ
            Gigajoule
            
            Q2
            second
      quarter of the year - April 1 to June 30GJ/d
            gigajoule
      per day
            
            Q3
            third
      quarter of the year - July 1 to September 30GORR
            Gross
      overriding royalty
            
            Q4
            fourth
      quarter of the year - October 1 to December 31LNG
            Liquefied
      Natural Gas
            
            SEC
            Securities
      and Exchange Commissionm3
            cubic
      metres
            
            US$
            United
      States dollarsmbbl
            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.




-  -


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
      byMcf
            Cubic
      metres
            28.174Cubic
      metres
            Cubic
      feet
            35.494Bbls
            Cubic
      metres
            0.159Cubic
      metres
            Bbls
      oil
            6.290Feet
            Metres
            0.305Metres
            Feet
            3.281Miles
            Kilometres
            1.609Kilometres
            Miles
            0.621Acres
            Hectares
            0.4047Hectares
            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 312009
            2008
            2007Year
      End
            0.9514
            0.8210
            1.0087High
            0.7698
            0.7726
            1.0905Low
            0.9748
            1.0290
            0.8506Average
            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.




-  -




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.








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




-  -




GENERAL
DEVELOPMENTS OF 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.




-  -




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.




-  -


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
      ReservesReserves
      Category
            Light
      and Medium Crude Oil
            Heavy
      Oil
            Natural
      Gas Liquids
            Natural
      Gas
            TotalGross
              (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
            3.747.8Non-Producing
            -
            -
            -
            -
            39.0
            24.2
            5,277.0
            3,278.9
            918.5
            570.7Proved
      Undeveloped
            8.1
            7.7
            120.0
            76.4
            0.7
            0.6
            74.9
            64.8
            141.3
            95.5Proved
            1,686.7
            1,593.7
            691.7
            520.4
            117.6
            81.7
            19,551.1
            13,308.9
            5,754.5
            4,414.0Probable
            848.1
            755.2
            357.4
            254.4
            81.0
            59.4
            16,457.3
            11,228.3
            4,029.4
            2,940.4Total
      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
            7,354.3OKLAHOMA(2)Producing
            603.5
            487.2
            -
            -
            5,499.7
            4,400.9
            33,657.2
            26,883.1
            11,712.7
            9,368.6Non-Producing
            47.9
            38.4
            -
            -
            194.0
            154.4
            1,793.9
            1,428.8
            540.9
            430.9Proved
      Undeveloped
            4.7
            3.7
            -
            -
            1,774.8
            1,419.1
            14,503.4
            11,600.1
            4,196.8
            3,356.1Proved
            656.1
            529.2
            -
            -
            7,468.5
            5,974.5
            49,954.5
            39,912.0
            16,450.4
            13,155.7Probable
            26.0
            21.5
            -
            -
            2,126.0
            1,858.0
            16,072.1
            14,313.1
            4,830.7
            4,265.0Total
      Proved plus Probable
            682.1
            550.7
            -
            -
            9,594.5
            7,832.2
            66,026.6
            54,225.1
            21,281.0
            17,420.7AGGREGATEProducing
            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
            13,116.4Non-Producing
            47.9
            38.4
            -
            -
            233.0
            178.6
            7,070.9
            4,707.7
            1,459.4
            1,001.6Proved
      Undeveloped
            12.8
            11.4
            120.0
            76.4
            1,775.5
            1,419.7
            14,578.3
            11,664.9
            4,338.0
            3,451.6Proved
            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
            17,569.7Probable
            874.1
            776.7
            357.4
            254.4
            2,207.0
            1,917.4
            32,529.4
            25,541.4
            8,860.0
            7,205.4Total
      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
            20Reserves
      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
            83.6Non-Producing
            7.6
            6.5
            5.7
            5.1
            4.5
            7.6
            6.5
            5.7
            5.1
            4.5Proved
      Undeveloped
            2.6
            2.2
            2.0
            1.8
            1.6
            2.6
            2.2
            2.0
            1.8
            1.6Proved
            137.8
            120.5
            107.7
            97.7
            89.7
            137.8
            120.5
            107.7
            97.7
            89.7Probable
            99.2
            72.4
            55.4
            43.8
            35.4
            80.0
            59.4
            46.1
            36.9
            30.2Total
      Proved plus Probable
            237.0
            192.9
            163.1
            141.5
            125.1
            217.8
            179.9
            153.8
            134.6
            119.9OKLAHOMA(2)Producing
            340.0
            255.1
            203.0
            168.4
            144.0
            258.7
            194.2
            154.6
            128.4
            109.8Non-Producing
            12.2
            9.2
            7.2
            5.8
            4.7
            9.4
            7.1
            5.6
            4.5
            3.7Proved
      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
            105.0Probable
            139.4
            95.7
            69.2
            52.1
            40.5
            89.6
            62.3
            45.8
            35.1
            27.8Total
      Proved plus Probable
            542.5
            384.1
            286.9
            223.4
            179.5
            389.3
            277.8
            209.3
            164.1
            132.8AGGREGATEProducing
            467.7
            366.8
            302.9
            259.3
            227.6
            386.3
            305.9
            254.6
            219.2
            193.4Non-Producing
            19.8
            15.8
            12.9
            10.8
            9.3
            17.0
            13.7
            11.3
            9.6
            8.2Proved
      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
            194.7Probable
            238.6
            168.1
            124.6
            95.9
            75.9
            169.6
            121.7
            92.0
            72.1
            58.1Total
      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 TaxesReserves
      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
            -
            137.8Total
      Proved plus Probable
            577.4
            122.6
            185.0
            15.5
            17.3
            237.0
            19.2
            217.8OKLAHOMA(2)
      (3)Total
      Proved
            844.5
            208.9
            165.0
            63.3
            4.3
            403.1
            103.4
            299.7Total
      Proved Plus Probable
            1,107.6
            273.5
            201.4
            85.6
            4.4
            542.5
            153.2
            389.5AGGREGATETotal
      Proved
            1,183.4
            277.0
            279.6
            65.1
            20.8
            540.9
            103.4
            437.5Total
      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
            TotalUnit
      ValueReserves
      Category
            
            MM$
            MM$
            MM$
            $/bbl(3)
            
            (2)ProvedLight
      and Medium Crude Oil (1)
            
            47.8
            22.4
            70.1
            33.04Heavy
      Oil
            
            14.8
            -
            14.8
            28.39Natural
      Gas Liquids
            
            3.6
            98.6
            102.2
            16.87Natural
      Gas
            
            41.5
            96.8
            138.3
            2.60Total
            
            107.7
            217.7
            325.4Proved
      Plus ProbableLight
      and Medium Crude Oil (1)
            
            70.0
            23.2
            93.2
            32.13Heavy
      Oil
            
            22.0
            -
            22.0
            28.36Natural
      Gas Liquids
            
            5.9
            129.3
            135.1
            16.95Natural
      Gas
            
            65.3
            134.5
            199.8
            2.54Total
            
            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
            35.19Proved
      Non-Producing
            -
            -
            -
            -
            -
            -
            (3,592.0)
            n/aProved
      Undeveloped
            8.0
            8.0
            34.0
            32.0
            1.0
            1.0
            284.0
            37.13Total
      Proved
            1,684.0
            1,592.0
            1,015.0
            813.0
            26.0
            18.0
            52,443.0
            32.95Probable
            847.0
            754.0
            690.0
            562.0
            16.0
            12.0
            25,299.0
            33.53Total
      Proved & Probable
            2,531.0
            2,346.0
            1,705.0
            1,375.0
            42.0
            30.0
            77,742.0
            33.14Heavy
      OilProved
      Producing
            572.0
            444.0
            147.0
            125.0
            -
            -
            14,215.0
            32.01Proved
      Non-Producing
            -
            -
            -
            -
            -
            -
            (356.9)
            n/aProved
      Undeveloped
            120.0
            76.0
            41.0
            33.0
            -
            -
            1,704.0
            22.32Total
      Proved
            692.0
            520.0
            188.0
            158.0
            -
            -
            15,562.1
            29.90Probable
            357.0
            254.0
            99.0
            82.0
            -
            -
            7,586.0
            29.82Total
      Proved & Probable
            1,049.0
            774.0
            287.0
            240.0
            -
            -
            23,148.1
            29.88Natural
      Gas LiquidsProved
      Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Non-Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Undeveloped
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved
            -
            -
            -
            -
            -
            -
            -
            n/aProbable
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved & Probable
            -
            -
            -
            -
            -
            -
            -
            n/aNatural
      Gas (including By-products)Proved
      Producing
            3.0
            2.0
            13,070.0
            9,059.0
            53.0
            40.0
            29,989.0
            3.31Proved
      Non-Producing
            -
            -
            5,277.0
            3,279.0
            39.0
            24.0
            9,660.0
            2.95Proved
      Undeveloped
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved
            3.0
            2.0
            18,347.0
            12,338.0
            92.0
            64.0
            39.649.0
            3.21Probable
            1.0
            1.0
            15,668.0
            10,584.0
            65.0
            48.0
            22,541.0
            2.13Total
      Proved & Probable
            4.0
            3.0
            34,015.0
            22,922.0
            157.0
            112.0
            62,190.0
            2.71OKLAHOMA(2)
      (3)Light
      and Medium OilProved
      Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Non-Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Undeveloped
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved
            -
            -
            -
            -
            -
            -
            -
            n/aProbable
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved & Probable
            -
            -
            -
            -
            -
            -
            -
            n/aHeavy
      OilProved
      Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Non-Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Undeveloped
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved
            -
            -
            -
            -
            -
            -
            -
            n/aProbable
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      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 LiquidsProved
      Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Non-Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Undeveloped
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved
            -
            -
            -
            -
            -
            -
            -
            n/aProbable
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved & Probable
            -
            -
            -
            -
            -
            -
            -
            n/aNatural
      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
            7.55Proved
      Non-Producing
            47.9
            38.4
            1,793.9
            1,428.8
            194.0
            154.4
            7,213.0
            5.05Proved
      Undeveloped
            4.7
            3.7
            14,503.4
            11,600.1
            1,774.8
            1,419.1
            7,539.2
            0.65Total
      Proved
            656.1
            529.2
            49,954.5
            39,912.0
            7,468.5
            5,974.5
            217,722.4
            5.46Probable
            26.0
            21.5
            16,072.1
            14,313.1
            2,126.0
            1,858.0
            69,221.1
            4.84Total
      Proved & Probable
            682.1
            550.7
            66,026.6
            54,225.1
            9,594.5
            7,832.5
            286,943.4
            5.29AGGREGATELight
      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
            35.20Proved
      Non-Producing
            -
            -
            -
            -
            -
            -
            (3,592.0)
            n/aProved
      Undeveloped
            8.0
            8.0
            34.0
            32.0
            1.0
            1.0
            284
            35.50Total
      Proved
            1,684.0
            1,592.0
            1,015.0
            813.0
            26.0
            18.0
            52,443.0
            32.94Probable
            847.0
            754.0
            690.0
            562.0
            16.0
            12.0
            25,299.0
            33.55Total
      Proved & Probable
            2,531.0
            2,346.0
            1,705.0
            1,375.0
            42.0
            30.0
            77,742.0
            33.14Heavy
      OilProved
      Producing
            572.0
            444.0
            147.0
            125.0
            -
            -
            14,215.0
            32.01Proved
      Non-Producing
            -
            -
            -
            -
            -
            -
            (356.9)
            n/aProved
      Undeveloped
            120.0
            76.0
            41.0
            33.0
            -
            -
            1,704.0
            22.32Total
      Proved
            692.0
            520.0
            188.0
            158.0
            -
            -
            15,562.1
            29.90Probable
            357.0
            254.0
            99.0
            82.0
            -
            -
            7,586.0
            29.82Total
      Proved & Probable
            1,049.0
            774.0
            287.0
            240.0
            -
            -
            23,148.1
            29.88Natural
      Gas LiquidsProved
      Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Non-Producing
            -
            -
            -
            -
            -
            -
            -
            n/aProved
      Undeveloped
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved
            -
            -
            -
            -
            -
            -
            -
            n/aProbable
            -
            -
            -
            -
            -
            -
            -
            n/aTotal
      Proved & Probable
            -
            -
            -
            -
            -
            -
            -
            n/aNatural
      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
            6.48Proved
      Non-Producing
            47.9
            38.4
            7,070.9
            4,707.8
            233.0
            178.4
            16,873.0
            3.58Proved
      Undeveloped
            4.7
            3.7
            14,503.4
            11,600.1
            1,774.8
            1,419.1
            7,539.2
            0.65Total
      Proved
            659.1
            531.2
            68,301.5
            52,250.0
            7,560.5
            6,038.5
            257.371.4
            4.93Probable
            27.0
            22.5
            31,740.1
            24,897.1
            2,191.0
            1,906.0
            91,762.1
            3.69Total
      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
            0.8802010
            80.00
            83.20
            72.30
            68.10
            76.50
            60.30
            6.05
            5.85
            5.85
            2.0
            0.9502011
            83.60
            87.00
            73.80
            67.60
            79.10
            63.50
            6.90
            6.55
            6.55
            2.0
            0.9502012
            87.40
            91.00
            74.40
            68.00
            81.80
            66.50
            7.30
            6.95
            6.95
            2.0
            0.9502013
            91.30
            95.00
            75.80
            68.10
            85.40
            69.40
            7.70
            7.25
            7.25
            2.0
            0.9502014
            95.30
            99.20
            79.20
            71.10
            89.20
            72.50
            8.15
            7.60
            7.60
            2.0
            0.9502015
            99.40
            103.5
            82.60
            74.20
            93.10
            75.60
            8.50
            7.95
            7.95
            2.0
            0.9502016
            101.40
            105.60
            84.30
            75.70
            94.90
            77.20
            8.75
            8.15
            8.15
            2.0
            0.9502017
            103.40
            107.70
            85.90
            77.20
            96.80
            78.70
            8.90
            8.30
            8.30
            2.0
            0.9502018
            105.40
            109.80
            87.60
            78.70
            98.70
            80.30
            9.10
            8.45
            8.45
            2.0
            0.9502019
            107.60
            112.10
            89.40
            80.40
            100.70
            82.00
            9.30
            8.65
            8.65
            2.0
            0.9502020
            109.70
            114.30
            91.20
            81.90
            102.70
            83.60
            9.45
            8.80
            8.80
            2.0
            0.9502021
            111.90
            116.50
            93.00
            83.60
            104.80
            85.20
            9.65
            9.00
            9.00
            2.0
            0.9502022
            114.10
            118.80
            94.80
            85.20
            106.80
            86.90
            9.85
            9.20
            9.20
            2.0
            0.9502023
            116.40
            121.20
            96.70
            86.90
            109.00
            88.70
            10.05
            9.40
            9.40
            2.0
            0.9502024
            118.80
            123.70
            98.70
            88.70
            111.20
            90.50
            10.25
            9.60
            9.60
            2.0
            0.950Thereafter
            +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
            TotalReserves
      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
            3,560.7Non-Producing
            -
            -
            -
            -
            31.7
            20.8
            3,574.3
            2,688.3
            627.4
            468.9Proved
      Undeveloped
            8.1
            7.7
            120.0
            78.1
            0.7
            0.6
            74.9
            64.9
            141.3
            97.2Total
      Proved
            1,645.2
            1,621.8
            687.2
            523.7
            93.6
            66.0
            15,632.7
            11,491.3
            5,031.5
            4,126.7Probable
            834.2
            795.8
            356.8
            258.9
            36.5
            26.7
            8,050.0
            5,805.1
            2,569.2
            2,048.9Total
      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
            6,175.6OKLAHOMA(2)Producing
            583.5
            471.1
            -
            -
            5,272.5
            4,219.4
            31,625.3
            25,261.2
            11,126.9
            8,900.7Non-Producing
            46.0
            36.8
            -
            -
            153.4
            122.2
            1,334.7
            1,063.6
            421.8
            336.3Proved
      Undeveloped
            4.7
            3.7
            -
            -
            1,650.9
            1,319.9
            13,471.3
            10,774.4
            3,900.8
            3,119.4Total
      Proved
            634.2
            511.7
            
            -
            7,076.8
            5,661.5
            46,431.3
            37,099.2
            15,449.5
            12,356.3Probable
            28.8
            23.7
            -
            -
            2,021.2
            1,770.3
            15,042.7
            13,442.7
            4,557.2
            4,034.4Total
      Proved plus Probable
            663.0
            535.4
            -
            -
            9,098.0
            7,431.7
            61,474.0
            50,541.8
            20,006.6
            16,390.8AGGREGATEProducing
            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
            12,461.4Non-Producing
            46.0
            36.8
            -
            -
            185.1
            143.0
            4,909.0
            3,751.9
            1,049.2
            805.1Proved
      Undeveloped
            12.8
            11.4
            120.0
            78.1
            1,651.6
            1,320.5
            13,546.2
            10,839.3
            4,042.1
            3,216.6Total
      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
            16,483.1Probable
            863.0
            819.5
            356.8
            258.9
            2,057.7
            1,797.0
            23,092.7
            19,247.8
            7.126.3
            6,083.3Total
      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
            20MM$
            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
            50.2Non-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
            1.0Total
      Proved
            70.0
            62.8
            57.3
            53.0
            49.4
            70.0
            62.8
            57.3
            53.0
            49.4Probable
            45.2
            34.8
            28.0
            23.2
            19.7
            45.2
            34.8
            28.0
            23.2
            19.7Total
      Proved plus Probable
            115.2
            97.6
            85.3
            76.2
            69.0
            115.2
            97.6
            85.3
            76.2
            69.0OKLAHOMA(2)
      (3)Producing
            165.4
            132.8
            110.0
            95.5
            84.0
            153.1
            119.8
            98.1
            83.0
            72.1Non-Producing
            4.5
            3.4
            2.7
            2.2
            1.8
            4.7
            3.6
            2.9
            2.3
            1.9Proved
      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
            53.4Probable
            51.8
            35.9
            25.8
            19.0
            14.4
            36.7
            25.7
            18.8
            14.2
            11.1Total
      Proved plus Probable
            206.6
            150.6
            114.0
            89.2
            71.6
            186.3
            135.3
            102.6
            80.3
            64.5AGGREGATEProducing
            237.1
            197.0
            169.4
            149.4
            134.2
            224.8
            184.0
            156.6
            137.0
            122.3Non-Producing
            1.0
            0.5
            0.2
            0.1
            (0.1)
            1.2
            0.7
            0.4
            0.2
            0.1Proved
      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
            102.8Probable
            97.1
            70.8
            753.8
            42.3
            34.0
            81.9
            60.5
            46.8
            37.5
            30.8Total
      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 TaxesReserves
      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
            -
            70.0Total
      Proved plus Probable
            311.0
            48.9
            128.3
            4.1
            14.5
            115.2
            -
            115.2OKLAHOMA(2)
      (3)Total
      Proved
            439.0
            107.6
            112.2
            60.2
            4.3
            154.8
            5.2
            149.6Total
      Proved plus Probable
            568.5
            139.1
            136.7
            81.5
            4.6
            206.6
            20.3
            186.3AGGREGATETotal
      Proved
            645.9
            138.9
            201.7
            61.9
            18.6
            224.8
            5.2
            219.6Total
      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
            TotalUnit
      ValueReserves
      Category
            
            MM$
            MM$
            MM$
            $/bbl
      or $/mcf(3)
            
            (2)ProvedLight
      and Medium Crude Oil(1)
            
            32.0
            13.8
            45.7
            21.43Heavy
      Oil
            
            10.6
            -
            10.6
            20.27Natural
      Gas Liquids
            
            2.1
            45.2
            47.3
            8.25Natural
      Gas
            
            12.7
            29.3
            42.0
            0.86Total
            
            57.3
            88.3
            145.6Proved
      Plus ProbableLight
      and Medium Crude Oil (1)
            
            47.3
            14.1
            61.4
            20.81Heavy
      Oil
            
            16.0
            -
            16.0
            20.49Natural
      Gas Liquids
            
            2.8
            58.6
            61.4
            8.16Natural
      Gas
            
            19.2
            41.3
            60.5
            0.89Total
            
            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 LiquidsTotal
      Proved
            Probable
            Total
      Proved
            Total
      Proved
            Probable
            Total
      ProvedReserves
            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
            168.6Extensions
      and Improved Recovery
            -
            -
            -
            5.1
            -
            5.1Technical
      Revisions
            338.2
            (143.4)
            194.8
            34.3
            20.3
            54.6Acquisitions
            -
            -
            -
            -
            -
            -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
            199.0UNITED
      STATES (2)Opening
      balance – December 31, 2008
            1,157.5
            165.1
            1,322.6
            4,790.1
            795.9
            5,586.0Extensions
      and Improved Recovery
            3.9
            1.1
            5.0
            40.6
            11.9
            52.5Technical
      Revisions
            (388.7)
            (142.0)
            (530.8)
            3,068.7
            1,301.0
            4,369.7Acquisitions
            34.4
            1.8
            36.2
            326.7
            17.2
            343.9Dispositions
            -
            -
            -
            -
            -
            -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
            9,594.5AGGREGATEOpening
      balance – December 31, 2008
            3,089.1
            1,156.5
            4,245.6
            4,898.0
            856.6
            5,754.6Extensions
      and Improved Recovery
            3.9
            1.1
            5.0
            45.7
            11.9
            57.6Technical
      Revisions
            (50.5)
            (285.4)
            (336.0)
            3,103.0
            1,321.3
            4,424.3Acquisitions
            34.4
            1.8
            36.2
            326.7
            17.2
            343.9Dispositions
            -
            -
            -
            -
            -
            -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
      OilTotal
      Proved
            Probable
            Total
      Proved
            Total
      Proved
            Probable
            Total
      ProvedReserves
            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
            1,494.6Extensions
      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
            1,049.0UNITED
      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
            -
            -
            -AGGREGATEOpening
      balance – December 31, 2008
            63,123
            28,100
            91,223
            976.4
            518.2
            1,494.6Extensions
      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
            TotalM$
            M$
            M$(1)
      (2)Constant Prices and Costs –
      Proved Reserves(1)2010
            1,484
            17,500
            18,9842011
            -
            27,840
            27,8402012
            -
            16,074
            16,0742013
            -
            260
            2602014
            -
            31
            31Remaining
      Years
            200
            -
            200Total
      Undiscounted
            1,684
            61,880
            63,389Total
      Discounted at 10% per Year
            1,608
            56,381
            58,042Forecast Prices and Costs –
      Proved Reserves(2)2010
            1,555
            17,623
            19,1782011
            -
            28,624
            28,6242012
            -
            16,810
            16,8102013
            -
            245
            2452014
            -
            -
            -Remaining
      Years
            225
            -
            225Total
      Undiscounted
            1,780
            63,303
            65,308Total
      Discounted at 10% per Year
            1,754
            57,722
            59,476Forecast Prices and Costs –
      Proved Plus Probable Reserves(2)2010
            15,139
            19,572
            34,7112011
            104
            40,161
            40,2652012
            -
            25,423
            25,4232013
            -
            387
            3872014
            -
            -
            -Remaining
      Years
            225
            33
            258Total
      Undiscounted
            15,468
            85,610
            101,303Total
      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-ProducingOil
            Gas
            Oil
            Gas
            Grand
      TotalState/Province
            Gross
            Net
            Gross
            Net
            Gross
            Net
            Gross
            Net
            Gross
            NetAlberta
            242
            154.8
            20
            12.7
            318
            229.3
            80
            57.7
            660
            454.5British
      Columbia
            -
            -
            23
            23.0
            -
            -
            17
            17.0
            40
            40.0Saskatchewan
            14
            14.0
            13
            13.0
            4
            4.0
            16
            16.0
            47
            47.0Total
            256
            168.8
            56
            48.7
            322
            233.3
            113
            90.7
            747
            541.5Oklahoma
            -
            -
            154
            95.8
            -
            -
            53
            36.9
            207
            132.7Grand
      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
      AcresCanada
            307,756
            153,056United
      States
            137,473
            77,369Total
            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 AbandonmentArea
            Undiscounted
            Discounted
      at 10%Canada
            4.3
            3.7United
      States
            0.3
            0.3Total
            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
            
            
            TotalProperty
      acquisition costs(1)Proved
            
            
            -
            
            
            
            9.0
            
            
            
            9.0Unproved
            
            
            3.2
            
            
            
            5.2
            
            
            
            8.4Exploration
      costs
            
            
            0.4
            
            
            
            -
            
            
            
            0.4Development
      costs
            
            
            5.5
            
            
            
            1.6
            
            
            
            7.1Total
      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
      WellsCanada
            United
      States
            Canada
            United
      StatesGross
            Net
            Gross
            Net
            Gross
            Net
            Gross
            Net
            Gross
            NetLight
      and Medium Oil
            -
            -
            -
            -
            -
            -
            -
            -
            -
            -Natural
      Gas
            -
            -
            -
            -
            1.0
            1.0
            3.0
            0.7
            4.0
            1.5Service
            -
            -
            -
            -
            -
            -
            1.0
            1.0
            1.0
            1.0Dry
            1.0
            0.8
            -
            -
            
            
            -
            -
            1.0
            1.0Total
            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
            179,118Provost
            296,197
            42,517
            12,034
            353,138
            409,604Brooks
            114,101
            -
            3,722
            224,434
            155,229Desan
            2,469
            -
            4,980
            1,133,543
            196,372Saskatchewan
            9,024
            237,664
            -
            1,811,330
            548,576Ricinus
            13
            -
            816
            516,107
            86,846Other
      Canadian
            33,718
            -
            216
            10,644
            35,710Oklahoma
            150,992
            -
            757,558
            6,512,333
            1,993,938734,206
            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
            
            
            
            
            
            NaturalMedium
            
            
            
            
            
            Gas
            
            
            NaturalCrude
      Oil
            
            
            Heavy
      Oil
            
            
            Liquids
            
            
            Gas
            
            
            TotalGross
            
            
            Gross
            
            
            Gross
            
            
            Gross
            
            
            GrossReserve
      Category
            
            [mbbl]
            
            
            [mbbl]
            
            
            [mbbl]
            
            
            [mmcf]
            
            
            [mBOE]CANADA
      (McDaniel Report)ProvedProducing
            
            
            541.8
            
            
            
            184.5
            
            
            
            24.2
            
            
            
            3,679.9
            
            
            
            1,363.8Non-Producing
            
            
            -
            
            
            
            -
            
            
            
            1.9
            
            
            
            523.7
            
            
            
            89.2Undeveloped
            
            
            17.6
            
            
            
            1.2
            
            
            
            0.1
            
            
            
            12.1
            
            
            
            20.9Total
      Proved
            
            
            559.4
            
            
            
            185.7
            
            
            
            26.2
            
            
            
            4,215.7
            
            
            
            1,473.9Probable
            
            
            51.1
            
            
            
            17.2
            
            
            
            3.7
            
            
            
            471.0
            
            
            
            150.5Total
      Proved plus Probable
            
            
            610.5
            
            
            
            202.9
            
            
            
            29.9
            
            
            
            4,686.7
            
            
            
            1,624.4OKLAHOMA
      (Haas Report)ProvedProducing
            
            
            102.0
            
            
            
            -
            
            
            
            775.3
            
            
            
            4,907.6
            
            
            
            1,695.2Non-Producing
            
            
            0.9
            
            
            
            -
            
            
            
            6.5
            
            
            
            68.9
            
            
            
            18.9Undeveloped
            
            
            0.1
            
            
            
            -
            
            
            
            2.7
            
            
            
            18.3
            
            
            
            5.9Total
      Proved
            
            
            103.0
            
            
            
            -
            
            
            
            784.5
            
            
            
            4,994.8
            
            
            
            1,720.0Probable
            
            
            1.5
            
            
            
            -
            
            
            
            64.6
            
            
            
            371.5
            
            
            
            128.1Total
      Proved plus Probable
            
            
            104.5
            
            
            
            -
            
            
            
            849.2
            
            
            
            5,366.4
            
            
            
            1,848.1AGGREGATEProvedProducing
            
            
            643.8
            
            
            
            184.5
            
            
            
            799.5
            
            
            
            8,587.5
            
            
            
            3,059.0Non-Producing
            
            
            0.9
            
            
            
            -
            
            
            
            8.4
            
            
            
            592.6
            
            
            
            108.1Undeveloped
            
            
            17.7
            
            
            
            1.2
            
            
            
            2.8
            
            
            
            30.4
            
            
            
            26.8Total
      Proved
            
            
            662.3
            
            
            
            185.7
            
            
            
            810.7
            
            
            
            9,210.5
            
            
            
            3,193.9Probable
            
            
            52.6
            
            
            
            17.2
            
            
            
            68.3
            
            
            
            842.5
            
            
            
            278.6Total
      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 2009March
      31
            June
      30
            September
      30
            December
      31Average
      Daily ProductionOil
      (bbl/d)
            
            3,126
            2,786
            2,682
            2,530NGL
      (bbl/d)
            
            1,058
            2,039
            2,729
            2,749Natural
      Gas (Mcf/d)
            
            34,557
            31,407
            26,977
            25,815Combined
      (BOE/d)
            
            9,968
            10,059
            9,907
            9,582Average
      Prices ReceivedOil
      ($/bbl)
            
            54.99
            63.48
            63.68
            69.81NGL
      (bbl/d)
            
            31.12
            28.63
            25.67
            41.63Natural
      Gas ($/Mcf)
            
            4.78
            3.43
            3.30
            4.01NetbackRevenues
      – combined ($/boe)(1)
            
            46.69
            34.09
            33.30
            42.04Royalties
      – combined ($/boe)
            
            7.25
            5.92
            6.69
            9.70Operating
      Expenses – combined ($/boe)
            
            12.61
            12.19
            8.56
            10.25Transportation
      Expenses – combined ($/boe)
            
            0.54
            0.78
            0.77
            0.59Operating
      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 theSecurities
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 ExchangeHigh
      ($)
            
            
            Low
      ($)
            
            
            Volume
      (000’s)
            
            
            High
      (US$)
            
            
            Low
      (US$)
            
            
            Volume2009January
            
            
            0.91
            
            
            
            0.57
            
            
            
            533,300
            
            
            
            0.77
            
            
            
            0.44
            
            
            
            3,270,100February
            
            
            0.73
            
            
            
            0.53
            
            
            
            576,800
            
            
            
            0.65
            
            
            
            0.43
            
            
            
            1,973,500March
            
            
            0.92
            
            
            
            0.55
            
            
            
            914,600
            
            
            
            0.71
            
            
            
            0.43
            
            
            
            2,945,700April
            
            
            1.56
            
            
            
            0.74
            
            
            
            2,612,100
            
            
            
            1.35
            
            
            
            0.59
            
            
            
            6,452.500May
            
            
            1.68
            
            
            
            1.20
            
            
            
            1,258,900
            
            
            
            1.53
            
            
            
            1.20
            
            
            
            6,458,900June
            
            
            1.96
            
            
            
            1.44
            
            
            
            1,120,300
            
            
            
            1.79
            
            
            
            1.58
            
            
            
            6,811,000July
            
            
            1.25
            
            
            
            1.19
            
            
            
            472,600
            
            
            
            1.35
            
            
            
            1.00
            
            
            
            3,583,900August
            
            
            1.50
            
            
            
            1.25
            
            
            
            284,600
            
            
            
            1.39
            
            
            
            1.14
            
            
            
            3,577,900September
            
            
            1.43
            
            
            
            1.21
            
            
            
            620,300
            
            
            
            1.35
            
            
            
            1.09
            
            
            
            4,123,100October
            
            
            1.91
            
            
            
            1.22
            
            
            
            939,900
            
            
            
            1.84
            
            
            
            1.14
            
            
            
            7,538,100November
            
            
            1.69
            
            
            
            1.50
            
            
            
            417,800
            
            
            
            1.71
            
            
            
            1.28
            
            
            
            3,912,100December
            
            
            2.25
            
            
            
            1.50
            
            
            
            1,365,900
            
            
            
            2.16
            
            
            
            1.48
            
            
            
            9,596,6002010January
            
            
            2.88
            
            
            
            1.84
            
            
            
            5,536,700
            
            
            
            2.42
            
            
            
            1.72
            
            
            
            7,984,500February
            
            
            3.04
            
            
            
            1.92
            
            
            
            2,312,900
            
            
            
            2.94
            
            
            
            1.79
            
            
            
            9,563,100March(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
      ($)
            
            
            Volume2009January
            
            
            66.00
            
            
            
            55.00
            
            
            
            3,550
            
            
            
            70.00
            
            
            
            55.00
            
            
            
            1,520February
            
            
            65.01
            
            
            
            55.00
            
            
            
            10,300
            
            
            
            65.00
            
            
            
            58.00
            
            
            
            1,100March
            
            
            68.25
            
            
            
            50.00
            
            
            
            2,210
            
            
            
            62.50
            
            
            
            59.00
            
            
            
            730April
            
            
            69.00
            
            
            
            62.90
            
            
            
            9,420
            
            
            
            69.00
            
            
            
            59.00
            
            
            
            10,900May
            
            
            75.00
            
            
            
            65.00
            
            
            
            1,470
            
            
            
            78.00
            
            
            
            66.50
            
            
            
            10,770June
            
            
            79.00
            
            
            
            61.00
            
            
            
            10,750
            
            
            
            82.00
            
            
            
            73.50
            
            
            
            4,640July
            
            
            87.86
            
            
            
            74.55
            
            
            
            4,890
            
            
            
            85.00
            
            
            
            80.00
            
            
            
            16,940August
            
            
            86.00
            
            
            
            81.00
            
            
            
            20,770
            
            
            
            83.50
            
            
            
            78.00
            
            
            
            16,280September
            
            
            81.30
            
            
            
            84.00
            
            
            
            2,510
            
            
            
            83.50
            
            
            
            82.00
            
            
            
            1,830October
            
            
            84.00
            
            
            
            93.00
            
            
            
            24,270
            
            
            
            95.00
            
            
            
            83.25
            
            
            
            20,710November
            
            
            95.00
            
            
            
            91.01
            
            
            
            14,040
            
            
            
            96.00
            
            
            
            90.51
            
            
            
            9,280December
            
            
            96.25
            
            
            
            92.60
            
            
            
            14,770
            
            
            
            96.00
            
            
            
            95.25
            
            
            
            12,6702010January
            
            
            100.49
            
            
            
            95.02
            
            
            
            18,730
            
            
            
            99.75
            
            
            
            95.79
            
            
            
            25,550February
            
            
            100.00
            
            
            
            98.00
            
            
            
            24,240
            
            
            
            100.49
            
            
            
            98.00
            
            
            
            20,300March(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
            
            2003January
            
            
            -
            
            
            
            -
            
            
            $
            0.12
            
            
            $
            0.18
            
            
            $
            0.14
            
            
            $
            0.10February
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.18
            
            
            $
            0.14
            
            
            $
            0.10March
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.18
            
            
            $
            0.15
            
            
            $
            0.11April
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.18
            
            
            $
            0.15
            
            
            $
            0.11May
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.18
            
            
            $
            0.15
            
            
            $
            0.11June
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.18
            
            
            $
            0.16
            
            
            $
            0.12July
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.18
            
            
            $
            0.16
            
            
            $
            0.12August
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.12
            
            
            $
            0.16
            
            
            $
            0.12September
            
            
            -
            
            
            
            -
            
            
            $
            0.06
            
            
            $
            0.12
            
            
            $
            0.17
            
            
            $
            0.13October
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            $
            0.12
            
            
            $
            0.17
            
            
            $
            0.13November
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            $
            0.12
            
            
            $
            0.17
            
            
            $
            0.13December
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            $
            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.
            6,929John
      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
            30,747Michael
      Doyle (1) (2)
      (4) (5)
              Calgary,
      Alberta
            Director
      (since 2007)
            Principal
              CanPetro
      International Ltd.
            10,100Victor
      Dusik (1) (2)
      (3) (4) (5)
              Vancouver,
      British Columbia
            Director
      (since 2008)
            Chief
      Financial Officer
              Run
      of River Power Inc.
            5,630Don
      Klapko
              Calgary,
      Alberta
            President
      and Chief Executive Officer
              Director
      (since 2008)
            President
      and Chief Executive Officer
              Enterra
      Energy Corp.
            223,443John
      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.
            72,021Blaine
      Boerchers
              Calgary,
      Alberta
            Senior
      Vice President  Finance and Chief Financial Officer (since
      2007)
            Sr.
      VP Finance and Chief Financial Officer
              Enterra
      Energy Corp.
            87,360John
      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
            52,994Shane
      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 ExperienceVictor
      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
            
            
            2008Audit
      fees (1)
            
            
            456.9
            
            
            
            530.1Audit-related
      fees (2)
            
            
            76.2
            
            
            
            75.0Tax
      fees (3)
            
            
            -All
      other fees (4)
            
            
            55.8
            
            
            
            10.2Total
            
            
            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.




-  -


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
            
            
            TotalMarch
      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, March4, 2010









Signed “P. A.
Welch”                             .


P. A.
Welch, P. Eng


President
& Managing Director


Calgary,
Alberta


-  -


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
            TotalMarch
      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




-  -


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









-  -


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.









-  -