UNITED
STATES




SECURITIES AND EXCHANGE
COMMISSION




Washington,
D.C.  20549







FORM
20-F




(Mark
One)





            
            REGISTRATION
      STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE
      ACT OF 1934.




OR




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


For
the fiscal year ended December 31, 2008.




OR





            
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
      OF 1934.




OR





            
            SHELL
      COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934.


Date of
event requiring this shell company report ...................




For the transition period from
____________________ to _____________________




Commission
file number 000-32115




ENTERRA ENERGY
TRUST




(Exact
Name of Registrant as Specified in Its Charter)




Alberta,
Canada




(Jurisdiction of Incorporation or
Organization)




Suite 2700,
500 – 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6


(Address
of Principal Executive Offices)





Blaine
Boerchers, Suite 2700, 500 – 4th Avenue S.W., Calgary, Alberta, Canada, T2P
2V6,


Tel:
(403) 538-3580, Fax: (403) 294-1197


(Name,
Telephone, E-mail and/or Facsimile number and Address of Company Contact
Person)




Securities
registered or to be registered pursuant to Section 12(b) of the
Act:




Title of Each
      Class
            
            Name
      of Each Exchange On Which RegisteredTrust
      Units
            
            New
      York Stock Exchange




Securities
registered or to be registered pursuant to Section 12(g) of the
Act:.






Trust
Units




(Title of Class)





Enterra Energy Trust Form 20 –
F







Securities
for which there is a reporting obligation pursuant to Section 15(d) of the
Act:






None




(Title of Class)




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






Trust Units, without par value at
December 31, 2008: 62,158,987






Indicate
by check mark whether if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Exchange Act of 1934.


Yes  No
R




If this
report is an annual or transition report, indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934.


Yes  No
R




Note –
Checking the box above will not relieve any registrant required to file reports
pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from
their obligations under those Sections.




Indicate
by check mark whether if the registrant: (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.


Yes
R No





Indicate
by check mark whether if the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer.  See definition of
“accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange
Act.  (Check one):




Large
accelerated filer
                                                      Accelerated
filer
                                                      Non-Accelerated
filer R




Indicate
by check mark which basis of accounting the registrant has used to prepare the
financial statements included in this filing:




U.S. GAAP
                                International
Financial Reporting Standards as
issued                                                                                                Other  R


by the International Accounting
Standards
Board         




If
“Other” has been checked in response to the previous question, indicate by check
mark which financial statement item the registrant has elected to
follow.


 Item
17                      R Item
18




If this
is an annual report, indicate by check mark whether the registrant is a shell
company (as defined in Rule 12b-2 of the Exchange Act.


Yes  No
R




(APPLICABLE
ONLY TO ISSUER INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE
YEARS)




Indicate
by check mark whether the registrant has filed all documents and reports
required to be filed by sections 12, 13 or 15(d) of the Securities Exchange Act
of 1934 subsequent to the distribution of securities under a plan confirmed by a
court


Yes  No
R








Enterra Energy Trust Form 20 –
F





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 Enterra’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 Enterra’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 Enterra’s website
(www.enterraenergy.com).  Furthermore, the forward-looking statements
contained herein are made as at the date hereof and Enterra 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.





Enterra Energy Trust Form 20 –
F





Glossary





The following are defined terms used in this form
20-F:





“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 5, 2009 and
effective January 1, 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;





“US
Farmout Partner” means Petroflow Energy Ltd.;





Enterra Energy Trust Form 20 –
F





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





“McDaniel
Report” means the independent engineering evaluation of certain oil, NGL and
natural gas interests of the Trust prepared by McDaniel dated February 17,
2009 and effective December 31, 2008;





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





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





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





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





“Revolving
and Operating Credit Facilities” means


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


(ii) ans operating facility
with Bank of Nova Scotia as lender,


provided
pursuant to the second amended and restated syndicated credit agreement dated
June 25, 2008;





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





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





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





“Second-Lien
Credit Facility” means a second-lien non-revolving credit facility with a
syndicate of lenders provided pursuant to a credit agreement dated June 25,
2008;





“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;





Enterra Energy Trust Form 20 –
F





“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
            
            US$
            United
      States dollarsm3
            cubic
      metres
            
            WTI
            West
      Texas Intermediate, the reference price paid in U.S. dollars at Cushing,
      Oklahoma for crude oil of standard gradembbl
            thousand
      barrels of oil





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 20-F is stated as at December 31, 2008 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





Enterra Energy Trust Form 20 –
F







PART
1






ITEM
1 - IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS




Not
applicable.




ITEM
2 - OFFER STATISTICS AND EXPECTED TIMETABLE




Not
applicable.




ITEM
3 - KEY INFORMATION






A.  Selected
Financial Data




The
financial data set forth below as at December 31, 2008, 2007, 2006, 2005, and
2004 and for each of the years in the five year period ended December 31, 2008
have been derived from our audited consolidated financial statements and should
be read in conjunction with those financial statements.  The financial
data has been prepared in accordance with Canadian Generally Accepted Accounting
Principles (GAAP), the application of which, in the case of Enterra Energy
Trust, conforms in all material respects for the periods presented with US GAAP,
except as disclosed in footnotes to the financial statements.





The
following table presents a summary of our consolidated statement of operations
derived from our financial statements for the years ended December 31, 2008,
2007, 2006, 2005 and 2004.  The monetary amounts in the table are in
Canadian dollars (“C$”).  All data presented below should be read in
conjunction with ITEM 5 Operating and Financial Review and Prospects and ITEM 18
Financial Statements and accompanying notes included in this Form
20-F.





For
      the years ended December 31 (in thousands of Canadian dollars except for
      per unit amounts)
                
                2008
                
                
                2007
                
                
                2006
                
                
                2005
                
                
                2004Amounts
      in Accordance with Canadian GAAPFINANCIALRevenue
      before mark-to-market adjustment(1)
                
                
                255,268
                
                
                
                223,828
                
                
                
                233,592
                
                
                
                157,743
                
                
                
                108,293Income
      (loss) before taxes
                
                
                11,892
                
                
                
                (177,986
                )
                
                
                (121,850
                )
                
                
                (16,292
                )
                
                
                14,953Per
      unit  ($)
                
                
                0.19
                
                
                
                (2.98
                )
                
                
                (2.76
                )
                
                
                (0.55
                )
                
                
                0.64Net
      income (loss)
                
                
                7,061
                
                
                
                (142,036
                )
                
                
                (64,239
                )
                
                
                970
                
                
                
                14,764Per
      unit  ($)
                
                
                0.11
                
                
                
                (2.38
                )
                
                
                (1.46
                )
                
                
                0.03
                
                
                
                0.62Per
      unit – diluted ($)
                
                
                0.11
                
                
                
                (2.38
                )
                
                
                (1.46
                )
                
                
                0.03
                
                
                
                0.62Total
      assets
                
                
                587,018
                
                
                
                599,790
                
                
                
                795,366
                
                
                
                611,543
                
                
                
                200,301Net
      assets
                
                
                294,416
                
                
                
                219,184
                
                
                
                403,756
                
                
                
                322,111
                
                
                
                98,095Unitholders’
      equity
                
                
                294,416
                
                
                
                219,184
                
                
                
                402,024
                
                
                
                289,707
                
                
                
                98,095SHARES
      AND UNITS OUTSTANDINGWeighted
      average units outstanding (000s)
                
                
                61,661
                
                
                
                59,766
                
                
                
                44,142
                
                
                
                29,534
                
                
                
                23,328Units
      outstanding at period end (000s)
                
                
                62,159
                
                
                
                61,436
                
                
                
                56,098
                
                
                
                36,504
                
                
                
                25,427





Amounts
      in Accordance with U.S. GAAP (2)FINANCIALRevenue
      before mark-to-market adjustment(1)
                                    
                                    
                                    255,268
                                    
                                    
                                    
                                    223,828
                                    
                                    
                                    
                                    233,592
                                    
                                    
                                    
                                    157,743
                                    
                                    
                                    
                                    108,293Income
      (loss) before taxes
                                    
                                    
                                    (46,687
                                    )
                                    
                                    
                                    (47,747
                                    )
                                    
                                    
                                    76,787
                                    
                                    
                                    
                                    (28,989
                                    )
                                    
                                    
                                    7,536Per
      unit  ($)
                                    
                                    
                                    (0.76
                                    )
                                    
                                    
                                    (0.80
                                    )
                                    
                                    
                                    1.71
                                    
                                    
                                    
                                    (0.94
                                    )
                                    
                                    
                                    0.32Net
      income (loss)
                                    
                                    
                                    (31,802
                                    )
                                    
                                    
                                    (65,664
                                    )
                                    
                                    
                                    (280,348
                                    )
                                    
                                    
                                    (18,780
                                    )
                                    
                                    
                                    10,338Per
      unit ($)
                                    
                                    
                                    (0.52
                                    )
                                    
                                    
                                    (1.10
                                    )
                                    
                                    
                                    (6.26
                                    )
                                    
                                    
                                    (0.61
                                    )
                                    
                                    
                                    0.44Per
      unit – diluted ($)
                                    
                                    
                                    (0.52
                                    )
                                    
                                    
                                    (1.10
                                    )
                                    
                                    
                                    (6.26
                                    )
                                    
                                    
                                    (0.61
                                    )
                                    
                                    
                                    0.44Total
      assets
                                    
                                    
                                    279,389
                                    
                                    
                                    
                                    387,045
                                    
                                    
                                    
                                    465,676
                                    
                                    
                                    
                                    530,433
                                    
                                    
                                    
                                    171,331Net
      assets
                                    
                                    
                                    2,995
                                    
                                    
                                    
                                    22,247
                                    
                                    
                                    
                                    115,026
                                    
                                    
                                    
                                    262,821
                                    
                                    
                                    
                                    80,037Unitholders’
      equity, including mezzanine equity
                                    
                                    
                                    2,995
                                    
                                    
                                    
                                    22,247
                                    
                                    
                                    
                                    115,026
                                    
                                    
                                    
                                    262,821
                                    
                                    
                                    
                                    80,037SHARES
      AND UNITS OUTSTANDINGWeighted
      average units outstanding (000s)
                                    
                                    
                                    61,661
                                    
                                    
                                    
                                    59,766
                                    
                                    
                                    
                                    44,846
                                    
                                    
                                    
                                    30,834
                                    
                                    
                                    
                                    23,328Units
      outstanding at period end (000s)
                                    
                                    
                                    62,159
                                    
                                    
                                    
                                    61,436
                                    
                                    
                                    
                                    56,098
                                    
                                    
                                    
                                    36,504
                                    
                                    
                                    
                                    25,427


(1)
            Revenue  before
      mark-to-market adjustment is a non-GAAP measure.  Refer to the
      “Revenues” section in Item 5.A.


(2)
            See
      note 21 to the consolidated financial statements for an explanation of the
      significant differences between Canadian and U.S.
  GAAP.





Exchange
Rate Information




We
publish our consolidated financial statements in Canadian dollars.  In
this report, except where otherwise indicated, all dollar amounts are stated in
Canadian dollars.  References to “$” or “C$” are to Canadian dollars
and references to “US$” are to U.S. dollars.  The following table sets
forth for each period indicated the period end exchange rates for conversion of
U.S. dollars to Canadian dollars, the average exchange rates on the last day of
each month during such period and the high and low exchange rates during such
period.  These rates are based on the noon buying rate in New York
City, expressed in U.S. dollars, for wire transfers in Canadian dollars as
certified for customs purposes by the Federal Reserve Bank of New
York.  The exchange rates are presented as U.S. dollars per Canadian
dollar.  On June 22, 2009, the noon buying rate was US$1.00 equals
Cdn$1.1547 and the inverse noon buying rate was Cdn$1.00 equals
US$0.8660.








U.S. Dollar per Canadian
    DollarHigh
                LowMay
      2009
                0.9198
                0.8423April
      2009
                0.8375
                0.7910March
      2009
                0.8167
                0.7692February
      2009
                0.8202
                0.7758January
      2009
                0.8458
                0.7849December
      2008
                0.8358
                0.7711








Year Ended December 31
                  U.S. Dollar per Canadian
    Dollar2008
                2007
                2006
                2005
                2004Average
                0.9381
                0.9304
                0.8818
                0.8253
                0.7683







B.  Capitalization
and Indebtedness




Not
applicable.




C.  Reasons
for the Offer and Use of Proceeds




Not
applicable.







D.  Risk
Factors




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





Enterra Energy Trust Form 20 –
F





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 Enterra may not be able to obtain
additional financing on attractive economic terms, if at all.  On June
25, 2008 Enterra 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
Enterra.  Borrowings under the revolving and operating credit
facilities at March 31, 2009 were $80.0 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 bank
debt is 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.





Enterra Energy Trust Form 20 –
F





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 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.





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




The
reserve and recovery information contained in the Reserve Reports relating to
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.





Enterra Energy Trust Form 20 –
F





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 production 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 Trusts activities to oil and gas 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, 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
still has limited experience operating properties in the United States and
therefore is reliant on the local employees and on the U.S. Farmout partner for
technical and operational support.  It is the Trust’s expectation that
it will gain more insight into the technical and operational characteristics of
each of these properties through these relationships.  Any early
termination or deterioration of the relationship with a partner, or any
inability to rapidly understand the geology and production characteristics of
the properties, could have a material adverse effect on the market price of the
Trust Units or Debentures.





Enterra Energy Trust Form 20 –
F








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 2008, approximately 5% 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 us.





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”.





Enterra Energy Trust Form 20 –
F








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 Enterra’s 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.





Enterra
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





Enterra Energy Trust Form 20 –
F





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




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





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





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.





Enterra Energy Trust Form 20 –
F





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.





Enterra’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  Enterra’s costs and have a material adverse impact on
Enterra.





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 Enterra to amend its Credit Facilities to
address the changes in accounting principles.





Enterra’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 Income Tax
Act (Canada) (the “Tax Act”) provides that a trust will permanently lose
its “mutual fund trust” status (which is essential to the income trust
structure) if it is established or maintained primarily for the benefit of
non-residents of Canada (which is generally interpreted to mean that the
majority of Unitholders must not be non-residents of Canada), unless at all
times “all or substantially all” of the trust’s property consisted of property
other than certain taxable Canadian property (the “TCP
Exception”).  Based on the most recent information obtained through
the Trust’s transfer agent and financial intermediaries, in February 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





Enterra Energy Trust Form 20 –
F





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”.  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 us.  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
Enterra), 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 29.5
percent in 2011 and 28.0 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





Enterra Energy Trust Form 20 –
F





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, the Canadian Minister of Finance tabled a Notice of Ways and
Means Motion in the House of Commons which contained proposed changes to the
SIFT conversion provisions under the Income Tax Act.  On
December 4, 2008, the Minister 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 Department of 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.





Enterra Energy Trust Form 20 –
F





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 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





Enterra Energy Trust Form 20 –
F





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.




Enterra
is a 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





Enterra Energy Trust Form 20 –
F





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.  Since at present the Trust does
not reinvest the majority of its cash flow, its success is, in part, dependent
on its ability to raise capital from time to time by selling additional Trust
Units.  Unitholders will suffer dilution as a result of these
offerings if, for example, the cash flow, production or reserves from the
acquired assets do not reflect the additional number of Trust Units issued to
acquire those assets.  Unitholders may also suffer dilution in
connection with future issuances of Trust Units to effect
acquisitions.





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





Enterra Energy Trust Form 20 –
F








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 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.




ITEM
4 – INFORMATION ON THE COMPANY






A.  History
and Development of the Company






Enterra Energy
Trust




Enterra
Energy Trust is an oil and gas trust established under the laws of the Province
of Alberta pursuant to the Trust Indenture dated as of October 24, 2003,
between Enterra Energy Corp. and Olympia Trust Company (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, Tel: (403) 263-0262.  The Trust’s registered office is
located at 4300 Bankers Hall West, 888 – 3rd Street
S.W., Calgary, Alberta, Canada T2P 5C5.  Our agent for service of
process in the United States is CT Corporation, 2610, 520 Pike Street, Seattle,
Washington 98101.





As a
result of the completion of a plan of arrangement involving the Trust, Enterra
Energy Corp. (“Old Enterra”), Enterra Acquisition Corp. and Enterra Energy
Commercial Trust (“EEC Trust” or “Commercial Trust”) (the “Arrangement”) on
November 25, 2003, former holders of common shares of Old Enterra received
two trust units or two Exchangeable Shares of Enterra Acquisition Corp., in
accordance with the elections made by such holders, and Old Enterra became a
subsidiary of the Trust.  Old Enterra was subsequently amalgamated
with Enterra Acquisition Corp. to form Enterra Energy Corp.  (“New
Enterra”).





The
principal undertaking of the Trust is to issue trust units and to acquire and
hold debt instruments, royalties and other interests.  The direct and
indirect wholly owned subsidiaries of the Trust carry on the business of
acquiring and holding interests in petroleum and natural gas properties and
assets related thereto.





Olympia
Trust Company has been appointed as trustee under the Trust
Indenture.  The beneficiaries of the Trust are holders of the
outstanding trust units.  The principal and head office of Olympia
Trust Company is located at 2300, 125 – 9th Avenue S.E., Calgary, Alberta T2G
0P6.




History and Significant
Acquisitions




2006 Acquisition of Oklahoma
Assets




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





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





Enterra Energy Trust Form 20 –
F





wells.  Enterra
operates all of its related production, gathering and water disposal
facilities.  On June 27, 2006, a farm-out agreement was entered into
with a U.S. Farmout Partner to exploit the undeveloped Hunton Group
prospects.





2006 Property Swap with JED
Oil Inc.





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





2007 Acquisition of Trigger
Resources Ltd.




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





2007 Disposition of Non-core
Assets




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





2008 Disposition of Non-core
Assets




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




Equity
Offerings


2006
Financings




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





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





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





2007
Financings




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




B.  Business
Overview







Enterra Energy Trust Form 20 –
F





1.  Nature
of the Business





Enterra
is an exploration and production oil and gas trust based in Calgary, Alberta,
Canada with its United States operations office located in Oklahoma City,
Oklahoma.  Enterra’s trust units are listed on the New York Stock
Exchange (ENT) and Enterra’s trust units and convertible debentures are listed
on the Toronto Stock Exchange (ENT.UN, ENT.DB and ENT.DB.A).




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 2008, approximately45% 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 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 2008 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, 2008, the Trust employed or contracted 54 office personnel and 36
field operations personnel in its Canadian operations and 20 office personnel
and 33 field operations personnel in its U.S. operations for a total of 143
employees.




Business Strategy During
2008




The
Trust’s portfolio of oil and gas properties is geographically diversified with
producing properties located principally in Alberta, British Columbia,
Saskatchewan and Oklahoma.  Average production during 2008 was 10,283
boe per day comprised of approximately 63% natural gas and 37% crude oil and
natural gas liquids (“NGL”).  For 2009, production is expected to be
approximately 47% oil and NGL and 53% natural gas due to new marketing contracts
in Oklahoma that recognize more volume for the natural gas liquids in the
production stream.  Enterra has compiled a multi-year drilling
inventory for its properties.





Enterra
had some significant accomplishments during the year primarily in the areas of
focus which were debt reduction and reserve replacement.  Additional
highlights were:





Enterra Energy Trust Form 20 –
F





·      Total bank debt was decreased to
$95.5 million, a reduction of $76.5 million during the year, and has been
further reduced by approximately $15.5 million since the end of
2008.


·
            Net
      debt was reduced to $52.4 million from $168.2 million at the end of
      2007.  This is a decrease of 69
  percent.


·
            Funds
      from operations grew by 48 percent year over year to $107.3 million
      compared to $72.7 million for 2007.


·
            Production
      averaged 10,283 boe per day a decrease of 17 percent, despite the
      disposition of certain producing properties during the first half of the
      year.


·
            Finding
      and development costs declined by 25 percent to $8.24/boe (P+P excluding
      FDC) from $10.93/boe.


·
            Reserves
      produced during 2008 were replaced on a proved plus probable basis,
      through an effective capital spending program and the negotiation of new
      marketing agreements in Oklahoma.


·
            Participated
      in 42 wells (17.4 net) attaining a 97% success
  rate.





2.  Markets and
Revenues




Producers
of oil negotiate sales contracts directly with oil purchasers, generally
obtaining in a market price for oil.  The price depends, in part, on
oil type and quality, prices of competing fuels, distance to market, the value
of refined products, the supply/demand balance and other contractual terms, as
well as on the world price of oil.  The price of natural gas sold in
intraprovincial, interprovincial and international trade is determined by
negotiation between buyers and sellers.  The price depends, in part,
on natural gas quality, prices of competing natural gas and other fuels,
distance to market, access to downstream transportation, length of contract
term, seasonal factors, weather conditions, the value of refined products, the
supply/demand balance and other contractual terms




Our
revenue is obtained from the sale of oil and natural gas.  The
revenues for the last three years were:





For
      the year ended December 31,($000s)
                
                2008
                
                
                2007
                
                
                2006Canada
                
                
                151,675
                
                
                
                138,844
                
                
                
                152,254United
      States
                
                
                103,593
                
                
                
                84,984
                
                
                
                81,338Revenue
                
                
                255,268
                
                
                
                223,828
                
                
                
                233,592





3.  Seasonality





The
business is somewhat seasonal in nature because a significant portion of the
demand for natural gas is during the winter heating season in North America
which can result in seasonal commodity price volatility.  We produce
the oil and gas and then sell the oil and gas to marketing companies and
integrated oil and gas companies that then arrange for the oil and gas to be
further refined and processed and they sell the refined products to the ultimate
end users.





4.  Volatility
of Prices





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.





5.  Marketing
Channels





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.





Enterra Energy Trust Form 20 –
F








6.  Patents
and Licenses





Enterra
is not dependent on any patents or licenses in order to conduct
business.








Enterra Energy Trust Form 20 –
F





7.  Competition





The
petroleum industry is highly competitive.  We compete with numerous
other participants in the acquisition of oil and gas leases and properties, and
the recruitment of employees.  Competitors include oil companies and
other income trusts, many of whom have greater financial resources, staff and
facilities than we have.  Our ability to increase reserves in the
future will depend not only on our ability to develop existing properties, but
also on our ability to select and acquire suitable additional producing
properties or prospects for drilling.  We also compete with numerous
other companies in the marketing of oil.  Competitive factors in the
distribution and marketing of oil include price and methods and reliability of
delivery.





8.  Government Regulation
in Canada and the United States





The oil
and natural gas industry is subject to extensive controls and regulations
governing its operations, including land tenure, exploration, development,
production, refining, transportation and marketing, imposed by legislation
enacted by various levels of government and with respect to pricing and taxation
of oil and natural gas by agreements among the governments of Canada, Alberta,
British Columbia, Saskatchewan, United States and Oklahoma all of which should
be carefully considered by investors in the oil and gas industry.  It
is not expected that any of these controls or regulations will affect our
operations in a manner materially different from how they would affect other oil
and gas companies of similar size operating in Western Canada and
Oklahoma.  All current legislation is a matter of public record and we
are unable to predict what additional legislation or amendments may be
enacted.




Enterra’s
U.S. oil and natural gas operations are regulated by administrative agencies
under statutory provisions of the state of Oklahoma where such operations are
conducted and by certain agencies of the federal government for operations on
federal leases.  These statutory provisions regulate matters such as
the exploration for and production of crude oil and natural gas, including
provisions related to permits for the drilling of wells, bonding requirements in
order to drill or operate wells, the location of wells, the method of drilling
and casing wells, the surface use and restoration of properties upon which wells
are drilled, and the abandonment of wells.  Enterra’s U.S. operations
are also subject to various conservation laws and regulations which regulate
matters such as the size of drilling and spacing units or proration units, the
number of wells which may be drilled in an area, and the unitization or pooling
of crude oil and natural gas properties.  In addition, state
conservation laws sometimes establish maximum rates of production from crude oil
and natural gas wells, generally prohibit the venting or flaring of natural gas,
and impose certain requirements regarding the ratability or fair apportionment
of production from fields and individual wells.






Pricing and Marketing -
Oil






Crude oil
exported from Canada is subject to regulation by the National Energy Board
(the "NEB") and the Government of Canada.  Oil exports may be
made pursuant to export contracts with terms not exceeding one year in the case
of light crude oil, and not exceeding two years in the case of heavy crude oil,
provided that an order approving any such export has been obtained from the
NEB.  Any oil export to be made pursuant to a contract of longer
duration (to a maximum of 25 years) requires an exporter to obtain an
export license from the NEB and the issue of such a license requires the
approval of the Governor in Council.






Pricing and Marketing –
Natural Gas






Natural
gas exported from Canada is subject to regulation by the NEB and the Government
of Canada.  Exporters are free to negotiate prices and other terms
with purchasers, provided that the export contracts must continue to meet
certain criteria prescribed by the NEB and the Government of
Canada.  Natural gas exports for a term of less than two years or for
a term of two to 20 years (in quantities of not more than
30,000 cubic metres per day), must be made pursuant to an NEB
order.  Any natural gas export to be made pursuant to a contract of
longer duration (to a maximum of 25 years) or a larger quantity
requires an exporter to obtain an export license from the NEB and the issue of
such a license requires the approval of the Governor
in Council.






The
governments in the Canadian provinces where Enterra operates also regulate the
volume of natural gas which may be removed from those provinces for consumption
elsewhere, based on such factors as reserve availability, transportation
arrangements and market considerations.




Royalties and
Incentives


Canada:


In
addition to federal regulation, each province has legislation and regulations,
which govern land tenure, royalties, production rates, environmental protection
and other matters.  The royalty regime is a significant factor in the
profitability of crude oil, natural gas liquids, sulphur and natural gas
production.  Royalties payable on production from





Enterra Energy Trust Form 20 –
F





lands
other than Crown lands are determined by negotiations between the mineral owner
and the lessee, although production from such lands is subject to certain
provincial taxes and royalties.  Crown royalties are determined by
governmental regulation and are generally calculated as a percentage of the
value of the gross production.  The rate of royalties payable
generally depends in part on prescribed reference prices, well productivity,
geographical location, field discovery date and the type or quality of the
petroleum product produced.





From time
to time the governments of the western Canadian provinces create incentive
programs for exploration and development.  Such programs often provide
for royalty rate reductions, royalty holidays and tax credits, and are generally
introduced when commodity prices are low.  The programs are designed
to encourage exploration and development activity by improving earnings and cash
flow within the industry.





United
States:


The
royalties incurred by Enterra’s Oklahoma operations are in the form of freehold
royalties which are charged by the individual mineral owner and production taxes
which are charge by the state of Oklahoma.  The freehold royalty rate
is determined by negotiations between the mineral owner and the lessee at the
beginning of the lease.  The production tax is charged by the Oklahoma
Tax Commission and is based on either prices received or production volumes and
is determined when the well is drilled.  The current production tax
rate is approximately seven percent.  There is currently a six percent
production tax rebate for the first 24 months of production on horizontal
wells.





In late
October 2007, the Alberta provincial government announced a new oil and gas
royalty regime that took effect January 1, 2009.  The Trust has
assessed the impact of the new royalty regime and has determined that it will
have a modest negative effect on its current portfolio of production and
reserves in Alberta.  Enterra now incorporates the new royalty scheme
into its Alberta-based economic analysis prior to pursuing opportunities in the
province.  During 2008, approximately 31% of the Trust’s production
came from Alberta.








Tax
Legislation


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 Enterra.  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
Enterra), 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 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 29.5 percent in 2011
and 28.0 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;







Enterra Energy Trust Form 20 –
F





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, the Canadian Minister of Finance tabled a Notice of Ways and
Means Motion in the House of Commons which contained proposed changes to the
SIFT conversion provisions under the Income Tax Act.  On
December 4, 2008, the Minister 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 Department of 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.








Land
Tenure





Crude oil
and natural gas located in the western provinces is owned predominantly by the
respective provincial governments.  Provincial governments grant
rights to explore for and produce oil and natural gas pursuant to leases,
licenses and permits for varying terms from two years and on conditions set
forth in provincial legislation including requirements to perform specific work
or make payments.  Oil and natural gas located in such provinces can
also be privately owned and rights to explore for and produce such oil and
natural gas are granted by lease on such terms and conditions as may be
negotiated.  In Oklahoma land sales are done privately between the
individual mineral owner and Enterra.





Environmental
Regulation





The oil
and natural gas industry is currently subject to environmental regulations
pursuant to a variety of provincial and federal legislation.  Such
legislation provides for restrictions and prohibitions on the release or
emission of various substances produced in association with certain oil and gas
industry operations.  In addition, such legislation requires that well
and facility sites be abandoned and reclaimed to the satisfaction of provincial
authorities.  Compliance with such legislation can require significant
expenditures and a breach of such requirements may result in suspension or
revocation of necessary licenses and authorizations, civil liability for
pollution damage and the imposition of material fines and
penalties.





Environmental
legislation in the Province of Alberta has been consolidated into the Environmental Protection and
Enhancement Act, or EPEA, which came into force on September 1,
1993.  The EPEA imposes stricter environmental standards, requires
more stringent compliance, reporting and monitoring obligations and
significantly increases penalties for violations.  We are committed to
meeting our responsibilities to protect the environment wherever it operates and
anticipates making increased expenditures of both a capital and expense nature
as a result of the increasingly stringent laws relating to the protection of the
environment and will be taking such steps as required to ensure compliance with
the EPEA and similar legislation in other jurisdictions in which it
operates.  We believe that we are in material compliance with
applicable environmental laws and regulations.  We also believe that
it is reasonably likely that the trend towards stricter standards in
environmental legislation and regulation will continue.





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





Enterra Energy Trust Form 20 –
F





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
2008, the Trust experienced three salt water spills at water handling facilities
in Oklahoma.  In aggregate, in excess of 200,000 bbls of produced
water is moved daily to facilitate hydrocarbon production.  The
increased drilling activity in 2008 coupled with the prolific nature of many of
these new wells has resulted in almost double the daily water production as
compared to 2007.  As such, the Trust took steps over 2008 to reduce
the environmental risk from potential spills.  These improvements
included enhancements to both the alarm systems as well as to the on-site spill
containment.








Additional Information
Relating to the Trust





Income
Streams and Distribution Policy





A portion
of the cash flows generated by the assets held, directly or indirectly, by the
Trust may be distributed to its Unitholders.  Enterra’s 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.  The availability of cash for the payment of distributions will
at all times be dependant upon a number of factors, including resource prices,
production rates and reserve growth and the Enterra Board cannot assure that
sufficient cash will be available for distribution to Unitholders in the amounts
anticipated or at all.  See “Risk Factors” in Item 3
D.





In
September 17, 2007 Enterra suspended its monthly distributions in order to
redirect its cash flow to the repayment of its outstanding debt.  In
June 2008, Enterra stated that it would extend the distribution suspension until
at least November 2008 and that under the current credit facility Enterra is
restricted from paying distributions while it has the second-lien facility in
place.  As a result, no distributions were paid in 2008.




Enterra
continues to assess how cash flows generated from operations are
used.  In light of the current economic uncertainty, Enterra has
deferred capital spending and has increased its cash position and reduced
debt.  Enterra will maintain a conservative approach during 2009 and
assess how best to allocate cash between capital spending, debt repayment and
distributions.




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







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.





Enterra Energy Trust Form 20 –
F








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.




The Trust
Indenture




Enterra’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.




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, installment or subscription receipts.  Enterra’s 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.





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,





Enterra Energy Trust Form 20 –
F





communications
and other documentation sent to Unitholders, the Special Voting Rights do not
confer upon the holders thereof any other rights.





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.





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:
(iii) 90% of the
“market price” of the Trust Units on the principal market on which the Trust
Units are quoted for trading during the 10 trading day period commencing
immediately after the date on which the Trust Units are tendered to the Trust
for redemption; and (iv) the closing market
price on the principal market on which the Trust Units are quoted for trading on
the date that the Trust Units are so tendered for 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





Enterra Energy Trust Form 20 –
F





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 TSX or NYSE 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.





Reporting to Unit
Holders





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 Canadian 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.





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 Enterra’s 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.





Enterra Energy Trust Form 20 –
F








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.





Voting
of EEC trust units





There is
an annual general meeting of the holders of EEC trust
units.  Immediately following this meeting is a Trustee meeting
permitting the Trustee to vote the EEC trust units held by the Trust in the
manner directed by Unitholders at the immediately preceding meeting of the
Trust.  Any resolution passed by Unitholders pertaining to the manner
in which EEC trust units held by the Trust are to be voted by the Trustee in
respect of a particular matter which is to be put forth to the holders of EEC
trust units for vote at a contemplated meeting (including by written resolution)
of holders of EEC trust units, shall be deemed to be a direction to the Trustee
in respect of the EEC trust units held by the Trust to, as applicable, either
vote such EEC trust units in favor of or in opposition to, or to vote or
with-hold from voting in respect of such matter in equal proportions to the
votes cast by Unitholders in respect of the matter, and the Trustee is obligated
to vote, in respect of such matter if put forth to the holders of EEC trust
units at a meeting of such holders, the EEC trust units held by the Trust in
accordance with such direction.





Exercise
of Voting Rights





Enterra’s
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;







Enterra Energy Trust Form 20 –
F





·
            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.




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.




Delegation
of Authority, Administration and Trust Governance





The
Enterra Board has generally been delegated the significant management decisions
of the Trust.  In particular, the Trustee has delegated to Enterra
responsibility for any and all matters relating to the following: (i) an
offering of securities of the Trust; (ii) ensuring compliance with all
applicable laws, including in relation to an offering of securities of the
Trust; (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 material contracts of the Trust; (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;
(vii) all matters relating to the voting rights on any instruments held by
the Trust, other than the EEC trust units; and (viii) all matters relating
to the specific powers and authorities as set forth in the Trust
Indenture.




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.




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







Enterra Energy Trust Form 20 –
F





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.




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.  Enterra’s 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 Enterra’s 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 Enterra’s 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.




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 Enterra’s 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





Enterra Energy Trust Form 20 –
F





agency or
authority, and shall in all respects act in accordance with the directions, if
any, of Enterra’s 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.





Description of
Debentures




General




Enterra’s
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 Trust’s 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 below 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 below 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




Enterra’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 Enterra’s 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 of the holders of Enterra’s 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 Enterra’s Trust Units or in the
case of any consolidation, amalgamation or merger of the Trust with
or





Enterra Energy Trust Form 20 –
F





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




Enterra’s
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.





Enterra
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 Enterra’s 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, Enterra’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 Enterra’s voluntary liquidation, dissolution or other
winding-up, whether or not involving





Enterra Energy Trust Form 20 –
F





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




Enterra’s
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 Enterra’s
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.





Enterra Energy Trust Form 20 –
F





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 Enterra’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.





Enterra Energy Trust Form 20 –
F





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
Enterra’s 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 were 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 were 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 were 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.





Enterra Energy Trust Form 20 –
F





C.  Organizational
Structure




Enterra Energy
Trust




Enterra
Energy Trust is an oil and gas trust established under the laws of the Province
of Alberta pursuant to the Trust Indenture.  The Trust’s assets
consist of the securities of the Trust Subsidiaries and indirect interests in
crude oil and natural gas properties through the Operating
Subsidiaries.




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 laws of the Province of Alberta on
August 16, 2001.  The partners of the Partnership are EEC and Enterra
Energy Partner Corp. EEC manages the operations of EPP.




Enterra Energy Partner
Corp.




EEPC is 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.





Enterra Energy Trust Form 20 –
F





Organizational
Chart


The
following chart illustrates the Corporate structure as at December 31,
2008.









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




D.  Property,
Plants and Equipment




Enterra’s
Canadian core areas include a variety of assets in Western Canada in the
provinces of British Columbia, Alberta and Saskatchewan.  In northeast
British Columbia Enterra has a significant producing area at
Desan.  In Alberta, the major producing areas are: Clair,
Provost-Alliance-Wainwright, Princess and Ricinus.  In west-central
Saskatchewan, the majority of production is located in the Primate and
Liebenthal areas.  In the United States, Enterra’s producing assets
are located mainly in Grant, Lincoln and Logan Counties in
Oklahoma.  Enterra also has an inventory of minor producing assets,
minor royalty interests, and various prospects of an exploitation and
exploration nature on undeveloped lands in Alberta, British Columbia,
Saskatchewan and Oklahoma, the development of which could significantly increase
the size of the existing production and reserve base.





Enterra Energy Trust Form 20 –
F





Description
of Material Tangible Property




Northeast British
Columbia




The
northeast British Columbia assets consist of the producing property in Desan and
the undeveloped properties at Peggo.




Desan


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




The
average production in Desan for December 2008 was 3.7 mmcf/d natural gas and 23
bbls/d of hydrocarbon liquid from a total of 27 producing
wells.  Desan production is 100% working interest.  McDaniel
assigned total proved reserves of 6.0 Bcf of natural gas and 24 mbbl of NGL to
the Desan property as of the December 31, 2008 effective date.




Enterra
has acquired 45 square kilometres (17 square miles) of 3D seismic and 61
kilometres (38 miles) of trade 2D seismic.  Based upon the Trust’s
technical assessment of the seismic, six locations in the Jean Marie and three
locations in the Debolt formation are at a drill ready stage.  The
Trust is evaluating a multi-well drilling program during the 2009 and 2010
winter drilling season.





Western
Alberta


In
western Alberta, Enterra’s properties range from deep, high-rate foothills sour
gas wells in Ricinus to mid-depth oil wells at Clair.





Clair


The Clair
property is located seven miles north of Grande Prairie, Alberta.  The
Trust’s assets include a 100% working interest in 3,040 acres of land, 25
producing wells, seven water injection wells, and a profit sharing interest in
an oil treating and blending facility.  Gas is conserved and processed
at the Encana Sexsmith gas plant, and the oil is delivered into the Pembina
Peace Pipeline System.  Production is primarily from the Doe Creek
(Dunvegan) formation with a small amount of gas production from the Charlie Lake
formation.  Production is light oil with a 41°API gravity, along with
solution gas.  This pool is under water flood to maximize oil
recovery.  There is also gas production from one Charlie Lake
well.  Average working interest production for December 2008 was 426
bbl/d of oil and 489 mcf/d of raw gas.  Enterra’s technical team is
presently evaluating waterflood optimization options and step-out drilling
opportunities for 2009 or 2010.  McDaniel assigned total proved
reserves of 308 mbbl of crude oil, 591 Mmcf of natural gas, and 31 mbbl of NGL
to the Clair property as of the December 31, 2008 effective date.




Ricinus


Ricinus
is located in the Rocky Mountain foothills, 80 miles northwest of
Calgary.  At Ricinus, Enterra holds a 45% working interest in a 2,800m
(9,200 feet deep) high-rate Leduc reef sour gas well that produces steady at 10
Mmcf/d and 15bbl/d of NGL.  This well has the capability to produce at
higher rates, but has been limited to maximize the reserve
recovery.  McDaniel assigned proved reserves of 5.2 Bcf of natural gas
and 6 mbbl of NGLs to the producing well as of the December 31, 2008 effective
date.




Eastern
Alberta




Provost-Alliance-Wainwright,
Alberta


The
Provost-Alliance-Wainwright producing area is located near Provost,
Alberta.  Major areas are Alliance, Sounding Lake, Soapy Lake,
Halkirk, Monitor, Provost and Wainwright.  Enterra currently has 252
producing oil and gas wells in this area.





Production
is obtained primarily from the Dina, Cummings and Belly River
formations.  Average working interest production for December 2008 was
1,153 bbl/d of oil and NGLs and 1.3 Mmcf/d of gas.  In order to
increase





Enterra Energy Trust Form 20 –
F





production
and lower operating costs, the Trust continues to optimize well pumping systems
and upgrade or consolidate oil batteries and water injection facilities to
handle high volumes of produced fluid more efficiently.  Solution gas
is currently conserved at most of the oil batteries.





McDaniel
assigned total proved reserves 919 mbbl of oil, 327 Mmcf of natural gas and 11
mbbl of NGLs in the Provost-Alliance-Wainwright area, as of the December 31,
2008 effective date.





While
these pools are mature, detailed geologic and engineering studies have
identified significant potential for increases in both production and reserves
through more efficient secondary recovery and exploitation of bypassed pay
zones.  These studies are ongoing and will be utilized to identify
2009 and 2010 opportunities.





Princess


Princess
is located 100 miles southeast of Calgary.  The primary production is
crude oil (27o API) from the Pekisko formation, a reefal
carbonate.  Much of Enterra’s land is covered by 3D seismic, and
detailed geological and geophysical studies have outlined new development
drilling opportunities which the Trust may drill during 2009 and
2010.  In addition, significant potential lies in the Glauconite and
Sunburst formations.  At year end 2008, Enterra had 23 producing wells
in the Princess area with average working interest production of  390
bbl/d of crude oil and NGL and 655 mcf/d of natural gas.





McDaniel
assigned total proved reserves in the Princess area of 289 mbbl of crude oil,
535 Mmcf of natural gas and 8 mbbl of NGLs  in the Princess area as of
December 31, 2008 effective date.




Saskatchewan




Enterra’s
assets in west central Saskatchewan include several areas including Primate and
Liebenthal.  In addition, there are several minor non-core areas
scattered geographically.  In late 2008 Enterra shot a large 3D
seismic program in the Cactus area.  This 3D is currently being
studied to pinpoint drilling locations for 2009.  McDaniel assigned
total proved plus probable reserves of 12.6 Bcf of natural gas and 1,056 mbbl of
oil in the Saskatchewan properties as of the December 31, 2008 effective
date.





Primate


The
Primate area was the main producing asset of the Trigger Resources acquisition
made by Enterra in 2007, and Enterra holds a 100% working interest in this
property.  Production is primarily from the McLaren and Colony
formations.  Although the oil is 11° API gravity, its gasified
nature allows high initial production rates of up to 250 bbls/day per well of
oil under primary recovery.





Average
December 2008 production from the Primate area was 793 bbls/day of crude oil and
1,151 mcf/day of natural gas.





Plans for
2009 or 2010 include completing a study of secondary recovery opportunities in
the main primate oil pool which potentially could potentially double the
ultimate recoverable oil reserves.  Plans also may include drilling
several infill wells.





Liebenthal


The gas
production from the Liebenthal area comes from the Viking
formation.  Enterra holds a 100% working interest in two prolific
wells in the pool.  Seismic indicates that the pool is structurally
controlled, and future opportunities include infill drilling of the main pool
and exploiting up-hole potential in the Belly River
formation.  Average December 2008 production from the Liebenthal area
was 3,520 mcf/day of natural gas.





Cactus
Lake


3D
seismic was shot over Cactus area in late 2008.  The seismic
information continues to be studied, and plans for 2009 or 2010 include drilling
several seismic delineated locations as well as farming in on adjacent
lands.




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 and gas from
smaller rock pores.





Enterra Energy Trust Form 20 –
F





Peak
hydrocarbon production rates average 150 BOE/d per horizontal
well.  Peak rates are generally observed within six months of
production commencement.  Enterra generally has a 20-25% working
interest in producing wells drilled by the Trust’s U.S. Farmout
Partner.  Average gross proved plus probable reserves are
approximately 280 Mboe per horizontal well.





Under a
farmout agreement, the U.S. Farmout Partner pays 100% of the costs to drill and
complete each well on Trust lands to earn a 70% working interest.  The
farmout agreement requires the U.S. Farmout Partner to drill not less than 30
wells during rolling twenty-month periods.  By the end of 2008, 61
wells were drilled as producers, in addition to three salt water disposal
wells.  Of the wells drilled by the end of 2008, 55 were producing
wells, three are awaiting completion, one is completed but not producing and two
were dry and abandoned.  Enterra pays 100% of the costs of drilling
the required water disposal wells and associated infrastructure, but recovers
100% of those costs plus interest over a 3-year period through a capital
recovery agreement with the U.S. Farmout Partner.





Average
production for 2008 in Oklahoma was 24.6 Mmcf/d of natural gas and 545 bbl/d of
crude oil and NGLs.  Haas attributed total proved reserves of 967 mbbl
of crude oil, 3,955 mbbl of NGL’s and 33.7 Bcf of natural gas to Oklahoma as of
the January 1, 2009 effective date.  Working interest production rates
in December 2008 were 22.5 Mmcf/d and 547 bbl/d oil and
NGL.  Operating costs on these properties averaged $11.42/boe (Cdn $)
during 2008.  Enterra’s U.S. office is located in Oklahoma City, with
a fully staffed field office maintained in Carney, Oklahoma, about 50 miles to
the north-east.  The Trust’s U.S. based staff as of December 31, 2008
numbers 53 people.





In
Oklahoma, there is approximately 44,706 net undeveloped acres of land, with an
average working interest of 100% at year end 2008.  This acreage is
centered in Alfalfa, Grant, Lincoln and Logan Counties.  To date, more
than 50 additional drilling locations on these properties have been
identified.





Reserves
Summary





See Note
22 to the Consolidated Financial Statement for information on Enterra’s oil and
gas producing activities.








Production
before royalties from 2006 – 2008


2008
                
                
                2007
                
                
                2006Oil
      and NGLs (bbls/day)
                
                
                3,756
                
                
                
                4,698
                
                
                
                5,126Natural
      gas (mcf/day)
                
                
                39,163
                
                
                
                46,378
                
                
                
                43,358Total
      (boe/day)
                
                
                10,283
                
                
                
                12,428
                
                
                
                12,352







Oil
and Gas Wells




The
following table summarizes the Trust’s interest as at December 31, 2008 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
                
                
                300.0
                
                
                
                218.7
                
                
                
                46.0
                
                
                
                30.6
                
                
                
                230.0
                
                
                
                182.9
                
                
                
                34.0
                
                
                
                21.0
                
                
                
                610.0
                
                
                
                453.2British
      Columbia
                
                
                -
                
                
                
                -
                
                
                
                27.0
                
                
                
                27.0
                
                
                
                -
                
                
                
                -
                
                
                
                13.0
                
                
                
                13.0
                
                
                
                40.0
                
                
                
                40.0Saskatchewan
                
                
                19.0
                
                
                
                17.1
                
                
                
                13.0
                
                
                
                13.0
                
                
                
                8.0
                
                
                
                7.2
                
                
                
                9.0
                
                
                
                9.0
                
                
                
                49.0
                
                
                
                46.3Total
                
                
                319.0
                
                
                
                235.8
                
                
                
                86.0
                
                
                
                70.6
                
                
                
                238.0
                
                
                
                190.1
                
                
                
                56.0
                
                
                
                43.0
                
                
                
                699.0
                
                
                
                539.5Oklahoma
                
                
                -
                
                
                
                -
                
                
                
                154.0
                
                
                
                91.5
                
                
                
                -
                
                
                
                -
                
                
                
                49.0
                
                
                
                36.4
                
                
                
                203.0
                
                
                
                127.8Grand
      Total
                
                
                319.0
                
                
                
                235.8
                
                
                
                240.0
                
                
                
                162.0
                
                
                
                238.0
                
                
                
                190.1
                
                
                
                105.0
                
                
                
                79.4
                
                
                
                902.0
                
                
                
                667.3


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




Land
Holdings




The
following table summarizes land holdings in which Enterra has an interest at
December 31, 2008.


Area
                
                Gross
      Acres
                
                
                Net
      AcresCanada
                
                
                275,389
                
                
                
                177,905United
      States
                
                
                108,106
                
                
                
                77,209Total
                
                
                383,495
                
                
                
                255,114





Delivery
Commitments





The Trust
has not entered into obligations to provide a fixed and determinable quantity of
oil or gas in the near future under existing contracts or
agreements.  Enterra has never been able to meet any significant
delivery commitments.





Enterra Energy Trust Form 20 –
F





Environmental
Issues





See Item
4. Business Overview, Government Regulations for a discussion on Enterra’s
Environmental Issues.





Plans
for Expansion





As an oil
and gas producer, Enterra has a declining asset base and therefore relies on
development activities and acquisitions to replace production and add additional
reserves.  The Trust’s future oil and natural gas production is highly
dependent on Enterra’s success in exploiting its asset base and acquiring or
developing additional reserves.  Although the Trust has an internal
inventory of drilling opportunities it continues to exploit, Enterra will
evaluate alternatives external to this inventory but will also evaluate and act
on accretive external acquisition opportunities.  An expansion will be
financed through cash flow, debt financing, farm in agreements or other
corporate financings.





ITEM
4A.  UNRESOLVED STAFF COMMENTS





None




ITEM
5 – OPERATING AND FINANCIAL REVIEW AND PROSPECTS




Overview





The
following should be read in conjunction with other financial information
included in this annual report on 20-F and with the consolidated financial
statements of Enterra Energy Trust (“the Trust” or “Enterra”) contained in this
Form 20-F.  All amounts are stated in Canadian dollars and are
prepared in accordance with Canadian Generally Accepted Accounting Principles
(“GAAP”) except where otherwise indicated.  Discussion with regard to
the Trust’s 2009 outlook is based on currently available
information.




A.  Operating
Results







Critical Accounting
Estimates





Enterra
prepares its financial statements and the accompanying notes in conformity with
generally accepted accounting principles in Canada, which requires management to
make estimates and assumptions about future events that affect the reported
amounts in the financial statements and the accompanying
notes.  Enterra identifies certain accounting policies as critical
based on, among other things, their impact on the portrayal of Enterra’s
financial condition, results of operations or liquidity and the degree of
difficulty, subjectivity and complexity in their deployment.  Critical
accounting policies cover accounting matters that are inherently uncertain
because the future resolution of such matters is unknown.  Management
routinely discusses the development, selection and disclosure of each of the
critical accounting policies.  Following is a discussion of Enterra’s
most critical accounting policies:





Reserve
Estimates





Enterra’s
estimate of proved reserves is based on the quantities of oil and gas that
geological and engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under existing economic and
operating conditions.  The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment.  For example, Enterra must estimate the
amount and timing of future operating costs, royalties, development costs and
workover costs, all of which may in fact vary considerably from actual
results.  In addition, as prices and cost levels change from year to
year, the estimate of proved reserves also changes.  Any significant
variance in these assumptions could materially affect the estimated quantity and
value of the Trust’s reserves.  As such, Enterra’s reserve engineers
review and revise the Trust’s reserve estimates at least
annually.




Despite
the inherent imprecision in these engineering estimates, Enterra’s reserves are
used throughout our financial statements.  For example, since Enterra
uses the units-of-production method to amortize its oil and gas properties, the
quantity of reserves could significantly impact its DD&A
expense.  Enterra’s oil and gas properties are also subject to a
“ceiling” limitation based in part on the quantity of its proved
reserves.  Finally, these reserves are the basis for its supplemental
oil and gas disclosures.




Asset
Retirement Obligation (ARO)





The Trust
has significant obligations to remove tangible equipment and restore land at the
end of oil and gas production operations.  Enterra’s removal and
restoration obligations are primarily associated with plugging and abandoning
wells.  Estimating the future restoration and removal costs is
difficult and requires management to make





Enterra Energy Trust Form 20 –
F





estimates
and judgments because most of the removal obligations are many years in the
future, and contracts and regulation often have vague descriptions of what
constitutes removal.  Asset removal technologies and costs are
constantly changing, as are regulatory, political, environmental, safety and
public relations considerations.




ARO
associated with retiring tangible long-lived assets is recognized as a liability
in the period in which the legal obligation is incurred and becomes
determinable.  The liability is offset by a corresponding increase in
the underlying asset.  The ARO is recorded at fair value, and
accretion expense is recognized over time as the discounted liability is
accreted to its expected settlement value.




Inherent
in the present value calculation are numerous assumptions and judgments
including the ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement and changes in the legal, regulatory,
environmental and political environments.  To the extent future
revisions to these assumptions impact the present value of the existing ARO
liability, a corresponding adjustment is made to the oil and gas property
balance.




Income
Taxes





Enterra’s
oil and gas exploration and production operations are currently located in
Canada and the United States.  As a result, Enterra is subject to
taxation on its income in two jurisdictions.  Enterra records future tax assets and
liabilities to account for the expected future tax consequences of events that
have been recognized in its financial statements and tax returns.  The
Trust routinely assesses the ability to realize its future tax
assets.  If Enterra concludes that it is more likely than not that
some portion or all of the future tax assets will not be realized under
accounting standards, the tax asset would be reduced by a valuation
allowance.  Enterra considers future taxable income in making such
assessments.  Numerous judgments and assumptions are inherent in the
determination of future taxable income, including factors such as future
operating conditions (particularly as related to prevailing oil and gas
prices).




The Trust
regularly assesses and, if required, establishes accruals for tax contingencies
that could result from assessments of additional tax by taxing jurisdictions in
countries where the Trust operates.  Tax reserves have been
established and include any related interest, despite the belief by the Trust
that certain tax positions have been fully documented in the Trust’s tax
returns.  These reserves are subject to a significant amount of
judgment and are reviewed and adjusted on a periodic basis in light of changing
facts and circumstances considering the progress of ongoing tax audits, case law
and any new legislation.  The Trust believes that the reserves
established are adequate in relation to the potential for any additional tax
assessments.




SALES VOLUMES BEFORE
ROYALTIES




2008
                  
                  
                  2007
                  
                  
                  2006Daily sales volumes – averageOil
      & NGL (bbls per day)
                  
                  
                  3,756
                  
                  
                  
                  4,698
                  
                  
                  
                  5,126Natural
      gas (mcf per day)
                  
                  
                  39,163
                  
                  
                  
                  46,378
                  
                  
                  
                  43,358Total
      (boe per day)
                  
                  
                  10,283
                  
                  
                  
                  12,428
                  
                  
                  
                  12,352Daily sales volumes – exit
rateOil
      & NGL (bbls per day)
                  
                  
                  4,250
                  
                  
                  
                  3,952
                  
                  
                  
                  4,758Natural
      gas (mcf per day)
                  
                  
                  33,321
                  
                  
                  
                  45,031
                  
                  
                  
                  46,105Total
      (boe per day)
                  
                  
                  9,804
                  
                  
                  
                  11,457
                  
                  
                  
                  12,442Sales volumes mix by
productOil
      & NGL
                  
                  
                  37
                  %
                  
                  
                  38
                  %
                  
                  
                  41
                  %Natural
      gas
                  
                  
                  63
                  %
                  
                  
                  62
                  %
                  
                  
                  59
                  %100
                  %
                  
                  
                  100
                  %
                  
                  
                  100
                  %
  2008 compared to
2007


Average
production for 2008 decreased 17% to 10,283 boe per day from 12,428 boe per day
in 2007.  The decline in average production was due primarily to the
sale of properties which closed during the first half of the year.





Enterra Energy Trust Form 20 –
F





Average
production during 2008 consisted of 3,756 bbls per day of oil and natural gas
liquids (“NGL”) and 39,163 mcf per day of natural gas, resulting in a mix of 37%
oil and NGL and 63% natural gas.  Enterra exited 2008 with production
of 9,804 boe per day.  As a result of renegotiated marketing contracts
for a portion of the U.S. natural gas production under which Enterra receives a
direct portion of the natural gas liquids extracted from the gas stream, the
2009 production mix is expected to be about 47% oil and natural gas liquids and
53% natural gas.





In 2008,
Enterra participated in the drilling of 42 (17.4 net) wells; 11 (9.8 net) wells
in Canada and 31 (7.6 net) wells in Oklahoma.  All wells, except
the salt water disposal well, in Oklahoma were drilled by a joint venture
partner under an area farmout agreement that resulted in the joint venture
partner paying 100% of the drilling and completion costs in exchange for 70%
working interest.  Overall, the drilling in Canada and Oklahoma
resulted in 31 (8.7 net) gas wells, 8 (7.2 net) oil wells, 1 (1.0 net) salt
water disposal well and two (0.5 net) wells drilled and abandoned, resulting in
a success rate of 97%.





2007
compared to 2006


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





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





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




COMMODITY
PRICING




Pricing Benchmarks2008
                  
                  
                  2007
                  
                  
                  2006WTI
      (US$ per bbl)
                  
                  
                  99.65
                  
                  
                  
                  72.34
                  
                  
                  
                  66.22Average
      exchange rate: US$ to Cdn$1.00
                  
                  
                  0.94
                  
                  
                  
                  0.93
                  
                  
                  
                  0.88WTI
      (Cdn$ per bbl)
                  
                  
                  106.62
                  
                  
                  
                  77.78
                  
                  
                  
                  75.25AECO
      daily index (Cdn$ per GJ)
                  
                  
                  7.71
                  
                  
                  
                  6.55
                  
                  
                  
                  6.53NYMEX
      (US$ per mmbtu)
                  
                  
                  8.93
                  
                  
                  
                  6.92
                  
                  
                  
                  7.26
  West
Texas Intermediate (“WTI”) is a standard benchmark for the price of oil and is
expressed in U.S. dollars per barrel.  The price of natural gas in the
United States is benchmarked on the New York Mercantile Exchange (“NYMEX”) and
expressed in U.S. dollars per million British Thermal Units
(“mmbtu”).  In Western Canada the benchmark is the price at the AECO
hub (a storage and pricing hub for Canadian natural gas market) and is priced in
Canadian dollars per gigajoule (“GJ”).  For the purposes of financial
reporting, Enterra expresses its realized prices for oil and gas in Canadian
dollars.





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.








Enterra Energy Trust Form 20 –
F





2008
compared to 2007


Benchmark
oil prices for 2008 increased 38% to an average of US$99.65 per bbl WTI from
US$72.34 per bbl WTI in 2007.  The U.S. dollar exchange rate to the
Canadian dollar stayed relatively consistent at an average of US$0.94 per
Canadian dollar during 2008 compared to US$0.93 per Canadian dollar during
2007.





Benchmark
natural gas prices for 2008 on the NYMEX increased to an average of US$8.93 per
mmbtu from US$6.92 per mmbtu in 2007.  In Canada, AECO pricing was
significantly higher than 2007 levels, averaging $7.71 per GJ during 2008
compared to $6.55 during 2007.





2007
compared to 2006


Benchmark
oil prices for 2007 increased 9% to an average of US$72.34 per bbl WTI from
US$66.22 per bbl WTI in 2006.  The effect of the increase was off-set
by a 6% year over year weakening of the U.S. dollar against the Canadian dollar,
with the exchange rate rising to an average of US$0.93 per Canadian dollar in
2007 from an average of US$0.88 in 2006.





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




Average Commodity Prices
      Received2008
                  
                  
                  2007
                  
                  
                  2006Oil
      (1)
      (Cdn$ per bbl)
                  
                  
                  91.55
                  
                  
                  
                  61.84
                  
                  
                  
                  62.54Natural
      gas (Cdn$ per mcf)
                  
                  
                  8.94
                  
                  
                  
                  6.60
                  
                  
                  
                  6.70Oil
      commodity contract settlements (Cdn$ per bbl)
                  
                  
                  0.50
                  
                  
                  
                  (0.75
                  )
                  
                  
                  (0.41
                  )Natural
      gas commodity contract settlements  (Cdn$ per
    mcf)
                  
                  
                  0.04
                  
                  
                  
                  0.44
                  
                  
                  
                  0.83Combined
      oil (1)
      (Cdn$ per bbl)
                  
                  
                  92.05
                  
                  
                  
                  61.09
                  
                  
                  
                  62.13Combined
      natural gas (Cdn$ per mcf)
                  
                  
                  8.98
                  
                  
                  
                  7.04
                  
                  
                  
                  7.53Total
      (2)
      (Cdn$ per boe)
                  
                  
                  67.83
                  
                  
                  
                  49.34
                  
                  
                  
                  51.82


(1)
            Includes
      NGL and sulphur revenue.


(2)
            Price
      received excludes unrealized mark-to-market gain or
  loss.





2008
compared to 2007


The 2008
average price received for oil by Enterra, net of commodity contract settlements
increased 51% to $92.05 per bbl from $61.09 per bbl in 2007.  The 2008
average price received for natural gas, net of commodity contract settlements,
was up 28% to $8.98 per mcf from $7.04 per mcf in 2007.





2007
compared to 2006


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




REVENUES




Revenues(in thousands
      of Canadian dollars except for percentages)2008
                
                
                2007
                
                
                2006Oil
      and NGL
                
                
                126,557
                
                
                
                104,753
                
                
                
                114,669Natural
      gas
                
                
                128,711
                
                
                
                119,075
                
                
                
                119,111Revenue
      before mark-to-market adjustments (1)
                
                
                255,268
                
                
                
                223,828
                
                
                
                233,780Unrealized
      mark-to-market gain (loss) on commodity contracts
                
                
                20,229
                
                
                
                (16,792
                )
                
                
                10,628Oil
      and natural gas revenues
                
                
                275,497
                
                
                
                207,036
                
                
                
                244,408


(1)           
Non–GAAP measure.





2008
compared to 2007


Natural
gas revenue for 2008 increased 8% from 2007 to $128.7 million which was the
result of a 35% increase in the sales price of natural gas received for 2008
offset by production volumes for 2008 decreasing by 16%.  For oil and
NGL, the 21% revenue increase from 2007 to $126.6 million was the result of the
increase in oil price received of 48% which was offset by a 20% decrease in
production volumes from 2007.  The increase in revenue was
significantly higher than expected due to the unrealized mark-to-market gain on
commodity contracts of $20.2 million





Enterra Energy Trust Form 20 –
F





during
2008.  Unrealized mark-to-market on commodity contracts increased to
$20.2 million for the year compared to a loss of $16.8 million in the prior
year.





2007
compared to 2006


Natural
gas revenue for 2007 was consistent with 2006 at $119.1
million.  Natural gas production volumes for 2007 increased by 1%;
however this was offset by a 7% decrease in the sales price of natural gas
received for 2007.  For oil and NGL, the 9% revenue decrease from 2006
was consistent with an 8% decrease in production volumes from 2006, while the
oil price received decreased slightly.  Overall, in 2007 revenues
decreased by $37.4 million or 15% compared to 2006 with much of the decrease
attributable to rising oil prices that resulted in an unrealized mark-to-market
loss of $16.8 million at year-end compared to a mark-to-market gain at the end
of 2006 of $10.6 million.




COMMODITY
CONTRACTS




The Trust
has a formal risk management policy which permits management to use specified
price risk management strategies for up to 50% of its projected gross crude oil,
natural gas and NGL production including fixed price contracts, costless collars
and the purchase of floor price options and other derivative instruments to
reduce the impact of price volatility and ensure minimum prices for a maximum of
24 months beyond the current date.  The program is designed to provide
price protection on a portion of the Trust’s future production in the event of
adverse commodity price movement, while retaining significant exposure to upside
price movements.  By doing this the Trust seeks to provide a measure
of stability and predictability of cash inflows.





Enterra
has recently been focusing its price risk management on purchasing floor price
options to better maximize its exposure to upside price movements while trying
to ensure sufficient cash flow to achieve its budgeted plans.  As of
December 31, 2008, less than one quarter of the oil and gas production of
Enterra is economically hedged with commodity contracts that limit the maximum
price for these commodities.  For the winter heating season beginning
November 1, 2008 and ending March 31, 2009, only commodity floor price contracts
will remain on a portion of Enterra gas production.





The
mark-to-market value of the commodity contracts is determined based on the
quoted market price as at December 31 that was obtained from the counterparty to
the economic hedge.  Enterra then evaluates the reasonability of this
price in comparison to the value of other commodity contracts it currently owns
as well as recently quoted prices received from other counterparties for various
commodity contracts.  The Trust deals with several counterparties to
diversify the risks associated with having all commodity contracts with only one
counterparty.  The credit worthiness of each counterparty is assessed
at the time of purchase of each financial instrument and is regularly assessed
based on any new information regarding the counterparty.  The current
commodity contracts held by Enterra all mature during 2009 and based on
Enterra’s assessment the counterparties are believed to be
creditworthy.





At
December 31, 2008, the following financial derivatives and fixed price contracts
were outstanding:





Derivative
      Instrument
                Commodity
                Price
                Volume
      (per day)
                PeriodFloor
                Gas
                8.00
      ($/GJ)
                3,000
      GJ
                November
      1, 2008 – March 31, 2009Floor
                Gas
                9.00
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Gas
                9.50
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Gas
                10.00
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Oil
                72.00
      (US$/bbl)
                1,000
      bbl
                January
      1, 2009 – December 31, 2009Sold
      Call
                Oil
                91.50
      (US$/bbl)
                500
      bbl
                July
      1, 2009 – December 31,
2009








Enterra
had the following physical contracts outstanding as at December 31,
2008:





Fixed
      purchase
            Power
              (Alberta)
            62.90
              (Cdn$/Mwh)
            72
      Mwh
            July
      1, 2007 – December 31, 2009








Enterra Energy Trust Form 20 –
F





As at
December 31, 2008 the above commodity contracts had a net mark-to-market asset
position of $14.3 million which is a difference of $15.6 million from the Q3
2008 net liability of $1.3 million.  This change relates primarily to
the significant drop in oil prices which decreased from the US$100.00 range at
the end of Q3 2008 to the US$44.00 range at the end of 2008 and does not
necessarily reflect the expected future cash settlement value of these
contracts.





Since
December 31, 2008, the following financial derivatives and fixed price contracts
were entered into:





Derivative
      Instrument
                Commodity
                Price
                Volume
      (per day)
                PeriodFixed
                Gas
                5.01
      (US$/mmbtu)
                3,000
      mmbtu
                April
      1, 2009 – October 31, 2009Fixed
                Gas
                5.015
      ($/GJ)
                2,000
      GJ
                April
      1, 2009 – October 31, 2009Fixed
      Basis Differential (1)
                Gas
                Differential
      Fixed @ $1.08 US$/mmbtu
                3,000
      mmbtu
                April
      1, 2009 – October 31, 2009Fixed
      Basis Differential (1)
                Gas
                Differential
      Fixed @ $1.10 US$/mmbtu
                3,000
      mmbtu
                April
      1, 2009 – December 31, 2009Fixed
                Gas
                4.50
      ($/GJ)
                2,000
      GJ
                April
      1, 2009 – December 31, 2009Fixed
                Gas
                4.6725
      (US$/mmbtu)
                3,000
      mmbtu
                April
      1, 2009 – December 31, 2009Fixed
                Gas
                6.25
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2009 – December 31, 2010Fixed
      Basis Differential (1)
                Gas
                Differential
      Fixed @ $0.615 US$/mmbtu
                5,000
      mmbtu
                November
      1, 2009 – December 31, 2010Fixed
                Oil
                50.00
      (US$/bbl)
                250
      bbl
                April
      1, 2009 –June
      30, 2009Fixed
                Oil
                50.35
      (US$/bbl)
                200
      bbl
                July
      1, 2009 – September 30, 2009Fixed
                Oil
                65.00
      ($/bbl)
                300
      bbl
                July
      1, 2009 – September 30, 2009Fixed
                Oil
                85.00
      ($/bbl)
                500
      bbl
                October
      1, 2009 – December 31,
2010


(1)
            NYMEX
      / Southern Star (Oklahoma) 2009 basis
  differential.




ROYALTIES




Royalties
include crown, freehold and overriding royalties, production taxes and wellhead
taxes.  Royalties vary depending on the jurisdiction, volumes that are
produced, total volumes sold and the price received for the sales.





Royalties(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)2008
                
                
                2007
                
                
                2006Royalties
                
                
                58,350
                
                
                
                45,365
                
                
                
                48,288As
      a percentage of revenues
                
                
                23
                %
                
                
                20
                %
                
                
                21
                %Royalties
      per boe ($)
                
                
                15.50
                
                
                
                10.00
                
                
                
                10.71





In late
October 2007, the Alberta provincial government announced a new oil and gas
royalty regime to take effect January 1, 2009.  The Trust has assessed
the impact of the new royalty regime and has determined that it will have a
modest negative effect on its current portfolio of production and reserves in
Alberta.  Enterra now incorporates the new royalty scheme into its
Alberta-based economic analysis prior to pursuing opportunities in the
province.  During 2008, approximately 31% of the Trust’s production
came from Alberta.





2008
compared to 2007


Royalties
in 2008 increased 29% to $58.4 million from $45.4 million in 2007 primarily as a
result of the higher prices received for oil and natural gas during the course
of 2008.  As a percentage of revenue before mark-to-market
adjustments, royalties were 23% for 2008 and 20% for 2007.








Enterra Energy Trust Form 20 –
F


2007
compared to 2006





Royalties
in 2007 decreased compared to 2006 as a result of royalty rebates realized in
the U.S. The U.S. operations applied for, and received, a royalty
rebate for its horizontal wells in the state of Oklahoma.  Enterra
realized rebates of $3.2 million in 2007 for royalties paid in 2006 and
2007.




PRODUCTION
EXPENSE




Production Expense(in thousands
      Canadian dollars except for percentages and per boe
      amounts)2008
                
                
                2007
                
                
                2006Production
      expense
                
                
                55,846
                
                
                
                62,483
                
                
                
                48,494Non-cash
      gain (loss) from power contracts
                
                
                (157
                )
                
                
                (447
                )
                
                
                -Cash
      production costs
                
                
                55,689
                
                
                
                62,036
                
                
                
                48,494Production
      expense per boe ($)
                
                
                14.84
                
                
                
                13.77
                
                
                
                10.76Non-cash
      gain (loss) from power contracts per boe ($)
                
                
                (0.04
                )
                
                
                0.10
                
                
                
                -Cash
      production costs per boe ($)
                
                
                14.80
                
                
                
                13.67
                
                
                
                10.76





2008
compared to 2007


In 2008,
cash production costs increased 8% to $14.80 per boe compared to $13.67 per boe
in 2007 primarily due to properties with low operating costs being sold in the
first half of 2008 and to operating expenses increasing during 2008 throughout
the industry as a whole.  Production costs for 2008 were also slightly
higher due to additional maintenance and well workovers.  With high
commodity prices during the summer, additional work was performed to bring on
more production which resulted in higher operating costs but the associated
production did generate positive cash flow.





2007
compared to 2006


In 2007,
cash production costs increased 28% to $13.67 per boe compared to $10.76 per boe
in 2006 primarily due to Canadian operations experiencing one time non-recurring
expenses related to regulatory compliance, increased well workover costs, and
repair and environmental expenses associated with three pipeline failures in
Canada.  Severe weather conditions increased costs and reduced
production in Oklahoma as record spring and summer rain, were followed by a
destructive ice storm in December.




TRANSPORTATION
EXPENSE




Transportation
expense is a function of the point of legal transfer of the product and is
dependent upon where the product is sold, production split, location of
properties as well as industry transportation rates that are driven by supply
and demand of available transport capacity.





Transportation
      Expense(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)2008
                
                
                2007
                
                
                2006Transportation
      expense
                
                
                2,492
                
                
                
                2,340
                
                
                
                1,867Transportation
      expense per boe ($)
                
                
                0.66
                
                
                
                0.52
                
                
                
                0.41





2008
compared to 2007


On a year
to date basis, transportation costs increased 27% to $0.66 per boe for the year
ended December 31, 2008 compared to $0.52 per boe for the same period in
2007.  Transportation expense increased 6% primarily due to the
overall increase in costs in the industry.  As well, the per boe
equivalent cost have increased due in part to the sale of certain lower
operating cost properties in Q1 2008 as part of the asset disposition
program.





2007
compared to 2006


On a year
to date basis, transportation costs increased 27% to $0.52 per boe for the year
ended December 31, 2007 compared to $0.41 per boe for the same period in
2006.  Transportation expense increased 25% primarily due to the
overall increase in costs in the industry.




GENERAL AND ADMINISTRATIVE
EXPENSE




General and Administrative
      Expense(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)2008
                
                
                2007
                
                
                2006G&A
      expense
                
                
                15,858
                
                
                
                20,414
                
                
                
                17,145G&A
      expense per boe ($)
                
                
                4.21
                
                
                
                4.50
                
                
                
                3.80










Enterra Energy Trust Form 20 –
F





2008
compared to 2007


General
and administrative expense (“G&A”) decreased by 22% in 2008 compared to 2007
on a total dollar basis but stayed relatively flat on a per boe basis due to
lower production volumes, as a result of the asset sales in Q1 and Q2 2008, when
compared to 2007.  For 2008, G&A costs were $4.21 per boe compared
to $4.50 per boe for 2007, a 6% decrease primarily due to implementing cost
reduction plans.




2007
compared to 2006


General
and administrative expenses increased 19% in 2007 to $20.4 million from $17.1
million in 2006.  G&A per boe increased by 18% to $4.50 per boe in
2007 compared to $3.80 per boe in 2006.  The increase in general and
administrative costs related primarily to an increase in personnel in 2007 from
2006 and increased consulting costs in Q3 and Q4 2007 related to the turnover of
management and employees.






PROVISION FOR
NON-RECOVERABLE RECEIVABLES




The
provision for non-recoverable receivables was $8.5 million for 2008 as compared
to $nil at December 31, 2007 and 2006.  On July 22, 2008, SemGroup, a
midstream and marketing company through which the Trust marketed a portion of
the Trust’s production, filed a voluntary petition for reorganization under
Chapter 11 of the Bankruptcy Code in the U.S. and the Canadian units of
SemGroup filed for protection under the Companies’ Creditors Arrangement
Act.  As a result, the Trust has recorded a provision for
non-recoverable receivables for the full amount owed by SemGroup a one time
charge of $8.5 million with a corresponding decrease to net income ($6.0 million
net of tax).  Management believes that a portion of the $8.5 million
is recoverable; however, it is indeterminable at this time, therefore, an
allowance has been recorded for the amount.




INTEREST
EXPENSE




Interest
expense for 2008 was $17.5 million which was comprised of interest on bank
indebtedness of $8.4 million and interest on convertible debentures of $11.5
million less interest income of $2.4 million.





Interest Expense(in thousands
      of Canadian except for percentages and per boe
    amounts)2008
                
                
                2007
                
                
                2006Cash
      interest expense on bank indebtedness, capital lease, and note
      payable
                
                
                7,814
                
                
                
                12,120
                
                
                
                14,185Cash
      interest expense on convertible debentures
                
                
                9,726
                
                
                
                8,625
                
                
                
                786Cash
      interest income
                
                
                (2,350
                )
                
                
                (489
                )
                
                
                -Subtotal
      cash interest expense
                
                
                15,190
                
                
                
                20,256
                
                
                
                14,971Non-cash
      interest expense on bank indebtedness, capital lease, and note
      payable
                
                
                548
                
                
                
                988
                
                
                
                11,713Non-cash
      interest expense on convertible debentures
                
                
                1,728
                
                
                
                1,338
                
                
                
                33Total
      interest expense
                
                
                17,466
                
                
                
                22,582
                
                
                
                26,717Cash
      interest expense per boe on bank indebtedness, capital lease, and note
      payable ($)
                
                
                2.08
                
                
                
                2.67
                
                
                
                3.15Cash
      interest expense per boe on convertible debentures ($)
                
                
                2.58
                
                
                
                1.90
                
                
                
                0.17Cash
      interest income per boe ($)
                
                
                (0.62
                )
                
                
                (0.11
                )
                
                
                -Total
      cash interest expense per boe ($)
                
                
                4.04
                
                
                
                4.46
                
                
                
                3.32





2008
compared to 2007


Interest
expense during 2008 on bank indebtedness decreased to $8.4 million compared to
$13.1 million in 2007 due to lower debt levels, declining Bank of Canada
interest rates and lower interest rates that were negotiated under the June 25,
2008 revised credit facility agreement.  Enterra ended 2008
with a bank indebtedness balance of $95.5 million compared to $172.0
million at the start of 2008.





The
interest expense on convertible debentures for 2008 increased to $11.5 million
compared to $10.0 million in 2007.  This increase of 15% is due to the
8.25% convertible debentures issued on April 28, 2007 of $40.0 million being
outstanding for the entire year of 2008 compared to only part of
2007.





2007
compared to 2006


Interest
expense during 2007 on bank indebtedness decreased to $13.1 million compared to
$25.9 million in 2006 due to lower debt levels and lower interest
rates.  Enterra ended 2007 with a bank indebtedness balance of $172.0
million compared to $188.2 million at the start of 2007.





Enterra Energy Trust Form 20 –
F





The
interest expense on convertible debentures for 2007 increased to $10.0 million
compared to $0.8 million in 2006.  This increase is due to the 8.25%
convertible debentures issued on April 28, 2007 of $40.0 million and the 8.00%
convertible debentures issued on November 21, 2006 of $138.0
million.




UNIT-BASED COMPENSATION
EXPENSE




Unit-Based Compensation
      Expense(in thousands
      Canadian dollars except for percentages and per boe
      amounts)2008
                
                
                2007
                
                
                2006Gross
      unit-based compensation expense
                
                
                4,819
                
                
                
                4,128
                
                
                
                3,229Capitalized
                
                
                (404
                )
                
                
                -
                
                
                
                -Unit-based
      compensation expense
                
                
                4,415
                
                
                
                4,128
                
                
                
                3,229Unit-based
      compensation expense per boe ($)
                
                
                1.17
                
                
                
                0.91
                
                
                
                0.72





2008
compared to 2007


Non-cash
unit-based compensation expense for 2008 was $4.4 million compared to $4.1
million in 2007 due to an increase in restricted units and trust unit options
issued.





2007
compared to 2006


Non-cash
unit-based compensation expense for 2007 was $4.1 million compared to $3.2
million in 2006 due to an increase in restricted units and trust unit options
issued.




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




Depletion, Depreciation and
      Accretion(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)2008
                
                
                2007
                
                
                2006DD&A
      – excluding impairment
                
                
                99,377
                
                
                
                124,447
                
                
                
                135,429Impairment
      expense
                
                
                -
                
                
                
                26,254
                
                
                
                66,019DD&A
                
                
                99,377
                
                
                
                150,701
                
                
                
                201,448DD&A
      per boe – excluding impairment ($)
                
                
                26.40
                
                
                
                27.43
                
                
                
                30.04Impairment
      expense per boe ($)
                
                
                -
                
                
                
                5.79
                
                
                
                14.64DD&A
      per boe ($)
                
                
                26.40
                
                
                
                33.22
                
                
                
                44.68





2008
compared to 2007


DD&A
expenses excluding impairment decreased by 20% in 2008 to $99.4 million compared
to $124.4 million in 2007.  DD&A expenses excluding impairment on
a boe basis decreased by 4% from $27.43 per boe in 2007 to $26.40 in
2008.  The decrease year over year is caused by reduced property,
plant and equipment values primarily as a result of asset dispositions in the
first half of 2008.





2007
compared to 2008


DD&A
expenses excluding impairment decreased by 8% in 2007 to $124.4 million compared
to $135.4 million in 2006.  DD&A expenses excluding impairment on
a boe basis decreased by 9% from $30.04 per boe in 2006 to $27.43 in
2007.  The decrease year over year is caused by reduced property,
plant and equipment values primarily as a result of the impairment in 2006 and
2007.








Ceiling
Test




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





Enterra
completed ceiling test calculations for the Canadian and U.S. cost centers
as at December 31, 2008 to assess the recoverability of costs recorded in
respect of the petroleum and natural gas properties.  The ceiling test
did not result in a write down of the Canadian cost center or the U.S. cost
center.





Enterra Energy Trust Form 20 –
F





GOODWILL
IMPAIRMENT


2008
compared to 2007


A
goodwill impairment charge was not recorded in 2008 compared to a $76.5 million
charge in 2007.  During 2007 the balance of goodwill in the Canadian
reporting unit was considered impaired.  No goodwill remained at
December 31, 2008 and 2007.





2007
compared to 2006


A
goodwill impairment charge of $76.5 million was recorded in 2007 and no goodwill
impairment charge was recorded in 2006.  During 2007 the balance of
goodwill in the Canadian reporting unit was considered impaired.  No
goodwill remained at December 31, 2007 and there was a balance of $76.3 million
at December 31, 2006.




FOREIGN
EXCHANGE




2008
compared to 2007


Foreign
exchange for the year ended December 31, 2008 was a loss of $1.3 million
compared to a loss of $0.5 million in 2007.  The foreign exchange loss
for 2008 is comprised of a realized loss of $2.1 million as a result of the
application of the current rate method on the U.S. operations and a gain of $0.8
million as a result of the weakening of the Canadian dollar against the U.S.
dollar in the latter half of 2008.





2007
compared to 2006


Foreign
exchange for the year ended December 31, 2007 was a loss of $0.5 million
compared to a loss of $1.9 million in 2006.  The foreign exchange loss
for 2007 is comprised of a realized loss of $2.1 million as a result of the
application of the current rate method on the U.S. operations and a gain of $1.6
million as a result of selling of U.S. funds transferred from Enterra’s U.S.
subsidiary into Canadian dollars.





The
foreign exchange sensitivity in note 13 of the 2008 financial statements
indicates that for every $0.02 cent weakening of the Canadian dollar relative to
the U.S. dollar, the benefit to the Trust is $0.4 million in 2008 pre-tax
income; therefore, the weakening of the Canadian dollar relative to the U.S.
dollar has had a positive impact on the Trust.




TAXES




2008
compared to 2007


Future
income tax for the year ended December 31, 2008 was $4.5 million compared
to a future income tax reduction of $36.1 million in 2007.  The
federal and provincial statutory rate was 29.7% at December 31, 2008 compared to
an effective tax rate of 37.7% and a tax rate applied to temporary differences
of 25.0%.  The primary reason for the variance in the effective tax
rate and the statutory tax rate is the result of items not deductible for tax in
the U.S. operations in 2008 which should be deductible beginning in 2010 when
the withholding tax on U.S. source interest income will become zero, compared to
the current 5% rate, the non-deductible stock base compensation, and the
difference between the U.S. and Canadian tax rates.





2007
compared to 2006


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





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





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





Enterra Energy Trust Form 20 –
F





federal
and provincial corporate tax rate.  These distributions will be
treated as dividends to the trust unitholders.  The Trust constitutes
a SIFT and as a result, the Trust and its unitholders will be subject to Bill
C-52.





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





Commencing
January 1, 2011, the Trust will not be able to deduct certain of its distributed
income.  The Trust will become subject to a distribution tax ranging
from 25 to 28 percent but this tax will not apply to returns of
capital.  Enterra will consider the options and alternative structures
with legal and business advisors to determine if any potential restructuring
available to maximize value is in the best interest of unitholders.





The
federal component of the proposed tax on SIFT is expected to be 15 percent in
2012 (25 to 28 percent in total including provincial income taxes) and
thereafter.  The Trust is required to recognize, on a prospective
basis, future income taxes on temporary differences in the Trust.  In
2008, no reduction of the future income tax liability was recorded for temporary
differences (2007 – $9.9 million).  Subsequent to 2007, the Trust
suspended its distributions which caused these temporary differences to no
longer meet the criteria for future income tax asset
recognition.  Overall, there was no impact in 2008 due to the proposed
tax on SIFT.




NET INCOME
(LOSS)




2008
compared to 2007


Net
income in 2008 was $7.1 million ($0.11 per trust unit) compared to a loss of
$142.0 million (loss of $2.38 per trust unit) in 2007.  The net income
during the year is the result of increases in commodity prices in 2008, a
reduction in general and administrative expenses and no impairment charges on
goodwill or property, plant and equipment taken in 2008.  The net
income was partially offset by the $8.5 million charge relating to the provision
for non-recoverable receivables owed by SemGroup.





2007
compared to 2006


Net loss
in 2007 was $142.0 million (loss of $2.38 per trust unit) compared to a loss of
$64.2 million (loss of $1.46 per trust unit) in 2006.  The increase in
the net loss during the year is the result of a $76.5 million impairment charge
on goodwill taken in 2007.




NON-GAAP FINANCIAL
MEASURES




Management
uses certain key performance indicators (“KPIs”) and industry bench marks such
as cash flow netback, funds from operations, revenue before mark-to-market
adjustment, working capital, net debt, operating netbacks and operating recycle
ratio to analyze financial performance.  Management feels that these
KPIs and benchmarks are key measures of profitability and overall sustainability
for the Trust.  These KPIs and benchmarks as presented do not have any
standardized meanings prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures presented by other
entities.  All of the measures have been calculated on a basis that is
consistent with previous disclosures.





Cash Flow
Netback





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





Cash Flow Netback(in thousand
      of Canadian dollars, except for per unit and per boe
      amounts)2008
                
                
                2007
                
                
                2006Net
      income (loss)
                
                
                7,061
                
                
                
                (142,036
                )
                
                
                (64,239
                )Future
      income taxes
                
                
                4,487
                
                
                
                (36,051
                )
                
                
                (58,899
                )Foreign
      exchange loss (gain)
                
                
                1,279
                
                
                
                951
                
                
                
                1,038Depletion,
      depreciation and accretion
                
                
                99,377
                
                
                
                150,701
                
                
                
                201,448Goodwill
      impairment
                
                
                -
                
                
                
                76,463
                
                
                
                -Non-cash
      interest expense
                
                
                2,276
                
                
                
                2,327
                
                
                
                11,746Financing
      fees
                
                
                -
                
                
                
                -
                
                
                
                5,065Amortization
      of marketing contract
                
                
                -
                
                
                
                -
                
                
                
                (1,447
                )Non-controlling
      interest
                
                
                -
                
                
                
                -
                
                
                
                (36
                )Loss
      on sale of assets
                
                
                -
                
                
                
                -
                
                
                
                59Unit
      based compensation expense
                
                
                4,415
                
                
                
                4,128
                
                
                
                3,229Unrealized
      mark-to-market (gain) loss on commodity contracts
                
                
                (20,072
                )
                
                
                16,205
                
                
                
                (10,628
                )Provision
      for non-recoverable receivables
                
                
                8,522
                
                
                
                -
                
                
                
                -Funds
      from operations
                
                
                107,345
                
                
                
                72,688
                
                
                
                87,336Total
      volume (mboe)
                
                
                3,764
                
                
                
                4,536
                
                
                
                4,508Cash
      flow netback per boe (non-GAAP) ($)
                
                
                28.52
                
                
                
                16.02
                
                
                
                19.37





Funds from
Operations




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





Funds from
      Operations(in thousands
      of Canadian dollars)2008
                
                
                2007
                
                
                2006Cash
      provided by operating activities
                
                
                91,560
                
                
                
                76,844
                
                
                
                64,485Changes
      in non-cash working capital items
                
                
                5,492
                
                
                
                (6,381
                )
                
                
                21,632Asset
      retirement costs incurred
                
                
                1,771
                
                
                
                2,225
                
                
                
                1,219Provision
      for non-recoverable receivables
                
                
                8,522
                
                
                
                -
                
                
                
                -Funds
      from operations
                
                
                107,345
                
                
                
                72,688
                
                
                
                87,336







2008
compared to 2007


In 2008,
funds from operations increased by 48% over 2007.  The increase in
funds from operations is primarily the result of higher commodity prices
realized.





2007
compared to 2006


In 2007,
funds from operations decreased by 17% from 2006.  The decrease in
funds from operations is primarily the result of lower commodity prices
realized, an increase in operating expenses and higher general and
administrative expenses.  These decreases were partially offset by
lower interest expenses.




CAPITAL
EXPENDITURES




The
following table represents the capital expenditures that were paid for with
cash.




Capital
      Expenditures(in thousands
      of Canadian dollars except for percentages)2008
                
                
                2007
                
                
                2006Capital
      expenditures
                
                
                32,891
                
                
                
                88,323
                
                
                
                30,918Capital
      expenditures to be recovered (1)
                
                
                19,976
                
                
                
                6,724
                
                
                
                -Amounts
      recovered under agreement
                
                
                (5,049
                )
                
                
                (1,105
                )
                
                
                -Total
                
                
                47,818
                
                
                
                93,942
                
                
                
                30,918


(1)
            Recovered
      under capital recovery agreement over 36 months after project
      completion.




During
the year ended December 31, 2008 in Canada, Enterra spent $21.3 million in
capital expenditures.  The major components of these expenditures
include: $11.8 million for wells drilled or currently being drilled, $2.1
million on well optimization and activation projects, $2.0 million on land and
seismic acquisition, $1.0 million on the acquisition of gross overriding royalty
rights in northeastern British Columbia, $2.2 million related to well, facility
and other equipment maintenance and $2.2 million related to the capitalization
of certain G&A costs identified as attributable to exploration and
development activities.




During
the year ended December 31, 2008 in the U.S., a total of $31.6 million was spent
on capital expenditures.  Enterra is involved in a farmout and capital
recovery agreement whereby the Trust recovers infrastructure costs incurred from
a joint venture partner.  Infrastructure costs incurred in the U.S.
under the capital recovery agreement were $20.0 million during
2008.  These costs were billed to the joint venture partner as the
projects had reached the necessary stage of completion and became recoverable
over a three-year period as specified in the agreement.







Enterra Energy Trust Form 20 –
F





Interest
is charged on the outstanding balance at 12% per annum.  Enterra
received a total of $5.0 million of principal repayments and $1.7 million in
interest from this capital recovery agreement during 2008.




The
capital expenditures in the U.S. that Enterra is solely responsible for totalled
$11.6 million, of which $10.8 million was spent on acquisitions of land for
future development in Oklahoma.  In addition, $0.8 million was
incurred for other equipment.




The
remaining costs incurred include $14.9 million for related infrastructure which
will be billed to the joint venture partner under the terms of the agreement
once the projects reach a certain stage of completion.




Enterra
closed the dispositions of $39.6 million of non-core assets during 2008 with the
net proceeds used to reduce debt.




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




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




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




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




Capital
additions for the year ended December 31, 2006 were $420.0
million.  In addition to the acquisition of the Oklahoma Assets of
$353.0 million (of which $8.9 million was unpaid at December 31, 2006), the
assets acquired through the JED swap, including post closing adjustments, of
$32.4 million, property, plant and equipment additions of $30.9 million, $3.3
million of net asset retirement obligations and $0.4 million related to minority
interest accounting as per EIC-151 were charged to property, plant and
equipment.  Total dispositions for the year ended December 31, 2006
were $50.8 million.




In 2006
in Canada, the Trust spent $15.5 million in capital expenditures; $4.5 million
related to drilling and completions operations, $4.4 million for the
construction of facilities and pipelines, $2.3 million for other plant and
equipment and $1.6 million for the completion equipping and tie-in of the deep
gas well at Ricinus.




In
Oklahoma in 2006, the Trust initiated an aggressive land acquisition program.
During the year approximately US$4.5 million was spent to acquire lands for
future development. In addition, during Q4 2006 the Trust drilled two salt water
disposal wells at a total cost of approximately US$4.8 million. On occasion and
as required, the Trust will drill further water disposal wells and make
additions to existing facilities to support the dewatering efforts of the new
wells being drilled under the farmout. During 2006 the trust also spent
approximately US$1.5 million for infrastructure additions to support the
locations being drilled. The capital cost of the disposal wells and
infrastructure additions is recovered by the Trust over a 3 year period once the
partner begins to fully utilize the facilities.




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






B.  Liquidity
and Capital Resources




Enterra’s
Liquidity




As an oil
and gas producer Enterra has a declining asset base and therefore relies on
ongoing development activities and acquisitions to replace production and add
additional reserves.  The Trust’s future oil and natural gas
production is highly dependent on Enterra’s success in exploiting its asset base
and acquiring or developing additional reserves.







Enterra Energy Trust Form 20 –
F







Development
activities and acquisitions may be funded internally through cash flow or
through external sources such as debt or the issuance of equity.  To
the extent that cash flow is used to finance these activities, the cash
available to distribute to unit holders is affected.  Enterra’s U.S.
subsidiary is not restricted from transferring cash to the parent
company.  The Trust finances its operations and capital activities
primarily with funds generated from operating activities, but also through the
issuance of trust units, debentures and borrowing from its credit
facility.  The amount of equity Enterra raises through the issuance of
trust units depends on many factors including projected cash needs, availability
of funding through other sources, unit price and the state of the capital
markets.  The Trust believes its sources of cash, including bank debt,
will be sufficient to fund its operations and anticipated capital expenditure
program in 2009.  Enterra’s ability to fund its operations will also
depend on operating performance and is subject to commodity prices and other
economic conditions which may be beyond its control.  The Trust will
monitor commodity prices and adjust the 2009 capital expenditure program
accordingly to stay within its means.  Should external sources of
capital become limited or unavailable, the Trust’s ability to make the necessary
development expenditures and acquisitions to maintain or expand Enterra’s asset
base may be impaired.




Enterra’s
improved cash position and available credit facility has put the Trust in
reasonably good shape to deal with the current economic uncertainties and
management is confident in its ability to manage through this
cycle.




Enterra’s
capital structure at December 31, 2008 is follows:




December
      31, 2008
                      
                      
                      December
      31, 2007Capitalization(in thousand
      of Canadian dollars except percentages)
                      
                      Amount
                      
                      
                      %
                      
                      
                      Amount
                      
                      
                      %DebtBank
      indebtedness
                      
                      
                      95,466
                      
                      
                      
                      47
                      %
                      
                      
                      171,953
                      
                      
                      
                      49
                      %Working
      capital(1)
                      
                      
                      (23,767
                      )
                      
                      
                      (12
                      %)
                      
                      
                      269
                      
                      
                      
                      0
                      %Long-term
      receivable
                      
                      
                      (19,310
                      )
                      
                      
                      (9
                      %)
                      
                      
                      (4,003
                      )
                      
                      
                      (1
                      %)Net
      debt
                      
                      
                      52,389
                      
                      
                      
                      26
                      %
                      
                      
                      168,219
                      
                      
                      
                      48
                      %Convertible
      debentures
                      
                      
                      113,420
                      
                      
                      
                      56
                      %
                      
                      
                      111,692
                      
                      
                      
                      32
                      %Trust
      units issued, at market
                      
                      
                      38,341
                      
                      
                      
                      18
                      %
                      
                      
                      68,517
                      
                      
                      
                      20
                      %Total
      capitalization
                      
                      
                      204,150
                      
                      
                      
                      100
                      %
                      
                      
                      348,428
                      
                      
                      
                      100
                      %


(1)
            Working
      capital excludes commodity contracts and future income
    taxes.




Bank
Indebtedness




At
December 31, 2008, the Trust’s bank indebtedness was $95.5 million a decrease of
$76.5 million from the $172.0 million at December 31, 2007.  The Trust
has credit facilities with its banking syndicate that includes revolving and
operating credit facilities which have a current borrowing capacity of $110.0
million




Enterra
monitors capital using an interest coverage ratio that has been externally
imposed as part of the credit agreement.  Enterra is required to
maintain an interest coverage ratio greater than 3.00 to 1.00; this ratio is
calculated as follows:





As
      at December 31(in
      thousands of Canadian dollars except for ratios)
                
                2008
                
                
                2007Interest
      coverage (1):Cash
      flow over the prior four quarters
                
                
                116,911
                
                
                
                94,015Interest
      expenses over the prior four quarters
                
                
                18,088
                
                
                
                21,732Interest
      coverage ratio
                
                6.46
      : 1.00
                
                
                4.33
      : 1.00


(1)      Note
these amounts are defined terms within the credit agreements.









Working
Capital




The
working capital deficiency has decreased from the prior year due to Enterra’s
focus on debt reduction during 2008.  In addition to the impact of
high commodity prices, Enterra’s reduction in expenditures during the fourth
quarter of 2008 has decreased the working capital deficiency from December 31,
2007.




Enterra’s
working capital excluding bank indebtedness increased by $24.0 million due to an
increase in cash of $10.1 million and an increase in accounts receivable of
$15.7 million; these increases were slightly offset by an increase in accounts
payable of $2.2 million.  The increase in accounts receivables is due
to an increase in the current receivable from a joint venture partner under the
terms of a capital recovery agreement.







Enterra Energy Trust Form 20 –
F





Enterra
believes that its working capital is sufficient to fund its operations and the
anticipated capital expenditure program in 2009.




As
      at December 31Working Capital(in thousands of Canadian
      dollars)
                
                2008
                
                
                2007Working
      capital (deficiency)(1)
                
                
                (71,699
                )
                
                
                (172,212
                )Working
      capital (deficiency)(1)
      excluding bank indebtedness
                
                
                23,767
                
                
                
                (259
                )


(1)
            Working
      capital excludes commodity contracts and future income
    taxes.







Long-term
Receivable




During
2006 Enterra entered into a farmout agreement with Petroflow Energy Ltd. (“JV
Partner”), a public oil and gas company, to fund 100% of the drilling and
completion costs of the undeveloped lands in Oklahoma.  Under this
farmout agreement, Enterra pays the cost to acquire the land and the JV
Partner pays 100% of the drilling costs for producing
wells.  This resource play requires water to be pumped from the
producing formation to allow the oil and gas to flow, so Enterra pays the
initial costs of drilling saltwater disposal wells and related
infrastructure but it recovers all of these costs from the JV
Partner.  This arrangement allows Enterra to add reserve barrels at
finding and developing costs of less than $6.00 per boe which is very low
in comparison to the industry averages.  The long-term receivables are
for these infrastructure costs incurred by Enterra that are to be repaid by the
JV Partner over a three-year period and are subject to interest of 12.0% per
annum.  Based on current borrowing costs, Enterra is earning about a
7.5% interest premium in the interest that it is receiving from the JV
Partner compared to Enterra's costs of borrowing.  During 2008, $1.7
million of interest income was earned on the long-term receivables from JV
Partner.  In 2008, $5.0 million of principal payments have been
received.  The balance at year ended December 31, 2008 is $27.9
million (US$22.9 million) of which $8.6 million (US$7.0 million) is due within
one year and has been included in accounts receivable.




Convertible
Debentures




As at
December 31, 2008, Enterra had $113.4 million of convertible debentures
outstanding with a face value of $120.3 million.  The debentures have
the following conversion prices:




·
            ENT.DB
      – $9.25.  Each $1,000 principal amount of ENT.DB debentures is
      convertible into approximately 108.108 Enterra trust
      units.  Mature on December 31,
2011.


·
            ENT.DB.A
      - $6.80.  Each $1,000 principal amount of ENT.DB.A debentures is
      convertible into approximately 147.059 Enterra trust
      units.  Mature on June 30,
2012.







As at
December 31, 2008, Enterra has issued capital of 62.2 million trust units
outstanding.  If all the outstanding convertible debentures were
converted into units, a total of 76.8 million trust units would be
outstanding.




Management
believes that funds from operations are sufficient to meet its 2009 capital
expenditure program and make interest payments on all debt.  Although
management’s objective is to further reduce debt, the Trust does have unused
credit facilities available should an appropriate opportunity present
itself.






Financial
Instruments




The Trust
has a formal risk management policy which permits management to use specified
price risk management strategies for up to 50% of its projected gross crude oil,
natural gas and NGL production including fixed price contracts, costless collars
and the purchase of floor price options and other derivative instruments to
reduce the impact of price volatility and ensure minimum prices for a maximum of
24 months beyond the current date.  The program is designed to provide
price protection on a portion of the Trust’s future production in the event of
adverse commodity price movement, while retaining significant exposure to upside
price movements.  By doing this the Trust seeks to provide a measure
of stability and predictability of cash inflows.





Enterra
has recently been focusing its price risk management on purchasing floor price
options to better maximize its exposure to upside price movements while trying
to ensure sufficient cash flow to achieve its budgeted plans.  As of
December 31, 2008, less than one quarter of the oil and gas production of
Enterra is economically hedged with commodity contracts that limit the maximum
price for these commodities.  For the winter heating season beginning
November 1, 2008 and ending March 31, 2009, only commodity floor price contracts
will remain on a portion of Enterra gas production.





At
December 31, 2008, the following financial derivatives and fixed price contracts
were outstanding:





Derivative
      Instrument
                Commodity
                Price
                Volume
      (per day)
                PeriodFloor
                Gas
                8.00
      ($/GJ)
                3,000
      GJ
                November
      1, 2008 – March 31, 2009Floor
                Gas
                9.00
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Gas
                9.50
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Gas
                10.00
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Oil
                72.00
      (US$/bbl)
                1,000
      bbl
                January
      1, 2009 – December 31, 2009Sold
      Call
                Oil
                91.50
      (US$/bbl)
                500
      bbl
                July
      1, 2009 – December 31,
2009





Enterra
had the following physical contracts outstanding as at December 31,
2008:





Fixed
      purchase
            Power
              (Alberta)
            62.90
              (Cdn$/Mwh)
            72
      Mwh
            July
      1, 2007 – December 31, 2009





Since
December 31, 2008, the following financial derivatives and fixed price contracts
were entered into:





Derivative
      Instrument
                Commodity
                Price
                Volume
      (per day)
                PeriodFixed
                Gas
                5.01
      (US$/mmbtu)
                3,000
      mmbtu
                April
      1, 2009 – October 31, 2009Fixed
                Gas
                5.015
      ($/GJ)
                2,000
      GJ
                April
      1, 2009 – October 31, 2009Fixed
      Basis Differential (1)
                Gas
                Differential
      Fixed @ $1.08 US$/mmbtu
                3,000
      mmbtu
                April
      1, 2009 – October 31, 2009Fixed
      Basis Differential (1)
                Gas
                Differential
      Fixed @ $1.10 US$/mmbtu
                3,000
      mmbtu
                April
      1, 2009 – December 31, 2009Fixed
                Gas
                4.50
      ($/GJ)
                2,000
      GJ
                April
      1, 2009 – December 31, 2009Fixed
                Gas
                4.6725
      (US$/mmbtu)
                3,000
      mmbtu
                April
      1, 2009 – December 31, 2009Fixed
                Gas
                6.25
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2009 – December 31, 2010Fixed
      Basis Differential (1)
                Gas
                Differential
      Fixed @ $0.615 US$/mmbtu
                5,000
      mmbtu
                November
      1, 2009 – December 31, 2010Fixed
                Oil
                50.00
      (US$/bbl)
                250
      bbl
                April
      1, 2009 –June
      30, 2009Fixed
                Oil
                50.35
      (US$/bbl)
                200
      bbl
                July
      1, 2009 – September 30, 2009Fixed
                Oil
                65.00
      ($/bbl)
                300
      bbl
                July
      1, 2009 – September 30, 2009Fixed
                Oil
                85.00
      ($/bbl)
                500
      bbl
                October
      1, 2009 – December 31,
2010


(1)
            NYMEX
      / Southern Star (Oklahoma) 2009 basis
  differential.





Material
Commitments for Capital Expenditures




Currently,
Enterra does not have any material commitment for capital
expenditures.  As an oil and gas producer, Enterra has a declining
asset base and therefore relies on development activities and acquisitions to
replace production and add additional reserves.  The Trust’s future
oil and natural gas production is highly dependent on Enterra’s success in
exploiting its asset base and acquiring or developing additional
reserves.  Although the Trust has an internal inventory of drilling
opportunities it continues to exploit, Enterra will evaluate alternatives
external to this inventory but will also evaluate and act on accretive external
acquisition opportunities.  An expansion will be financed through cash
flow, debt financing, farm in agreements or other corporate
financings.









C.  Research
and Development, Patents and Licenses, etc.







Enterra Energy Trust Form 20 –
F












The Trust
has no material research and development programs, patents and licenses
etc.




D.  Trend
Information




Our
financial results have been principally affected by fluctuating crude oil and
natural gas prices and fluctuations in the Canadian to US dollar.




During
2008, the WTI oil price peaked above US$145.00 per barrel in July 2008 and has
since fallen as much as US$110.00 per barrel by December
2008.  Alberta natural gas settlement prices also increased in the
first half of 2008 to $10.60/mcf before decreasing to $5.85/mcf by September
2008.  During 2009, WTI crude oil prices have risen from the 2008 year
end price of US$44.60 per barrel to over US$68.00 per barrel in June
2009.




Oil is
priced in U.S. dollars, and the U.S. dollar has been falling against the
Canadian dollar for the last few years.  This has the effect of
reducing the Canadian dollar revenue that would otherwise be received for each
barrel of oil sold in U.S. dollars.






E.  Off
Balance Sheet Arrangements




There
were no off balance sheet arrangements in 2008 or 2007.






F.  Tabular
Disclosure of Contractual Obligations




Enterra
has commitments for the following payments over the next five
years:




Financial Instrument –
      Liability(in
      thousands of Canadian dollars)
                
                1
      Year
                
                
                2
      Years
                
                
                3
      Years
                
                
                3-5
      Years
                
                
                5+
      Years
                
                
                TotalBank
      indebtedness (1)
                
                
                -
                
                
                
                95,466
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                95,466Interest
      on bank indebtedness (2)
                
                
                3,580
                
                
                
                1,790
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                5,370Convertible
      debentures
                
                
                -
                
                
                
                -
                
                
                
                80,331
                
                
                
                40,000
                
                
                
                -
                
                
                
                120,331Interest
      on convertible debentures
                
                
                9,726
                
                
                
                9,726
                
                
                
                9,726
                
                
                
                1,650
                
                
                
                -
                
                
                
                30,828Accounts
      payable & accrued liabilities
                
                
                37,949
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                37,949Office
      leases (3)
                
                
                1,506
                
                
                
                1,597
                
                
                
                2,130
                
                
                
                925
                
                
                
                -
                
                
                
                6,158Vehicle
      and other operating leases
                
                
                373
                
                
                
                117
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                490Asset
      retirement obligations
                
                
                3,014
                
                
                
                4,090
                
                
                
                1,193
                
                
                
                3,983
                
                
                
                9,871
                
                
                
                22,151Total
      obligations
                
                
                56,148
                
                
                
                112,786
                
                
                
                93,380
                
                
                
                46,558
                
                
                
                9,871
                
                
                
                318,743


(1)  Assumes
the credit facilities are not renewed on June 24, 2009.


(2)  Assumes
an interest rate of 3.75% (the rate on December 31, 2008).


(3)  Future
office lease commitments may be reduced by sublease recoveries totaling $1.6
million.







G.  Safe
Harbor




Please
refer to the “Note Regarding Forward-Looking Statements” section at the
introduction of this 20-F.




ITEM 6 - DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES






A.  Directors
and Senior Management




Enterra’s
officers, directors and executive officers as of June 22, 2009
were:




Name and Municipality
                of Residence
            Position with Enterra
            Principal
  OccupationPeter
      Carpenter
              Toronto,
      Ontario
            Director
      (since 2006) and Chairman
            Senior
      Partner & Director
              Claridge
      House Partners, Inc.Roger
      Giovanetto
              Calgary,
      Alberta
            Director
      (since 2006)
            Business
      ConsultantMichael
      Doyle
              Calgary,
      Alberta
            Director
      (since 2007)
            Principal
              CanPetro
      International Ltd.Victor
      Dusik
              Vancouver,
      British Columbia
            Director
      (since 2008)
            Chief
      Financial Officer
              Run
      of River Power Inc.John
      Brussa
              Calgary,
      Alberta
            Director
      ( May 2009)
            Partner
      ,
              Burnet,
      Duckworth & Palmer LLP.Don
      Klapko
              Calgary,
      Alberta
            President
      and Chief Executive Officer
              Director
      (since 2008)
            President
      and Chief Executive Officer
              Enterra
      Energy Corp.Blaine
      Boerchers
              Calgary,
      Alberta
            Senior
      Vice President, Finance and Chief Financial Officer (since
      2007)
            Sr.
      VP, Finance and Chief Financial Officer
              Enterra
      Energy Corp.James
      (Jim) Tyndall
              Calgary,
      Alberta
            Senior
      Vice President and Chief Operating Officer (since 2006)
            Sr.  VP
      and COO
              Enterra
      Energy Corp.John
      F.  Reader
              Calgary,
      Alberta
            Senior
      Vice President Corporate Development (since 2005)
            Sr.  VP,
      Corporate Development
              Enterra
      Energy Corp.




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.




Roger Giovanetto,
Director




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




Michael Doyle,
Director




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




Victor Dusik,
Director




Victor
Dusik is a Chartered Accountant and Chartered Business Valuator with extensive
experience including the areas of corporate finance, acquisitions and
divestitures, risk management and public reporting and compliance.  He
is Chief Financial Officer of Run of River Power Inc., a publicly traded
developer of environmentally friendly energy based in Vancouver, British
Columbia.  Previously, Mr. Dusik held the positions of Vice President
Finance and Chief





Enterra Energy Trust Form 20 –
F





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.





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.




Don 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.




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




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




John F.  Reader,
Senior VP Corporate Development




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




Blaine Boerchers, Senior VP,
Finance 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.




B.  Compensation






The
following table sets forth the annual compensation, including total
compensation, for the financial year ended December 31, 2008 for the President
and Chief Executive Officer, the Chief Financial Officer and the three other
most highly compensated executive officers of the Trust and any of its
subsidiaries (collectively called the "Named Executive Officers" or
"NEOs").





Enterra Energy Trust Form 20 –
F










Name
      & Principal Position
              Year
              Salary
                ($)
              Share-based
      awards
                ($)
              Option-based
      awards
                ($)
              Non-equity
      incentive plan comp
                ($)
              Pension
                value
                ($)
              Other
      Comp
                
                ($)
              All
      other Comp
                
                ($)
              Total
      Comp
                ($)Annual
      Incentive Plans
              Long
      Term Incen-tive Plans(1)(2)
              (3)
              (4)
              (5)(6)(7)(8)
              
              
              (9)(10)(11)
              (12)(13)Trigger
      Projects
                Don
      Klapko
              2008
              240,000
              -
              -
              600,000
              -
              -
              -
              -
              840,000Don
      Klapko,
                President
      & CEO
              2008
              253,846
              2,303,280
              -
              -
              -
              -
              4,000,000
              28,096
              6,585,222Blaine
      Boerchers,
                CFO
              2008
              255,000
              307,561
              -
              85,000
              -
              -
              80,000
              47,110
              774,671Jim
      Tyndall,
                Senior
      Vice President & COO
              2008
              286,000
              469,167
              -
              85,000
              -
              -
              80,000
              30,840
              951,007John
      Reader,
                Senior
      Vice President Corporate Development
              2008
              265,000
              435,680
              -
              85,000
              -
              -
              80,000
              -
              865,680John
      Chimahusky,
                Senior
      Vice President & COO
                U.S.
      Operations
              2008
              245,183
              267,508
              33,720
              62,750
              -
              6,743
              189,173
              -
              805,077





(1)   Don
Klapko’s annual salary is $500,000.  Payment is for partial year (June
27 to December 31, 2008).


(2)
            John
      Chimahusky’s annual salary is US$230,000 and has been converted to C$ at
      the 2008 average annual exchange rate of
1.066


(3)
            RUs
      granted under the RUPU Plan.  The value is calculated on the
      basis of the accounting fair value.  The accounting fair value
      is calculated using the following formula: number of units grants less a
      forfeiture rate times the market value of the Trust Units, being their
      closing price on the TSX on the date prior to the date of
      grant.  RUs are typically 3 year grants with 1/3 of the units
      issued after each year (see “Unit Option Plan and RUPU Plan” on page
      16).


(4)
            John
      Chimahusky received a unit grant of 120,000 options on September 19, 2008
      pursuant to the Unit Option Plan which are exercisable as follows: (i) for
      the first 1/3 of the options granted, immediate vesting; (ii) for the next
      1/3 of the options granted, vesting on the first anniversary of John
      Chimahusky’s hire date, December 3, 2007 and (iii) for the remaining 1/3
      of the options granted, on the second anniversary of John Chimahusky’s
      hire date.  Any and all unexercised options shall expire on the
      fourth anniversary of John Chimahusky’s hire date, December 3, 2011 (see
      "Unit Option Plan and RUPU Plan" on page
16).




In
determining the fair value of John Chimahusky’s option award, the Black-Scholes
model, an established methodology, was used, with the following
hypothesis:




(i)      Risk-free
interest rate: 2.50%;


(ii)      Expected
volatility in the market price of the shares: 90.0%;


(iii)      Expected
dividend yield: 0%; and


(iv)      Expected
life: 3.2 years.


Fair
value per option: $0.2810




(5)
            Annual
      incentive for Trigger Projects consists of a bonus paid pursuant to the
      achievement of specific objectives (listed on 19) prior to contract
      completion.




(6)
            Don
      Klapko, President & CEO declined the annual incentive he was entitled
      to under the ABP (see “Bonus” on page
17).




(7)
            Annual
      incentives for Jim Tyndall, Blaine Boerchers, John Reader and John
      Chimahusky consist of the amounts earned under the ABP.  These
      amounts were earned based on the bonus terms approved by the Enterra Board
      in January 2008 and were awarded based on the NEOs meeting their
      individual performance objectives through the year.  The NEOs
      met their individual objectives (see "Annual Bonus Program" on page
      15).




(8)
            John
      Chimahusky’s ABP amount of US$50,000 has been converted to C$ at the
      exchange rate on the payment date, February 25, 2009 of
    1.255.




(9)
            Don
      Klapko was rewarded with a signing bonus that will be paid out over a
      period of three years, the total amount to be $4,000,000.  This
      is a one time reward in recognition of his achievements on behalf of the
      Trust prior to the date of his employment agreement and as an inducement
      to entering into his employment agreement (see “Other Income” on page
      19).




(10)
            Other
      compensation paid to Jim Tyndall, Blaine Boerchers and John Reader was a
      retention bonus paid on May 31, 2008, which was put in place in November
      2007, immediately after the former CEO resigned in order to ensure
      executive management continuity for the
Trust.




(11)
            Other
      compensation paid to John Chimahusky on September 29, 2008 was a signing
      bonus in the amount of US$181,200, converted to C$ at the exchange rate on
      the payment date of 1.044.




(12)
            Perquisites
      for Don Klapko and Jim Tyndall include the Trust’s contribution to their
      Unit Savings Plan as set out in “Trust Unit Savings Plan” on page 24,
      parking and other miscellaneous perquisites as required for business
      purposes,




(13)
            Perquisites
      for Blaine Boerchers include the Trust’s contribution to his Unit Savings
      Plan as set out in “Trust Unit Savings Plan” on page 24, payment for 18
      days of vacation he was unable to use in 2008, also parking and other
      miscellaneous perquisites as required for business
    purposes.





Enterra Energy Trust Form 20 –
F












Outstanding Share-based and
Option-based Incentive Plan Awards






The
following table indicates for each of the Named Executive Officers all awards
outstanding at the end of the 2008 financial year.







Option-based
      awards
                
                
                Share-based
      awardsName
                
                Number
      of securities underlying unexercised options
                  (#)
                
                
                Option
      exercise price
                  ($)
                
                
                Option
      expiration date
                
                
                Value
      of unexercised in-the-money options
                  ($)
                
                
                Number
      of shares or units of shares that have not vested
                  (#)
                
                
                Market
      or payout value of share-based awards that have not vested
                  ($)(1)
                
                
                
                (2)
                
                
                
                (3)Trigger
      Projects
                  Don
      Klapko
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -Don
      Klapko,
                  President
      & CEO
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                600,000
                
                
                
                360,000Blaine
      Boerchers
                  CFO
                
                
                150,000
                
                
                
                1.65
                
                
                Nov
      26, 2011
                
                
                
                -
                
                
                
                138,333
                
                
                
                83,000Jim
      Tyndall,
                  Senior
      Vice President & COO
                
                
                100,000
                
                
                
                15.49
                
                
                Jun
      5, 2011
                
                
                
                -
                
                
                
                161,651
                
                
                
                96,991150,000
                
                
                
                1.65
                
                
                Nov
      26, 2011John
      Reader,
                  Senior
      Vice President,
                  Corporate
      Development
                
                
                150,000
                
                
                
                1.65
                
                
                Nov
      26, 2011
                
                
                
                -
                
                
                
                146,927
                
                
                
                88,15675,000
                
                
                
                17.05
                
                
                May
      1, 201130,000
                
                
                
                23.26
                
                
                Jan
      25, 2010John
      Chimahusky,
                  Senior
      Vice President &
                  COO,
      U.S. Operations
                
                
                120,000
                
                
                
                2.81
                
                
                Dec
      3, 2011
                
                
                
                -
                
                
                
                70,769
                
                
                
                42,461









(1)
            None
      of the unexercised options (some of which have not yet vested) were
      in-the-money at the financial year end, December 31, 2008.  The
      actual gains, if any, on exercise will depend on the value of the Trust
      Units on the date of option exercise (see “Unit Option Plan and RUPU Plan”
      on page 16).




(2)
            RUs
      granted under the RUPU Plan.  The numbers include grants made in
      2006, 2007 and 2008.




(3)
            The
      market or payout value of the RU awards that have not vested is the number
      of RUs times the closing price of the Trust Units on December 31, 2008 on
      the TSX ($0.60).




Incentive-Plan Awards -
Value Vested or Earned during the Year






The
following table indicates for each of the Named Executive Officers the value on
vesting of all awards and the bonus payout during the 2008 financial
year.







Name
                
                Option-based
      awards Value vested during the year
                  ($)
                
                
                Share-based
      awards Value vested during the year
                  ($)
                
                
                Non-equity
      incentive plan compensation Value earned during the year
                  ($)(1)
                
                
                
                (2)
                
                
                
                (3)(4)(50(6)Trigger
      Projects
                  Don
      Klapko
                
                
                -
                
                
                
                -
                
                
                
                600,000Don
      Klapko,
                  President
      & CEO
                
                
                -
                
                
                
                -
                
                
                
                -Blaine
      Boerchers
                  CFO
                
                
                -
                
                
                
                25,643
                
                
                
                85,000Jim
      Tyndall,
                  Senior
      Vice President & COO
                
                
                -
                
                
                
                164,459
                
                
                
                85,000John
      Reader,
                  Senior
      Vice President, Corporate Development
                
                
                -
                
                
                
                139,296
                
                
                
                85,000John
      Chimahusky,
                  Senior
      Vice President & COO, U.S. Operations
                
                
                -
                
                
                
                30,985
                
                
                
                62,750





(1)
            The
      amount represents the aggregate dollar value that would have been realized
      if the options had been exercised on the vesting date, based on the
      difference between the closing price of the Trust Units on the TSX and the
      exercise price on such vesting
date.


(2)
            The
      amount represents the aggregate dollar value that has been realized upon
      vesting of the RUs


(3)
            Trigger
      Projects payment consists of a bonus paid pursuant to the achievement of
      specific objectives prior to contract completion (see “Other Income” on
      page 19).


(4)
            Don
      Klapko, President & CEO declined the bonus he was entitled to under
      the ABP (see “Bonus” on page 17).


(5)
            Jim
      Tyndall, Blaine Boerchers, John Reader and John Chimahusky earned bonus
      payments under the ABP (see “Annual Bonus Program” on page
      15).  Bonus payments to Jim Tyndall, Blaine Boerchers and John
      Reader were made on February 17,
2009.


(6)
            John
      Chimahusky’s bonus payment of US$50,000 has been converted to C$ at the
      exchange rate on the payment date, February 25, 2009 of
    1.255.




Pension
Plan Benefits






In 2008
the Trust did not have a Defined Benefit or a Defined Contribution Pension Plan
for the NEOs or for any of the Trust’s employees.




Trust Unit Savings
Plan




For all
of its Canadian employees, the Trust has an optional Trust Unit Savings Plan
whereby the Canadian employees including the NEOs can contribute up to 9% of
their base salaries through payroll deduction and the Trust will match their
contribution.  The combined contributions are used to purchase units
of the Trust on a monthly basis.  Employees can direct the
contributions to a Registered Retirement Savings Plan (up to the annual maximum
limit) or a non-registered savings account, or a combination of these
two.  Funds in the accounts can also be withdrawn or transferred to
another financial institution.  The Trust pays the administrative
costs associated with the Trust Unit Savings Plan including up to two transfers
or withdrawals per employee per year.




The
following table indicates the value accumulated under the Trust Unit Savings
Plan for each of the Canadian NEOs during the 2008 financial year:





Name
                
                Accumulated
      Value at Start of Year
                  ($)
                
                
                Compensatory
                  ($)
                
                
                Non-compensatory
                  ($)
                
                
                Accumulated
      Value at Year-end
                  ($)(1)
                
                
                
                (2)
                
                
                
                (3)
                
                
                
                (4)Don
      Klapko,
                  President
      & CEO
                
                
                -
                
                
                
                22,846
                
                
                
                22,846
                
                
                
                20,098Blaine
      Boerchers
                  CFO
                
                
                -
                
                
                
                22,856
                
                
                
                22,856
                
                
                
                11,753Jim
      Tyndall,
                  Senior
      Vice President & COO
                
                
                19,595
                
                
                
                25,740
                
                
                
                25,740
                
                
                
                14,057John
      Reader,
                  Senior
      Vice President,
                  Corporate
      Development
                
                
                12,990
                
                
                
                -
                
                
                
                -
                
                
                
                6,186





(1)
            The
      accumulated value at the start of the year is based on the number of Trust
      Units held in the plan multiplied by the closing price of the Trust Units
      on the TSX on January 2, 2008
($1.26)


(2)
            The
      compensatory amount is the Trust’s contribution to the
    plan.


(3)
            The
      non-compensatory amount is the NEOs contribution to the
    plan.


(4)
            The
      accumulated value at the end of the year is based on the number of Trust
      Units held in the plan multiplied by the closing price of the Trust Units
      on the TSX on December 31, 2008
($0.60).




Simple Incentive Match
Plan




For its
U.S. employees, the Trust has a Simple Incentive Match Plan for Employees
(“Simple Plan”).  Employees can contribute up to a maximum of $10,500
per year plus an additional $2,500 for employees over the age of
50.  The Trust matches the employee’s contribution up to 3% of their
base salaries up to $4,900.  The funds are held in individual
self-directed employee accounts.




Effective
January 1, 2009 the Trust is replacing the Simple Plan with a Safe Harbor 401(k)
Plan.  Employees will be able to contribute a maximum $16,500 plus an
additional $5,500 for employees over the age of 50.  The Trust will
match the employee’s contribution up to 6% of their base salaries.





Enterra Energy Trust Form 20 –
F







The
following table indicates the value accumulated under the Simple Plan for the
U.S. NEO during the 2008 financial year:







Name
            Accumulated
      Value at Start of Year
              ($)
            Compensatory
              ($)
            Non-compensatory
              ($)
            Accumulated
      Value at Year-end
              ($)(1)
            (2)
            (3)
            (4)John
      Chimahusky,
              Senior
      Vice President & COO,
              U.S.
      Operations
            -
            6,743
            12,703
            14,497





(1)
            The
      accumulated value at the start of the year is based on the value of the
      funds invested in the plan on January 2,
2008.


(2)
            The
      compensatory amount is the Trust’s contribution to the
    plan.


(3)
            The
      non-compensatory amount is the NEOs contribution to the
    plan.


(4)
            The
      accumulated value at the end of the year is based on the value of the
      funds invested in the plan on December 31,
2008.




REMUNERATION OF
DIRECTORS




The
Corporate Governance and Nomination Committee reviews the compensation of the
Trust’s non-employee Directors on an annual basis.  The Committee
reviews general compensation surveys to compare Enterra's director compensation
policies to generally accepted practices for publicly traded
companies.





During
the last financial year, the annual compensation of non-employee directors was
as follows, payable on a quarterly basis, in cash:




Annual
      Retainer - Chairman of the Board
                
                $
                45,000Annual
      Retainer – All Other Directors
                
                $
                30,000Board
      Meeting Fee – Chairman
                
                $
                2,500Board
      Meeting Fee – Director
                
                $
                2,000Special
      Committee Member fee (per month)
                
                $
                2,000Special
      Committee Meeting Fee
                
                $
                1,000All
      Other Committee Meetings as Chair
                
                $
                1,250All
      Other Committee Meetings as Member
                
                $
                1,000




In
November 2008, as a result of the significant responsibility undertaken by the
Audit Committee Chairman, the Corporate Governance and Nominating Committee
increased the annual retainer for the Audit Committee Chairman to $40,000
effective January 1, 2009.




In 2006
the Enterra Board approved RU grants for the then serving
Directors.  From 2006 to the date hereof the Enterra Board has
continued to approve RU grants for the directors.  The directors
receive most of their compensation in the form of cash and the RU grants that
have been granted to directors are small in relation to the RUs granted to
employees of the Trust.  However, the grants do provide directors with
an ongoing equity stake in the Trust throughout their respective periods of
Enterra Board service.




The
directors who are also executives of the Trust receive no remuneration for
serving as directors.  Directors are reimbursed for transportation and
other expenses for attendance at Board and Committee meetings.




The Trust
does not have a retirement plan for directors.  There are no other
arrangements or service contracts under which directors were compensated in
their capacity as directors by the Trust or its subsidiaries during the most
recently completed financial year.




The
following table provides details of the compensation received by the directors
of Enterra during the 2008 financial year.  Don Klapko, as an
executive of the Trust receives no remuneration for serving as a
Director.





Enterra Energy Trust Form 20 –
F










Name
              Fees
                earned
                ($)
              Share-based
      awards
                ($)
              Option-based
      awards
                ($)
              Non-equity
      incentive plan compensation
                ($)
              Pension
      value
                ($)
              All
      other compen-sation
                ($)
              Total
                Compensation
                ($)(2)
              (3)
              (4)
              (5)
              (6)Peter
      Carpenter
              104,000
              41,496
              -
              -
              -
              -
              145,496Keith
      Conrad
              -
              -
              -
              -
              -
              -
              -Michael
      Doyle
              81,795
              41,496
              -
              -
              -
              -
              123,291Victor
      Dusik
              74,942
              41,496
              -
              -
              -
              -
              116,438Roger
      Giovanetto
              65,750
              41,496
              -
              -
              -
              -
              107,246Don
      Klapko (1)
              -
              -
              -
              -
              -
              -
              -





(1)
            RUs
      granted under the RUPU Plan.  The value is calculated on the
      basis of the accounting fair value.  The accounting fair value
      is calculated using the following formula: number of units grants less a
      forfeiture rate times the market value of the Trust Units, being their
      closing price on the TSX on the date prior to the date of
      grant.  RUs are typically 3 year grants with 1/3 of the units
      issued after each year (see “Unit Option Plan and RUPU Plan” on page
      16).


(2)
            None
      of the directors received options under the Unit Option
    plan.


(3)
            None
      of the directors received any form of non-equity incentive plan
      compensation.


(4)
            The
      Trust does not have a retirement plan for
  Directors.


(5)
            The
      directors, other than Don Klapko who is an executive of the Trust, are
      reimbursed for transportation and other expenses for attendance at Enterra
      Board and Committee meetings.  There are no other arrangements
      under which the Directors were compensated by the Trust or its
      subsidiaries during the most recently completed financial
      year.


(6)
            Mr.
      Conrad resigned from the Enterra Board effective February 20,
      2008.









C.  Board
Practices






The Trust
does not have a Board of Directors or officers.  The Board of
Directors and officers of Enterra Energy Corp.  act as the Trust’s
directors and officers.  Enterra is authorized to have a board of at
least three directors and no more than ten.  Enterra currently has
five directors.  Directors are elected for a term of about one year,
from annual meeting to annual meeting, or until an earlier resignation, death or
removal.  Each officer serves at the discretion of the board or until
an earlier resignation or death.  There are no family relationships
among any of Enterra’s directors or officers.  Alberta securities laws
require that Enterra have at least two independent outside directors who are not
officers or employees of Enterra.  Currently, one director is a member
of management and four directors are independent.






Committees of the Board of
Directors






Committees




The board
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 Reserves
Committee and the Health Safety Regulatory Compliance and Environmental
Committee.  In addition, an independent committee (the “Special
Committee”) has been constituted for the purpose of addressing issues related to
Macon Resources Ltd. and Petroflow as detailed under “Special Committee”
below.





Corporate Governance and
Nominating Committee





EEC has
established a Corporate Governance and Nominating Committee comprised of 3
non-management members of the board of EEC.  The Corporate Governance
committee consists of Michael Doyle, Victor Dusik and Roger
Giovanetto.  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 (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.  The mandate of
the Audit Committee is to assist the board of EEC in its oversight of the
integrity of our financial and related information, including the financial
statements, internal controls and procedures for financial reporting and the
processes for monitoring compliance with legal and regulatory





Enterra Energy Trust Form 20 –
F





requirements.  In
doing so, the Audit Committee oversees the audit efforts of our external
auditors and, in that regard, is empowered to take such actions as it may deem
necessary to satisfy itself that our external auditors are independent of
us.





Compensation




EEC has
established a Compensation Committee comprised of 3 non-management members of
the board of ECC.  The compensation Committee at December 31, 2008
consists of Michael Doyle, Victor Dusik and Roger Giovanetto.  The
mandate of the Compensation Committee is to review and recommend to the board of
directors of EEC:





•
            executive
      compensation policies, practices and overall compensation
      philosophy;




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




•
            bonus
      and trust unit options;




•
            major
      changes in benefit plans; and




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




Reserves




EEC has
established a Reserves Committee comprised of 3 non-management members of the
board.  The reserves committee is Peter Carpenter, Victor Dusik and
Roger Giovanetto.  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.




Health Safety Regulatory
Compliance and Environmental Committee




The
Health Safety Regulatory Compliance and Environmental Committee currently
consists of Mr. Carpenter (Chairman), Mr. Doyle and Mr. Dusik. The mandate of
this Committee is to review the nature and extent of compliance in the areas of
health, safety, regulatory compliance and Environmental matters.







Special
Committee




EEC
established an Independent Committee composed of 3 non-management members of the
board of directors.  The special committee was Peter Carpenter,
Michael Doyle and Victor Dusik.





The
mandate of the Special Committee was to:





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




•
            search
      for and negotiate terms of employment for a President and CEO
      candidate;




•
            formulate
      a CEO succession plan;




•
            review
      alternatives to strengthen the balance
sheet;




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







Enterra Energy Trust Form 20 –
F





•
            review
      and resolve any conflicts of interest that exist;
  and




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




The
Special Committee was disbanded after Mr. Klapko was hired as President and
Chief Executive Officer.






D.  Employees







At
December 31, 2008, the Trust employed or contracted 54 office personnel and 36
field operations personnel in its Canadian operations and 20 office personnel
and 33 field operations personnel in its U.S. operations for a total of 143
employees.




E.  Share
Ownership







The
percentage of Trust Units that were owned, directly or indirectly, by all
directors and officers of Enterra as of June 18, 2009 as a group was 0.48%
(approximately 296,717 Trust Units).





The
following table sets forth the number of units, options and unvested units held
by the members of the Board of Directors as at June 18, 2009.





Name
              Number
      of  units held
                (#)
              Number
      of securities underlying unexercised options
                (#)
              Option
      exercise price
                ($)
              Option
      expiration date
              Number
      of  units that have not vested
                (#)Peter
      Carpenter,
                Director
              4,250
              10,000
              15.55
              May
      18, 2011
              10,000Roger
      Giovanetto,
                Director
              4,697
              10,000
              15.55
              May
      18, 2011
              10,000Michael
      Doyle,
                Director
              7,050
              -
              -
              -
              10,000Victor
      Dusik,
                Director
              2,815
              -
              -
              -
              10,000John
      Brussa,
                Director
              -
              -
              -
              -
              -








The
following table sets forth the number of units, options and unvested units held
by the officers of the Trust at June 18, 2009.








Name
              Number
      of  units held
                (#)
              Number
      of securities underlying unexercised options
                (#)
              Option
      exercise price
                ($)
              Option
      expiration date
              Number
      of  units that have not vested
                (#)Don
      Klapko,
                President
      & CEO
              52,026
              -
              -
              -
              600,000Blaine
      Boerchers
                CFO
              49,190
              150,000
              1.65
              Nov
      26, 2011
              138,333Jim
      Tyndall,
                Senior
      Vice President & COO
              115,430
              100,000
              15.49
              Jun
      5, 2011
              145,831150,000
              1.65
              Nov
      26, 2011John
      Reader,
                Senior
      Vice President,
                Corporate
      Development
              61,259
              150,000
              1.65
              Nov
      26, 2011
              135,42275,000
              17.05
              May
      1, 201130,000
              23.26
              Jan
      25, 2010













ITEM
7 - MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS






A.  Major
Shareholders






To
the extent that it is known to Enterra or can be ascertained from public
filings, no shareholder has more beneficial ownership of 5% or more of Enterra’s
Trust Units.  To the best of our knowledge, Enterra is not directly or
indirectly controlled by another corporation or the government of Canada or any
other government.  Our management believes that no single person or
entity holds a controlling interest in our share capital.






B.  Related
Party Transactions






On
November 23, 2007, Enterra entered into a consulting agreement with Trigger
Projects Ltd. for management services that would effectively be expected of the
most senior manager of the Trust.  This relationship was entered into
to provide temporary executive management services after the former Chief
Executive Officer resigned.  This contract had terms that required
payment for services of $40,000 per month and a bonus of up to $0.5 million on
termination.  The contract expired on May 31, 2008 and was extended to
June 26, 2008.  During 2008, total payments of $0.8 million were made
to Trigger Projects Ltd. and no balance was outstanding at December 31,
2008.






In 2006
Enterra entered into a farm-out agreement with Petroflow Energy Ltd. (“JV
Partner”), a public oil and gas company, to fund the drilling and completion
costs of the undeveloped lands in Oklahoma.  Per the agreement, JV
Partner pays 100% of the drilling and completion costs to earn 70% of Enterra’s
interest in the well and Enterra is required to pay 100% of the infrastructure
costs to support these wells, such as pipelines and salt water disposal
wells.  The infrastructure costs paid by Enterra are recoverable from
JV Partner over three years with interest charged at a rate of 12% per
annum.  Infrastructure costs paid by Enterra are accounted for as a
capital lease, therefore, the capital costs incurred are not included in
property, plant and equipment but are current and long-term
receivables.  The interest income on the long-term receivables is
recorded as a reduction in interest expense.  The former Chief
Executive Officer and former director of Enterra owned, directly and indirectly,
approximately 16% of the outstanding shares of JV Partner during his tenure at
Enterra.  A current director of Enterra owns approximately 2% of the
outstanding shares of JV Partner.  As at December 31, 2008, a total of
$27.9 million, split between $8.6 million of trade receivables and $19.3 million
of long-term receivables, relate to infrastructure costs incurred by Enterra on
behalf of JV Partner that are due from JV Partner.  The receivables
are for infrastructure costs incurred that are to be repaid by JV Partner over a
three-year period and is subject to interest of 12% per annum.  For
the year ended December 31, 2008, $1.7 million of interest income was earned on
the long-term receivables from JV Partner (2007 – $0.4 million).  In
2008, $5.0 million of principal payments have been received (2007 - $1.1
million).






In 2007,
Enterra paid Macon Resources Ltd. (“Macon”) $0.7 million, a company 100% owned
by the former Chief Executive Officer, for management services provided by the
former Chief Executive Officer.  Macon did not provide any services to
Enterra during 2008 and therefore there were no payments made in
2008.  During Q1 2007, 50,000 restricted units (valued at $0.4 million
based on the unit price of trust units on the grant date) were granted to
Macon.  On February 28, 2007, these restricted units vested and were
converted to 50,441 trust units.  The former Chief Executive Officer
resigned as an officer and director on November 27, 2007 and February 20, 2008
respectively.






Relationship
with JED Oil Inc. and JMG Exploration Inc.






On
January 1, 2006, Enterra terminated a Technical Services Agreement with JED Oil
Inc (“JED”), which had provided for services required to manage the Trust’s
field operations and governed the allocation of general and administrative
expenses between the two entities.  The Trust now manages its own
management, development, exploitation, operations and general and administrative
activities.






On
September 28, 2006, Enterra terminated the existing farmout, joint services and
an Agreement of Business Principles with JED.  Concurrent with the
termination of the agreements, the Trust settled all amounts owing to
JED.






In
September 2006, Enterra sold $44.0 million of petroleum and natural gas
properties to JED in exchange for $30.9 million of petroleum and natural gas
properties and the settlement of the $13.1 million balance due to
JED.







Enterra Energy Trust Form 20 –
F







Previously,
under an Agreement of Business Principles, properties acquired by the Trust were
contract operated and drilled by JMG Exploration, Inc. (“JMG”), a publicly
traded oil and gas exploration company, if they were exploration properties, and
contract operated and drilled by JED, a publicly traded oil and gas development
company, if they were development projects.  Exploration of the properties
was done by JMG, which paid 100% of the exploration costs to earn a 70% working
interest in the properties. If JMG discovered commercially viable reserves on
the exploration properties, the Trust had the right to purchase 80% of JMG’s
working interest in the properties at a fair value as determined by independent
engineers.  Had the Trust elected to have JED develop the properties,
development would have been done by JED, which would pay 100% of the development
costs to earn 70% of the interests of both JMG and the Trust.  The Trust
had a first right to purchase assets developed by JED.






C.  Interests
of Experts and Counsel


Not
applicable.




ITEM
8 - FINANCIAL INFORMATION




A.  Consolidated
Statements and Other Financial Information


See Item
18 – Financial Statements.






B.  Significant
Changes


There
were no significant changes since December 31, 2008, the date of the financial
statements.






ITEM
9 - THE OFFER AND LISTING




A.  Offer and Listing
Details




1.  Expected
Price of Shares Offered


Not
Applicable.






2.  Market
for Securities Offered


Not
Applicable.






3.  Purchase
Rights


Not
Applicable.






4.  Price
Range of Common Stock and Trading Markets




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


TSX
              
              
              NYSEHigh
      ($)
              
              
              Low
      ($)
              
              
              High
      (US$)
              
              
              Low
      (US$)Year
      ended 2008
              
              
              5.15
              
              
              
              0.58
              
              
              
              5.08
              
              
              
              0.47Year
      ended 2007
              
              
              9.68
              
              
              
              1.00
              
              
              
              8.25
              
              
              
              1.04Year
      ended 2006
              
              
              22.46
              
              
              
              7.75
              
              
              
              19.50
              
              
              
              6.78Year
      ended 2005
              
              
              32.32
              
              
              
              18.50
              
              
              
              26.75
              
              
              
              15.76Year
      ended 2004
              
              
              24.00
              
              
              
              13.01
              
              
              
              19.47
              
              
              
              10.10Quarter
      ended December 31, 2008
              
              
              2.45
              
              
              
              0.58
              
              
              
              2.29
              
              
              
              0.47Quarter
      ended September 30, 2008
              
              
              4.80
              
              
              
              2.07
              
              
              
              4.80
              
              
              
              1.93Quarter
      ended June 30, 2008
              
              
              5.15
              
              
              
              1.76
              
              
              
              5.08
              
              
              
              1.74Quarter
      ended March 31, 2008
              
              
              2.62
              
              
              
              1.14
              
              
              
              2.66
              
              
              
              1.16Quarter
      ended December 31, 2007
              
              
              2.96
              
              
              
              1.00
              
              
              
              2.99
              
              
              
              1.04Quarter
      ended September 30, 2007
              
              
              6.50
              
              
              
              1.35
              
              
              
              6.18
              
              
              
              1.33Quarter
      ended June 30, 2007
              
              
              6.95
              
              
              
              5.69
              
              
              
              6.41
              
              
              
              4.96Quarter
      ended March 31, 2007
              
              
              9.68
              
              
              
              5.76
              
              
              
              8.25
              
              
              
              4.88Six
      most recent months ended:May
      31, 2009
              
              
              1.70
              
              
              
              1.20
              
              
              
              1.53
              
              
              
              1.04April
      30, 2009
              
              
              1.62
              
              
              
              0.74
              
              
              
              1.35
              
              
              
              0.59March
      31, 2009
              
              
              0.92
              
              
              
              0.55
              
              
              
              0.79
              
              
              
              0.41February
      28, 2009
              
              
              0.80
              
              
              
              0.53
              
              
              
              0.65
              
              
              
              0.43January
      31, 2009
              
              
              0.91
              
              
              
              0.57
              
              
              
              0.77
              
              
              
              0.47December
      31, 2008
              
              
              1.09
              
              
              
              0.58
              
              
              
              0.92
              
              
              
              0.47







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





TSX
      (ENT.DB)
              
              
              TSX
      (ENT.DB.A)High
      ($)
              
              
              Low
      ($)
              
              
              High
      ($)
              
              
              Low
      ($)Year
      ended 2008
              
              
              97.50
              
              
              
              55.00
              
              
              
              100.50
              
              
              
              62.00Year
      ended 2007
              
              
              104.25
              
              
              
              60.00
              
              
              
              104.50
              
              
              
              60.00Year
      ended 2006
              
              
              121.00
              
              
              
              100.00
              
              
              
              N/A
              
              
              
              N/AYear
      ended 2005
              
              
              N/A
              
              
              
              N/A
              
              
              
              N/A
              
              
              
              N/AYear
      ended 2004
              
              
              N/A
              
              
              
              N/A
              
              
              
              N/A
              
              
              
              N/AQuarter
      ended December 31, 2008
              
              
              91.00
              
              
              
              55.00
              
              
              
              93.50
              
              
              
              62.00Quarter
      ended September 30, 2008
              
              
              97.50
              
              
              
              92.00
              
              
              
              100.50
              
              
              
              92.00Quarter
      ended June 30, 2008
              
              
              96.00
              
              
              
              85.00
              
              
              
              100.50
              
              
              
              86.00Quarter
      ended March 31, 2008
              
              
              94.70
              
              
              
              68.01
              
              
              
              90.00
              
              
              
              75.05Quarter
      ended December 31, 2007
              
              
              97.00
              
              
              
              60.00
              
              
              
              93.00
              
              
              
              60.00Quarter
      ended September 30, 2007
              
              
              100.00
              
              
              
              75.00
              
              
              
              102.00
              
              
              
              77.00Quarter
      ended June 30, 2007
              
              
              100.00
              
              
              
              94.67
              
              
              
              104.50
              
              
              
              99.75Quarter
      ended March 31, 2007
              
              
              104.25
              
              
              
              93.00
              
              
              
              N/A
              
              
              
              N/ASix
      most recent months ended:May
      31, 2009
              
              
              75.00
              
              
              
              65.00
              
              
              
              78.00
              
              
              
              66.50April
      30, 2009
              
              
              69.00
              
              
              
              62.90
              
              
              
              69.00
              
              
              
              59.00March
      31, 2009
              
              
              68.25
              
              
              
              50.00
              
              
              
              62.50
              
              
              
              59.00February
      28, 2009
              
              
              65.01
              
              
              
              55.00
              
              
              
              65.00
              
              
              
              58.00January
      31, 2009
              
              
              66.00
              
              
              
              55.00
              
              
              
              70.00
              
              
              
              55.00December
      31, 2008
              
              
              72.00
              
              
              
              55.00
              
              
              
              68.50
              
              
              
              62.00




B.  Plan of
Distribution


Not
applicable




C.  Markets


Our Trust
units are listed on the Toronto Stock Exchange (ENT.UN) and the New York Stock
Exchange (ENT).




D.  Selling
Shareholders


Not
applicable




E.  Dilution


Not
applicable




F.  Expenses of the
Issue







Enterra Energy Trust Form 20 –
F





ITEM
10 – ADDITIONAL INFORMATION





A.  Share
Capital


Not
applicable.





B.  Trust
Indenture / Memorandum and Articles of Incorporation


The Trust






Enterra
Energy Trust is an open-ended unincorporated investment trust governed by the
laws of the Province of Alberta and created pursuant to the Trust
Indenture.




The
principal undertaking of the Trust is to issue trust units and to acquire and
hold debt instruments, royalties and other interests.  The direct and
indirect wholly owned subsidiaries of the Trust carry on the business of
acquiring and holding interests in petroleum and natural gas properties and
assets related thereto.




The
Trustee is prohibited from acquiring any investment or engaging in any activity
which (a) would result in the Trust Units becoming “foreign property” (as
defined in the Income Tax Act(Canada)) or which would cause the Trust to become liable for tax under
Part XI under the Income
Tax Act (Canada), (b) would result in the Trust not being considered
either a “unit trust” or a “mutual fund trust” for purposes of the Income Tax Act(Canada), or
(c) would cause the Trust to be subject to regulation as an “investment
company” under the U.S.
Investment Company Act of 1940.




The Trust
is authorized to issue an unlimited number of trust units.  The
Unitholders have no liability for further capital calls and are not subject to
any discrimination due to number of trust units owned.




The
rights of trust Unitholders can be changed at any time in a Unitholders meeting
where the modifications are approved by 66 2/3% of the Unitholders represented
by proxy or in person at the meeting.




All
Unitholders are entitled to vote at annual or special meetings of Unitholders,
provided that they were Unitholders as of the record date.  The record
date for Unitholders meetings may precede the meeting date by no more than
50 days and not less than 21 days.  Notice of the time and
place of meetings of Unitholders may not be less than 21 or greater than
50 days prior to the date of the meeting.




Enterra


Enterra
is amalgamated under the laws of the Province of Alberta, Canada (corporation
number 207913385).  The Articles of Amalgamation and by-laws provide
no restrictions as to the nature of the business operations of
Enterra.




The
governing legislation requires a director to inform Enterra, at a meeting of the
Board of Directors, of any interest he or she has in a material contract or
proposed material contract with Enterra.  No director may vote in
respect of any such contract made by them with Enterra or in any such contract
in which they are interested.  However, these provisions do not apply
to (i) an arrangement by way of security for money lent to or obligations
undertaken by them: (ii) a contract relating primarily to their
remuneration as a director, officer, employee or agent of Enterra or an
affiliate: (iii) a contract for indemnity or insurance of the director as
allowed under the governing legislation: or (iv) a contract or transaction
with an affiliate.




The Board
of Directors, subject to the direction of the Trustee, may exercise all powers
of the Trust to borrow or raise money, and to give guarantees, and to mortgage
or charge its properties and assets, and to issue debentures, debenture stock
and other securities, outright or as security for any debt, liability or
obligation of the Trust or its subsidiaries.




There are
no age limit requirements regarding retirement of directors and there is no
minimum share ownership required for a director’s election to the
board.







Enterra Energy Trust Form 20 –
F







All
directors of Enterra are elected at each annual meeting of Unitholders of the
Trust and cumulative voting is not permitted.






C.  Material
Contracts




The Trust
has entered into material contracts that are other than in the ordinary course
of business during the previous two years, other than as described elsewhere in
this Form 20-F, as follows:




·
            Second
      Amended and Restated Credit Agreement dated June 25, 2008 among Enterra
      Energy Corp. and the Bank of Nova Scotia and a syndicate of lenders
      including Bank of Nova Scotia.




D.  Exchange
Controls




There is
no law or government decree or regulation in Canada that restricts the export or
import of capital, or affects the remittance of dividends, interest or other
payments to non-resident holders of trust units, other than withholding tax
requirements.




There is
no limitation imposed by Canadian law or by our charter or other charter
documents on the right of a non-resident to hold or vote our trust units, other
than as provided by the Investment Canada Act, the
North American Free Trade
Agreement Implementation Act(Canada) and the World Trade Organization Agreement
Implementation Act.  The Investment Canada Actrequires notification and, in certain cases, advance review and approval
by the Government of Canada of the acquisition by a “non-Canadian” of “control”
of a “Canadian business,” each as defined in the Investment Canada
Act.  In general, the threshold for review will be higher in
monetary terms for a member of the World Trade Organization or North American
Free.





E.  Taxation




Canadian Federal Income Tax
Considerations




The
following is a summary of the material Canadian federal income tax
considerations under the Income Tax Act(Canada) (the
“Tax Act”) in respect of the acquisition of trust units pursuant this offering
generally applicable to purchasers who (i) hold trust units as capital
property for purposes of the Tax Act, and (ii) at all material times deal
at arm’s length, and are not affiliated, with Enterra and the Trust for purposes
of the Tax Act.  Generally, trust units will be considered to be
capital property to a holder who does not hold such securities in the course of
carrying on a business and has not acquired them in one or more transactions
considered to be an adventure in the nature of trade.  Certain
Canadian resident Unitholders who might not otherwise be considered to hold
their trust units as capital property may, in certain circumstances, be entitled
to make an irrevocable election in accordance with subsection 39(4) of the Tax
Act to have such trust units treated as capital property.




This
summary is not applicable to either a unitholder that is a “financial
institution” or a “specified financial institution”, as defined for purposes of
the Tax Act, or a unitholder, an interest in which would be a “tax shelter
investment” under the Tax Act.




This
summary is based upon the provisions of the Tax Act and the regulations
thereunder (“Tax Regulations”) in force as of the date hereof, all specific
proposals to amend the Tax Act and the Tax Regulations that have been publicly
announced by or on behalf of the Minister of Finance (Canada) prior to the date
hereof (the “Proposed Amendments”) and the Trust’s understanding of the current
published administrative and assessing policies of the Canada Revenue Agency
(the “CRA”).




This
summary is not exhaustive of all possible Canadian federal income tax
considerations applicable to the acquisition of trust units and, except for the
Proposed Amendments, does not take into account or anticipate any changes in the
law, whether by legislative, governmental or judicial action or changes in the
administrative and assessing practices of the CRA.  This summary does
not take into account any provincial, territorial or foreign tax considerations,
which may differ significantly from those discussed herein.




This summary is of a general
nature only and is not intended to be relied on as legal or tax advice or
representations to any particular investor.  Consequently, potential
investors are urged to seek independent tax advice in respect of the
consequences to them of the acquisition of trust units having regard to their
particular circumstances.







Enterra Energy Trust Form 20 –
F







Residents
of Canada


This
portion of the summary is applicable to a unitholder who, for the purposes of
the Tax Act and at all relevant times, is resident, or deemed to be resident, in
Canada.






Status
of the Trust


The Trust
qualifies as a mutual fund trust under the provisions of the Tax Act and the
balance of the summary assumes that the Trust will continue to so
qualify.  The Trust is also a “registered investment” under the Tax
Act, and this summary further assumes that the Trust will be so
registered.]






The
requirements to qualify as a mutual fund trust for purposes of the Tax Act
include:




1.
            
            the
      sole undertaking of the Trust must be the investing of its funds in
      property (other than real property or interests in real property), the
      acquiring, holding, maintaining, improving, leasing or managing of any
      real property (or an interest in real property) that is capital property
      of the Trust, or any combination of these activities;2.
            
            the
      Trust must comply on a continuous basis with certain requirements relating
      to the qualification of the trust units for distribution to the public,
      the number of Unitholders and the dispersal of ownership of trust
      units.  In this regard, there must be at least 150 Unitholders,
      each of whom owns not less than one “block” of trust units having a fair
      market value of not less than $500.  A “block” of trust units
      means 100 trust units if the fair market value of one trust unit is less
      than $25; and3.
            
            continuously
      from the time of its creation, all or substantially all of the Trust’s
      property must consist of property other than property that would be
      “taxable Canadian property” for purposes of the Tax
  Act.




The Trust
has certain restrictions on its activities and its powers and certain
restrictions on the holding of taxable Canadian property, such that Enterra
believes it is reasonable to expect that the requirements will be
satisfied.  However, Enterra and the Trust can provide no assurances
that the requirements will continue to be met.






If the Trust were not to so
qualify as a mutual fund trust or were not to be registered as a registered
investment from inception, the income tax considerations would in some respects
be materially different from those described below.




Taxation
of the Trust


The Trust
is subject to tax in each taxation year on its income or loss for the year,
computed as though it were a separate individual resident in
Canada.  The taxation year of the Trust will end on December 31
of each year.




The Trust
will be required to include in its income for each taxation year (i) all
interest on the Notes that accrues to, becomes receivable or is received by it
before the end of the year, except to the extent that such interest was included
in computing its income for a preceding year (ii) all interest on the CT
Note that accrues to, becomes receivable or is received by it before the end of
the year, except to the extent that such interest was included in computing its
income for a preceding year (iii) the net income of Commercial Trust paid
or payable to the Trust in the year and (iv) all amounts in respect of any
oil and gas royalties, if any, held by the Trust including any amounts required
to be reimbursed to the grantor of the royalty in respect of Crown
charges.




In
computing its income, the Trust will generally be entitled to deduct reasonable
administrative expenses incurred to earn income.  The Trust will be
entitled to deduct the costs incurred by it in connection with the issuance of
trust units on a five-year, straight-line basis (subject to pro-ration for short
taxation years).  The Trust may also deduct amounts which become
payable by it to Unitholders in the year, to the extent that the Trust has net
income for the year after the inclusions and deductions outlined above and to
the extent permitted under the Tax Act.  An amount will be considered
to have become payable to a unitholder in a taxation year only if it is paid in
that year by the Trust or the unitholder is entitled in that year to enforce
payment of the amount.  Under the Trust Indenture, net income of the
Trust for each year will be paid or made payable by way of cash distributions to
the Unitholders.  The Trust Indenture also contemplates other
situations in which the Trust may not have sufficient cash to distribute all of
its net income by way of such cash distributions.  In such
circumstances, such net income will be payable to Unitholders in the form of the
issuance by the Trust of additional trust units (“Reinvested trust
units”).  Accordingly, it is anticipated that the Trust will generally
not have any taxable income for the purposes of the Tax Act.







Enterra Energy Trust Form 20 –
F







Under the
Trust Indenture, income received by the Trust may be used to finance cash
redemptions of trust units.  A redemption of trust units that is
effected by a distribution by the Trust to a unitholder of Series A Notes
will be treated as a disposition by the Trust of such Series A Notes for
proceeds of disposition equal to the fair market value thereof and may give rise
to a taxable capital gain to the Trust.




The Trust
will be entitled for each taxation year to reduce (or receive a refund in
respect of) its liability, if any, for tax on its net taxable capital gains by
an amount determined under the Tax Act based on the redemption or retraction of
trust units during the year (the “Capital Gains Refund”).  In certain
circumstances, the Capital Gains Refund for a particular taxation year may not
completely offset the Trust’s tax liability on net realized capital gains for
such taxation year.




For
purposes of the Tax Act, the Trust generally intends to deduct, in computing its
income and taxable income, the full amount available for deduction in each
year.  As a result of such deductions and the Trust’s entitlement to a
Capital Gains Refund, it is expected that the Trust will not be liable for any
material amount of tax under the Tax Act.  However, no assurance can
be given in this regard.




The Trust
is a “registered investment” under the Tax Act.  It may have its
registration revoked by the CRA if it ceases to be a mutual fund trust and did
not otherwise qualify for registered investment status.




If the
Trust ceases to qualify as a mutual fund trust, the Trust may be required to pay
tax under Part XII.2 of the Tax Act.  The payment of
Part XII.2 tax by the Trust may have material adverse tax consequences for
certain Unitholders.




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





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





Commencing
January 1, 2011, the Trust will not be able to deduct certain of its distributed
income.  The Trust will become subject to a distribution tax ranging
from 25 to 28 percent, depending on the amount of taxable income allocated to
various provinces on distributions of income, but this tax will not apply to
returns of capital.  Enterra will consider the options and alternative
structures with legal and business advisors to determine if any potential
restructuring available to maximize value is in the best interest of
unitholders.





The
federal component of the proposed tax on SIFT is expected to be 15 percent in
2012 (25 to 28 percent in total including provincial income taxes) and
thereafter.  The Trust is required to recognize, on a prospective
basis, future income taxes on temporary differences in the Trust.




Taxation
of Unitholders




Income
from trust units


The
income of a unitholder from the trust units will be considered to be income from
property for the purposes of the Tax Act.  Any deduction or loss of
the Trust for the purposes of the Tax Act cannot be allocated to and treated as
a deduction or loss of a unitholder.




A
unitholder will generally be required to include in computing income for a
particular taxation year of the unitholder the portion of the net income of the
Trust for a taxation year, including taxable dividends and net taxable capital
gains, that is paid or becomes payable to the unitholder in that particular
taxation year, whether such amount is payable in cash or in Reinvested trust
units.  Provided that appropriate designations are made by Commercial
Trust and the Trust, such portion of the Trust’s net taxable capital gains and
taxable dividends, if any, as are paid or payable to a unitholder will
effectively retain their character as taxable capital gains and taxable
dividends, respectively, and will be treated as such in the hands of the
unitholder for purposes of the Tax Act.







Enterra Energy Trust Form 20 –
F







The
amount of any net taxable capital gains designated by the Trust to a unitholder
will be included in the unitholder’s income under the Tax Act for the year of
disposition as a taxable capital gain.  See “Taxation of Capital Gains and
Capital Losses” below.  The non-taxable portion of net realized
capital gains of the Trust that is paid or becomes payable to a unitholder in a
year will not be included in computing the unitholder’s income for the
year.  Any other amount in excess of the net income of the Trust that
is paid or becomes payable by the Trust to a unitholder in a year will generally
not be included in the unitholder’s income for the year.  However, a
unitholder is required to reduce the adjusted cost base of the trust units held
by such unitholder by each amount payable to the unitholder otherwise than as
proceeds of disposition of trust units (except to the extent that the amount
either was included in the income of the unitholder or was the unitholder’s
share of the non-taxable portion of the net capital gains of the Trust, the
taxable portion of which was designated by the Trust in respect of the
unitholder).  To the extent that the adjusted cost base of a trust
unit is less than zero, the negative amount will be deemed to be a capital gain
of a unitholder from the disposition of the trust unit in the year in which the
negative amount arises.  See “Taxation of Capital Gains and
Capital Losses” below.




The
amount of dividends designated by the Trust to a unitholder will be subject to,
among other things, the gross-up and dividend tax credit provisions for
Unitholders who are individuals, the refundable tax under Part IV of the
Tax Act applicable to “private corporations” and “subject corporations” (as
defined under the Tax Act), and the deduction in computing taxable income in
respect of dividends received by taxable Canadian corporations.  In
general, net income of the Trust that is designated as taxable dividends from
taxable Canadian corporations or as net taxable capital gains may increase an
individual unitholder’s liability for alternative minimum tax.




Cost of
trust units


The cost
to a unitholder of a trust unit will generally include all amounts paid by the
unit holder for the trust unit.  Reinvested trust units issued to a
unitholder, as a non-cash distribution of income will have a cost equal to the
amount of income distributed by the issuance of such Reinvested trust
units.  This cost will be averaged with the adjusted cost base of all
other trust units held by the unitholder as capital property in order to
determine the respective adjusted cost base of each trust unit.






Disposition
of trust units


Upon the
disposition or deemed disposition by a unitholder of a trust unit, whether on a
redemption or otherwise, the unitholder will generally realize a capital gain
(or a capital loss) equal to the amount by which the proceeds of disposition
exceed (or are less than) the aggregate of (i) such unitholder’s adjusted
cost base of the trust units disposed of, determined immediately before the
disposition and (ii) any reasonable costs of disposition.  A
redemption of trust units in consideration for cash distributed to the
unitholder in satisfaction of the Market Redemption Price, or the issuance of a
Redemption Note by the Trust in satisfaction of the Market
Redemption






Price,
will be a disposition of such trust units for proceeds of disposition equal to
the cash or the principal amount of the Redemption Note, as the case may
be.  Where trust units are redeemed by the distribution of
Series A Notes to the unitholder, the proceeds of disposition to the
unitholder of such trust units will generally be equal to the fair market value
of the Series A Notes so distributed less any capital gain or income
realized by the Trust in connection with such redemption which has been
designated by the Trust to the redeeming unitholder.






Where a
unitholder that is a corporation or a trust (other than a mutual fund trust)
disposes of a trust unit, the unitholder’s capital loss from the disposition
will generally be reduced by the amount of dividends from taxable Canadian
corporations previously designated by the Trust to the unitholder, except to the
extent that a loss on a previous disposition of a trust unit has been reduced by
such dividends.  Similar rules apply where a corporation or trust
(other than a mutual fund trust) is a member of a partnership that disposes of
trust units.  See “Taxation of Capital Gains and
Capital Losses” below.






The cost
to a unitholder of any Series A Notes distributed to the unitholder by the
Trust on a redemption of trust units will be equal to the fair market value of
such Series A Notes at the time of distribution, excluding any accrued
interest thereon.  Such a unitholder will be required to include in
income interest on such Series A Notes (including interest that had accrued
to the date of distribution of the Series A Notes to the unitholder) in
accordance with the provisions of the Tax Act.  To the extent that the
unitholder is required to include in income any interest that had accrued to the
date of distribution of the Series A Notes, an offsetting deduction will be
available in computing the unitholder’s income from the Trust.






A
unitholder will be required to include in income interest on the Redemption
Notes in accordance with the provisions of the Tax Act.







Enterra Energy Trust Form 20 –
F







A
unitholder that is corporation that is throughout a relevant taxation year a
“Canadian-controlled private corporation”, as defined in the Tax Act, may be
liable to pay an additional refundable tax of 6 2/3% on certain investment
income, including taxable capital gains and interest.






Tax-Exempt
Unitholders


Provided
that the Trust qualifies as a “mutual fund trust” or is a “registered
investment” for purposes of the Tax Act at a particular time, the trust units
will be qualified investments for Exempt Plans.  If the Trust ceases
to qualify as a mutual fund trust and the Trust’s registration as a registered
investment under the Tax Act is revoked, the trust units will cease to be
qualified investments under the Tax Act for Exempt Plans.  Where, at
the end of a month, an Exempt Plan holds trust units or other properties that
are not qualified investments, the Exempt Plan may, in respect of that month, be
required to pay a tax under Part XI.1 of the Tax Act.




Exempt
Plans will generally not be liable for tax in respect of any distributions
received from the Trust or any capital gain arising on the disposition of trust
units.  However, where an Exempt Plan receives trust property as a
result of a redemption of trust units, some or all of such property may not be
qualified investments under the Tax Act for the Exempt Plans and could, as
discussed above, give rise to adverse consequences to the Exempt Plans (and, in
the case of registered retirement savings plans or registered retirement income
funds, to the annuitants thereunder).  Accordingly, Exempt Plans that
own trust units should consult their own tax advisors before deciding to
exercise their redemption rights thereunder.






Taxation
of Capital Gains and Capital Losses


Generally,
one half of any capital gain (a “taxable capital gain”) realized by a unitholder
or a unitholder on the disposition of capital property in a taxation year must
be included in the income of the holder for the year, and one half of any
capital loss (an “allowable capital loss”) realized in a taxation year may be
deducted from taxable capital gains realized by the holder in that
year.  Allowable capital losses for a taxation year in excess of
taxable capital gains for that year generally may be carried back and deducted
in any of the three preceding taxation years or carried forward and deducted in
any subsequent taxation year against net capital gains realized in such years,
to the extent and under the circumstances described in the Tax Act.




A
corporation that is throughout a relevant taxation year a “Canadian-controlled
private corporation”, as defined in the Tax Act, may be liable to pay an
additional refundable tax of 6 2/3% on certain investment income, including
taxable capital gains realized in the particular taxation year.




Capital
gains realized by an individual may give rise to a liability for alternative
minimum tax.




Non-Residents
of Canada


This
portion of the summary is applicable to a unitholder who, for the purposes of
the Tax Act, and at all relevant times is not resident in Canada and is not
deemed to be resident in Canada, does not use or hold, and is not deemed to use
or hold, trust units in, or in the course of, carrying on business in Canada,
and is not an insurer who carries on an insurance business in Canada and
elsewhere (a “Non-Resident Holder”).




Taxation
of the Trust


The tax
treatment of the Trust under the Tax Act is as generally described above under
“Residents of Canada – Taxation of the Trust”.  If the Trust ceases to
qualify as a mutual fund trust for purposes of the Tax Act, the Trust may be
required to pay tax under Part XII.2 of the Tax Act.  The payment
of Part XII.2 tax by the Trust may have adverse tax consequences to certain
Unitholders.




Taxation
of Income from Trust Units


All
income of the Trust determined in accordance with the Tax Act (except taxable
capital gains) paid or credited by the Trust in a taxation year to a
Non-Resident Holder will generally be subject to Canadian withholding tax at a
rate of 25%, subject to a reduction of such rate under an applicable income tax
treaty or convention, whether such income is paid or credited in cash or in
Reinvested trust units.  See “Residents of Canada – Taxation of
the Trust” above.  Provided that certain conditions are
satisfied, the rate of Canadian withholding tax may be reduced to 15% in
respect







Enterra Energy Trust Form 20 –
F







of
amounts that are paid or credited by the Trust to a Non-Resident Holder that is
a United States resident for the purposes of the Canadian-United States Income
Tax Convention.






The Trust
is required to maintain a special “TCP gains balance” account to which it will
add its capital gains from dispositions after March 22, 2004 of “taxable
Canadian property” (as defined in the Tax Act) and from which it will deduct its
capital losses from dispositions of such property and the amount of all “TCP
gains distributions” (as defined in the Tax Act) made by it in previous taxation
years.  If the Trust pays an amount to a Non-Resident Holder, makes a
designation to treat that amount as a taxable capital gain of the Holder and the
total of all such amounts designated by the Trust in a taxation year to
Non-Resident Holders exceeds 5% of all such designated amounts, such portion of
that amount as does not exceed the Non-Resident Holder’s pro rata portion of the
Trust’s “TCP gains balance” account (as defined in the Tax Act) for the taxation
year effectively will be subject to the same Canadian withholding tax as
described above for distributions of income (other than net realized capital
gains).  All other amounts distributed by the Trust to a Non-Resident
Holder other than amounts described above, where more than 50% of the fair
market value of a Trust Unit is attributable to, inter alia, real property
situated in Canada or a “Canadian resource property” (as defined in the Tax Act)
will be subject to a special Canadian tax of 15% of the amounts of such
distributions as an income tax on the deemed capital gain.  This tax
will be withheld from such distributions by the Trust.  A Non-Resident
Holder will not be required to report such distribution in a Canadian tax return
and such distribution will not reduce the adjusted cost base of the Non-Resident
Holder’s Trust Units.  If a Non-Resident Holder realizes a capital
loss on the disposition of a Trust Unit in a particular taxation year and files
a special tax return on or before such Non-Resident Holder’s filing due date for
such taxation year, the Non-Resident Holder will have a “Canadian property
mutual fund loss” (as defined in the Tax Act) equal to the lesser of such loss
and sum of all distributions previously received on such Trust Unit that were
subject to 15% tax.  The Non-Resident Holder’s tax liability for such
taxation year shall be computed by reducing any deemed capital gain for the
taxation year by the aggregate of such loss and any unused “Canadian property
mutual fund losses” (as defined in the Tax Act) from previous taxation years
arising from the disposition of a Trust Unit or a share of the capital stock of
a mutual fund corporation or a unit of another mutual fund trust.  In
certain circumstances, the Non-Resident Holder may be entitled to receive a
refund of all or a portion of such tax.  A Canadian property mutual
fund loss and unused Canadian mutual fund losses generally may be carried back
up to three years and forward indefinitely and deducted against similar
distributions received in such years.






Disposition
of trust units


A
Non-Resident Holder will be subject to taxation in Canada in respect of a
capital gain or capital loss realized on the disposition of trust units only to
the extent such units constitute “taxable Canadian property”, as defined in the
Tax Act, and the Non-Resident Holder is not afforded relief under an applicable
income tax treaty or convention.




Trust
units will normally not be taxable Canadian property at a particular time
provided that (i) the Non-Resident Holder, persons with whom the Non-Resident
Holder does not deal at arm’s length (within the meaning of the Tax Act), or the
Non-Resident Holder together with such persons, did not own or have an interest
in or option in respect of 25% or more of the issued trust units at any time
during the 60-month period preceding the particular time (ii) the Trust is
a mutual fund trust at the time of the disposition, and (iii) the trust
units are not otherwise deemed to be taxable Canadian property.




A
Non-Resident Holder of trust units that are not taxable Canadian property will
not be subject to tax on gains realized under the Tax Act on the disposition of
such units.




A
Non-Resident Holder whose trust units constitute taxable Canadian property
generally will realize a capital gain (or capital loss) on the redemption or
disposition of such units equal to the amount by which the proceeds of
disposition exceeds (or is less than) the aggregate of (i) such
unitholder’s adjusted cost base of its trust units so disposed, determined
immediately before the disposition and (ii) any reasonable costs of
disposition.




Taxation
of Capital Gains and Capital Losses on Dispositions of Taxable Canadian
Property


Generally,
one half of any capital gain (a “taxable capital gain”) realized by a
Non-Resident Holder on a disposition of taxable Canadian property in a taxation
year must be included in the income of the Non-Resident Holder for the year, and
one half of any capital loss (an “allowable capital loss”) realized by a
Non-Resident Holder on a disposition of taxable Canadian property in a taxation
year may be deducted from taxable capital gains realized by the Non-Resident
Holder in that year.  Allowable capital losses for a taxation year in
excess of taxable capital gains for that year generally may be carried back and
deducted in any of the three preceding taxation years or carried forward and
deducted in any subsequent taxation year against net capital gains realized in
such years, to the extent and under the circumstances described in the Tax
Act.







Enterra Energy Trust Form 20 –
F







In
certain cases where a Non-Resident Holder realizes a capital gain from a
disposition of property that constitute taxable Canadian property to such
Non-Resident Holder, it is possible that any such capital gain may be exempt
from tax for the purposes of the Tax Act by virtue of the provisions of an
income tax treaty or convention between Canada and the country of residence of
the Non-Resident Holder.  Conversely, the amount of any capital loss
resulting from the disposition of such property may not be deductible against
capital gains of the Non-Resident Holder for the purposes of the Tax Act by
virtue of the provisions of such income tax treaty or
convention.  Unitholders who are Non-Resident Holders are advised to
consult with their tax advisors regarding the application of any applicable
income tax treaty or convention.




If a
Non-Resident Holder disposes of taxable Canadian property, the Non-Resident
Holder is required to file a Canadian income tax return for the taxation year in
which such disposition occurs.






United States Federal Income
Tax Considerations


The
following summary discusses the material United States federal income tax
considerations that are generally applicable to a holder of Enterra common
shares and trust units who is a citizen or resident of the United States, who is
a corporation, partnership or other entity that is created or organized in or
under the laws of the United States, who is subject to United States federal
income tax on a net income basis with respect to Enterra common shares or who
will be subject to United States federal income tax on a net income basis with
respect to trust units that are acquired (a “U.S. Holder’’).




This
summary does not purport to be a complete description of all of the United
States federal income tax considerations that may be relevant to a U.S.
Holder.  In particular, this summary deals only with U.S. Holders who
hold Enterra common shares as a capital asset.  This summary does not
address the tax treatment of U.S. Holders who are subject to special tax
rules.  Nor does this summary discuss the United States federal income
tax considerations for a partner in a partnership which holds Enterra common
shares or trust units.






Flow-through
of Items of Income, Gain, Loss, Deduction and Credit


Enterra
should be treated as a partnership for U.S. federal income tax
purposes.  As such, a U.S. holder will include in each of its taxable
years its share of our items of income, gain, loss, deduction and credit whether
or not we make any distribution.  Such items of income, gain, loss,
deduction and credit will be determined under United States federal income tax
principles and will as a general matter retain their character and source as
they flow through us to the holders of trust units.  The use by a
holder of trust units of certain of our items of deduction, loss and credit will
be limited as is discussed below.




As a
result, a U.S. holder whose taxable year is not the same as our taxable year and
who disposes of all of its trust units after the close of its taxable year but
before the end of our taxable year will be required to include in income for its
then taxable year its share of more than one year of our items of income, gain,
loss, deduction and credit.  A U.S. Holder’s share of our items of
income, gain, loss, deduction and credit will, as a general matter, be its
percentage interest in us of such items.




Tax Rates and Creditability
of Certain Canadian Income Taxes.


As
general matter, the character and source of a U.S. holder’s share of the items
of the income, gain, loss, deduction and credit is determined at our level and
flows through us to each such U.S. holder in determining its liability for
United States federal income tax including any effect of the alternative minimum
tax.  Each U.S. holder should consult with its tax advisors as to the
impact of holding trust units on its liability for the United States federal
income tax and the alternative minimum tax.  The rules as to the use
of foreign income taxes as credits are complex, the following discussion is only
a summary of a portion thereof, and a U.S. holder should discuss these matters
with its own tax advisors.




United States Federal Income
Tax Rates


Dividends
that are received from certain foreign corporation by eligible shareholders
(excludes corporate shareholders)  are currently subject to the United
States federal income tax at a maximum rate of 15 percent under certain
conditions.  For example, if a U.S. holder is an individual, then any
dividends received would be subject to the United States federal income tax at a
maximum rate of 15 percent so long as (i) the shares in respect of
which the dividends are paid have been held (subject to certain tolling rules)
for more than 60 days during the 120 day period which begins
60 days before the those shares go ex-dividend, (ii) such U.S. holder
is not under an obligation to make







Enterra Energy Trust Form 20 –
F







certain
related payments with respect to substantially similar or related property,
(iii) we are not a passive foreign investment company, and (iv) we are
eligible for the benefits of the income tax treaty between Canada and the United
States.  It is likely that the Internal Revenue Service will take the
position that such holding period requirement is applied when an individual
holds shares indirectly through us to the individual’s holding period in trust
units.




For a
U.S. holder who is an individual, any long-term capital gain that is realized on
the sale or other disposition of trust units (including any part of a
distribution that is treated as gain on such shares that is a long-term capital
gain) would be subject to tax at a maximum rate of 15 percent until the end of
2010 under current law.  Each U.S. holder should discuss with its own
advisor whether a person whose holding period in us is less than one year can
claim such 15 percent tax rate.




Credits for Canadian Income
Taxes


As a
general matter, any Canadian income taxes that are withheld from distributions
are foreign income taxes that, subject to generally applicable limitations under
United States law, may be used by a U.S. holder as a credit against its United
States federal income tax liability or as a deduction (but only for a taxable
year for which such U.S. holder elects to do so with respect to all foreign
income taxes).  So long as we are a partnership for United States
federal income tax purposes, the provisions of Section 901(k) of the Internal
Revenue Code should not apply.  If we were a corporation for such
purposes, then a U.S. Holder would not be able to claim the foreign tax credit
with respect to any such Canadian tax that is withheld on a distribution that we
made unless such U.S. holder had held the trust units for a minimum period
(subject to certain tolling rules) of at least 16 days during the
30 day period beginning on the date which is 15 days before the date
on which the trust units went ex-dividend with respect to such dividend or to
the extent such U.S. holder is under an obligation to make related payments with
respect to substantially similar or related property.  It is likely
that the Internal Revenue Service will take the position that the holding period
requirement that is summarized in the preceding sentence is measured as to an
individual partner of us in respect of any Canadian taxes paid by us in respect
of dividends that we receive by the holding period in the trust
units.




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.  For such purposes, a U.S.
holder’s share of our income, gain, loss and deductions is generally in the
passive basket if it holds less than 10 percent of the trust
units.  Its share of the dividends and the income will be from foreign
sources, but the amount of foreign source income of an individual is only a
fraction of the dividend income that is subject to the 15 percent maximum
rate.  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.




Tax
Consequences if We are Determined to be a Passive Foreign Investment
Company


Although
we do not expect to be a passive foreign investment company, or PFIC, it will be
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 any company,
U.S. or foreign, in which it is considered to own 25 percent or more of the
shares by value, is passive income (as defined in the pertinent provisions of
the Internal Revenue Code or (b) 50 percent or more of its assets
(including the pro rata share of the assets of any company in which it is
considered to own 25 percent or more of the shares by value), are held for
the production of, or produce, passive income.  Although we believe
that we are not currently a PFIC and do not expect that we will become a PFIC,
there is no assurance in that regard.




If we
were a PFIC, and a U.S. holder did not make an election to treat it as a
qualified electing fund (there is no assurance that it will be able to make such
an election) or elect to make a mark-to-market election (again, there is no
assurance that it will be able to make such an election) then distributions on
our stock that exceed 125 percent of the average distributions received by
the U.S. holder in the shorter of the three previous taxable years or the U.S.
holder’s holding period for the trust units before the taxable year of
distribution and the entire amount of gain that is realized by a U.S. holder
upon the sale of the trust units would be subject to an additional United States
income tax that approximates (and in some cases exceeds) the value of presumed
benefit of a deferral of United States income taxation that was available
because we are a foreign corporation.









Enterra Energy Trust Form 20 –
F


Tax-Exempt
Organizations and Other Investors


Ownership
of trust units by employee benefit plans, other tax-exempt organizations,
non-resident aliens, foreign corporations, other foreign persons and regulated
investment companies or mutual funds raises issues unique to those investors
and, as described below, may have substantially adverse tax consequences to
them.




Employee
benefit plans and most other organizations exempt from federal income tax,
including individual retirement accounts and other retirement plans, are subject
to federal income tax on unrelated business taxable income.  We are
unable to provide any assurance that the income that we recognize in respect of
the royalty or in respect of any of our other assets will not be unrelated
business taxable income.




A
regulated investment company or “mutual fund” (as such terms are used in the
Internal Revenue Code) is required in order to maintain its special status under
the Internal Revenue Code to derive 90 percent or more of its gross income
from interest, dividends and gains from the sale of stocks or securities or
foreign currency or specified related sources.  A significant amount
of our gross income may not be any such type of income.




Administrative
Matters




Nominee
Reporting


Persons
who hold an interest trust units as a nominee for another person are required to
furnish to us:




•
            
            the
      name, address and taxpayer identification number of the beneficial owner
      and the nominee;•
            
            whether
      the beneficial owner is:





(i)
            
            a
      person that is not a United States person;(ii)
            
            a
      foreign government, an international organization or any wholly owned
      agency or instrumentality of either of the foregoing; or(iii)
            
            a
      tax-exempt entity;





•
            
            the
      amount and description of trust units held, acquired or transferred for
      the beneficial owner; and•
            
            specific
      information including the dates of acquisitions and transfers means of
      acquisitions and transfers, and acquisition cost for purchases, as well as
      the amount of net proceeds from sales.




Brokers
and financial institutions are required to furnish additional information,
including whether they are United States persons and specific information on the
trust units they acquire, hold or transfer for their own account.  A
penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is
imposed by the Internal Revenue Code for failure to report that information to
us.  The nominee is required to supply the beneficial owner of the
trust units with the information furnished to us.




Registration as a Tax
Shelter


The
Internal Revenue Code requires that “tax shelters” be registered with the
Secretary of the Treasury.  Although we may not be a “tax shelter” for
such purposes, we have applied to register as a “tax shelter” with the Secretary
of the Treasury in light of the substantial penalties that might be imposed if
registration is required and not undertaken.




Issuance of a tax shelter
registration number does not indicate that investment in us or the claimed tax
benefits have been reviewed, examined or approved by the Internal Revenue
Service.


We will
supply our tax shelter registration number to you when one has been assigned to
us.  A unitholder who sells or otherwise transfers a trust unit in a
later transaction must furnish the registration number to the
transferee.  The penalty for failure of the transferor of a unit to
furnish the registration number to the transferee is $100 for each
failure.  A unitholder must disclose our tax shelter registration
number on its tax return on which any deduction, loss or other benefit we
generates is claimed or on which any of our income is included.  A
unitholder who fails to disclose the tax shelter registration number on its
return, without reasonable cause for that failure, will be subject to a $250
penalty for each failure.  Any penalties discussed are not deductible
for federal income tax purposes.











Enterra Energy Trust Form 20 –
F


Reportable
Transactions


Certain
Treasury regulations require taxpayers to report specific information on
Internal Revenue Service Form 8886 if they participate in a “reportable
transaction”.  A transaction may be a reportable transaction based
upon any of several factors, including the existence of book-tax differences
common to financial transactions, one or more of which may be present with
respect to your investment in the trust units.  Investors should
consult their own tax advisor concerning the application of any of these factors
to an investment in the trust units.  Congress is considering
legislative proposals that, if enacted, would impose significant penalties for
failure to comply with these disclosure requirements.




Other Tax
Considerations


Each U.S.
holder is urged to investigate the legal and tax consequences, under the laws of
pertinent jurisdictions, of acquiring and holding the trust
units.  Accordingly, each prospective unitholder is urged to consult
its tax counsel or other advisor with regard to those
matters.  Further, it is the responsibility of each unitholder to file
all state, local and foreign, as well as United States federal tax returns that
may be required.






F.  Dividends
and Paying Agents


Not
applicable




G.  Statement
by Experts


Not
applicable




H.  Documents
on Display


It is
possible to read and copy documents referred to in this annual report on Form
20-F that have been filed with the SEC at the SEC’s public reference room
located at 100 F Street, NE, Room 1580, Washington, DC 20549 and at the SEC’s
other public reference rooms in New York City and Chicago.  Please
call the SEC at 1-800-SEC-0330 for further information on the public reference
rooms and their copy charges.  The SEC filings are also available to
the public from commercial document retrieval services and in the website
maintained by the SEC at www.sec.gov.  It is also possible to read and
copy documents referred to in this annual report on Form 20-F at the New York
Stock Exchange, 20 Broad Street, 17th floor, New York.




If you
are a unitholder, you may request a copy of these filings at no cost by
contacting us at:




Enterra
Energy Trust


Suite 2700,
500 – 4th Avenue
S.W.


Calgary,
Alberta, Canada


T2P
2V6


(403) 263-0262






I.  Subsidiary
Information


Not
applicable







ITEM
11- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK





In the
current volatile economic and financial market conditions, the Trust continually
assesses its risks and manages those risks to the best of its
abilities.  The Trust is exposed to normal market risks inherent in
the oil and natural gas business, including commodity price risk, credit risk,
financing risk, foreign currency and environmental risk.  From time to
time, Enterra attempts to mitigate its exposure to these risks by using
commodity contracts and by other means.  These risks are described in
more detail in Note 13 to the consolidated financial statement.





Commodity Price
Risk




Commodity
price fluctuations are among the Trust’s most significant
exposures.  Crude oil prices are influenced by worldwide factors such
as supply and demand fundamentals, OPEC actions and political
events.  Natural gas prices are influenced by oil prices, North
American natural gas supply and demand factors including weather, storage
levels







Enterra Energy Trust Form 20 –
F





and LNG
imports.  In accordance with policies approved by the Board of
Directors, the Trust may, from time to time, manage these risks through the use
of fixed physical contracts, swaps, collars or other commodity
contracts




Credit
Risk




Credit
risk is the risk of loss if purchasers or counterparties do not fulfill their
contractual obligations.  The receivables are principally with
customers in the oil and natural gas industry and are subject to normal industry
credit risk.  The Trust continues to assess the strength of its
counterparties and tries to do business with high quality companies with
substantial assets.  The counter parties on the commodity contracts
are generally large well financed companies and all new contracts are being
executed with only the strongest of these companies to manage the exposure from
counterparty risk.  Management continuously monitors credit risk and
credit policies to ensure exposures to customers are limited.  The
Trust believes that the financial strength of its Bank syndicate, which consists
of the Bank of Nova Scotia, HSBC Bank Canada and Union Bank of California,
appears to be relatively strong and has confirmed their commitment to Enterra
and has provided assurance that they are not unduly impacted by the recent
turmoil in credit markets.





Financing
Risk





Enterra
currently maintains a portion of its debt in floating-rate bank facilities which
results in exposure to fluctuations in short-term interest rates which have, for
a number of years, been lower than longer-term rates.  In June 2009,
Enterra completed a borrowing base review with its lenders where its revolving
and operating credit facilities borrowing capacity of $110.0 million was
established.  Enterra’s syndicate of lenders, consisting of Bank of
Nova Scotia, HSBC Bank Canada and Union Bank of California have confirmed their
commitment to Enterra and have indicated that they are not unduly impacted by
the recent turmoil in credit markets.





Foreign Currency Rate
Risk





Enterra’s
U.S. operations accounted for 45% of Enterra’s total 2008 production; therefore,
fluctuations in the U.S. dollar to Canadian dollar exchange rate will impact the
Trust’s revenues due to the Trust translating the revenues from the U.S.
operations into Canadian dollars.  The Trust also has commodity
contracts denominated and settled in U.S. dollars.




Environmental
Risk




The oil
and natural gas industry is subject to environmental regulation pursuant to
local, provincial and federal legislation.  A breach of such
legislation may result in the imposition of fines or issuance of clean up orders
in respect of Enterra or its working interests.  Such legislation may
be changed to impose higher standards and potentially more costly obligations on
Enterra.  There is uncertainty regarding the Federal Government’s
Regulatory Framework for Air Emissions (“Framework”), as issued under the
Canadian Environmental Protection Act.  Additionally, the potential
impact on the Trust’s operations and business of the Framework, with respect to
instituting reductions of greenhouse gases, is not possible to quantify at this
time as specific measures for meeting Canada’s commitments have not been
developed.




Liquidity
Risk




Liquidity
risk is the risk that Enterra is unable to meet its financial liabilities as
they come due.  Management utilizes a long-term financial and capital
forecasting program that includes continuous review of debt forecasts to ensure
credit facilities are sufficient relative to forecast debt levels, distribution
and capital program levels are appropriate, and that financial covenants will be
met.  In the short term, liquidity is managed through daily cash
management activities, short-term financing strategies and the use of collars
and other commodity contracts to increase the predictability of minimum levels
of cash flow from operating activities.  Additional information on
specific instruments is discussed in Item 5 and in Note 13 to the consolidated
financial statements.




Enterra
has commitments for the following payments over the next five
years:





Financial Instrument –
      Liability(in
      thousands of Canadian dollars)
                
                1
      Year
                
                
                2
      Years
                
                
                3
      Years
                
                
                3-5
      Years
                
                
                5+
      Years
                
                
                TotalBank
      indebtedness (1)
                
                
                -
                
                
                
                95,466
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                95,466Interest
      on bank indebtedness (2)
                
                
                3,580
                
                
                
                1,790
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                5,370Convertible
      debentures
                
                
                -
                
                
                
                -
                
                
                
                80,331
                
                
                
                40,000
                
                
                
                -
                
                
                
                120,331Interest
      on convertible debentures
                
                
                9,726
                
                
                
                9,726
                
                
                
                9,726
                
                
                
                1,650
                
                
                
                -
                
                
                
                30,828Accounts
      payable & accrued liabilities
                
                
                37,949
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                37,949Office
      leases (3)
                
                
                1,506
                
                
                
                1,597
                
                
                
                2,130
                
                
                
                925
                
                
                
                -
                
                
                
                6,158Vehicle
      and other operating leases
                
                
                373
                
                
                
                117
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                490Asset
      retirement obligations
                
                
                3,014
                
                
                
                4,090
                
                
                
                1,193
                
                
                
                3,983
                
                
                
                9,871
                
                
                
                22,151Total
      obligations
                
                
                56,148
                
                
                
                112,786
                
                
                
                93,380
                
                
                
                46,558
                
                
                
                9,871
                
                
                
                318,743


(1)  Assumes
the credit facilities are not renewed on June 24, 2009.


(2)  Assumes
an interest rate of 3.75% (the rate on December 31, 2008).


(3)  Future
office lease commitments may be reduced by sublease recoveries totaling $1.6
million.








ITEM
12- DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES




Not
Applicable.






PART
II




ITEM 13- DEFAULTS, DIVIDEND ARREARAGES AND
DELINQUENCIES




None




ITEM
      14- MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF
      PROCEEDS




Not
applicable




ITEM 15- CONTROLS AND PROCEDURES




(a) Disclosure
controls and procedures.




As of
December 31, 2008, an internal evaluation was carried out of the effectiveness
of the Trust’s disclosure controls and procedures as defined in Rule 13a-15
under the US Securities Exchange Act of 1934 and as defined in Canada by
National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and
Interim Filings.  Based on that evaluation, the President and Chief
Executive Officer and the Chief Financial Officer concluded that the disclosure
controls and procedures are effective to ensure that the information required to
be disclosed in the reports that the Trust files or submits under the Exchange
Act or under Canadian Securities legislation is recorded, processed, summarized
and reported, within the time periods specified in the rules and forms
therein.  Disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that the information
required to be disclosed by the Trust in the reports that it files or submits
under the Exchange Act or under Canadian Securities Legislation is accumulated
and communicated to the Trust’s management, including the senior executive and
financial officers, as appropriate to allow timely decisions regarding the
required disclosure.




(b) Management’s
annual report on internal control over financial reporting.




Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting for the Trust.  The Trust has
undertaken a review of the effectiveness of its internal control over financial
reporting based on the Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO).  For the year ended December 31, 2008, based on that
evaluation, the Trust’s internal controls were found to be operating effectively
and no material weaknesses existed.  The effectiveness of Enterra’s
internal control over financial reporting as at December 31, 2008 was audited by
KPMG LLP, an independent registered public accounting firm.





For the
December 31, 2007 reporting period it was identified that as a result of
turnover within Senior Management during 2007, the potential for control
weaknesses was heightened.  Enterra took action to fill these Senior
Management positions in Q4 2007 with individuals that have the necessary
experience and knowledge to address the complexity of the financial reporting
requirements and there have been no changes in these positions during
2008.   Throughout the year the new Senior Management team was in
place and changes to internal control processes were made to resolve the
material weakness that existed at December 31, 2007.  The Trust
completed testing of its internal controls over financial reporting in Q4 2008
and was able to conclude that no material control weakness existed at December
31, 2008.





Enterra Energy Trust Form 20 –
F





(c) Attestation
report of the registered public accounting firm




The
attestation report of the independent registered chartered accountants on the
effectiveness of internal control over financial reporting is included under the
heading "Report of Independent Registered Chartered Accountants" in Item 18
to this Annual Report on Form 20-F.






(d) Changes
in internal controls.




For the December 31, 2007 reporting period it was identified that as a
result of turnover within Senior Management during 2007, the potential for
control weaknesses was heightened.  Enterra took action to fill these
Senior Management positions in Q4 2007 with individuals that have the
necessary experience and knowledge to address the complexity of the financial
reporting requirements and there have been no changes in these positions during
2008.  Throughout the year the new Senior Management team was in place
and changes to internal control processes were made to resolve the material
weakness that existed at December 31, 2007.  The Trust completed
testing of its internal controls over financial reporting in Q4 2008 and was
able to conclude that no material control weakness existed at December 31,
2008.




ITEM
16.  [RESERVED]






ITEM
16A.  AUDIT COMMITTEE FINANCIAL EXPERT




The board
of directors of Enterra Energy Corp., on behalf of the Registrant, has
determined that Mr. Victor Dusik, a member and the chairman of the Registrant's
Audit Committee, is an "audit committee financial expert" (as such
term is defined by the rules and regulations of the Securities and Exchange
Commission) and is "independent" (as that term is defined by the
New York Stock Exchange's listing standards applicable to the
Registrant).




The
Securities and Exchange Commission has indicated that the designation or
identification of a person as an "audit committee financial expert" does not
(i) mean that such person is an "expert" for any purpose, including without
limitation for purposes of Section 11 of the Securities Act of 1933,
(ii) impose on such person any duties, obligations or liability that are
greater than the duties, obligations and liability imposed on such person as a
member of the audit committee and the board of directors in the absence of such
designation or identification, or (iii) affect the duties, obligations or
liability of any other member of the audit committee or the board
of directors.






ITEM 16B.  CODE OF
ETHICS




The
Registrant has adopted a "code of ethics" (as that term is defined by the
rules and regulations of the Securities and Exchange Commission), entitled the
"Code of Business Conduct” that applies to each director, officer (including its
principal executive officer, principal financial officer, principal accounting
officer or controller, or persons performing similar functions), employee and
consultant of the Registrant.  The Code of Business Conduct is
available for viewing on the Registrant's website at www.enterraenergy.com
under "Corporate Governance" and is attached in the exhibits to this
document.  There were not any amendments to any provision of the Code
of Business Conduct during the fiscal year ended December 31,
2008.  Further, during the fiscal year ended December 31, 2008,
there were not any waivers, including implicit waivers, granted from any
provision of the Code of Business Conduct that applied to the Registrant's
principal executive officer, principal financial officer, principal accounting
officer or controller, or persons performing similar functions.






ITEM
16C.  PRINCIPAL ACCOUNTANT FEES AND SERVICES




Audit
Fees




KPMG LLP
audited the annual financial statements for the 2008 and 2007 fiscal
year.





(in $ thousands)
                
                2008
                
                
                2007Audit
      fees (1)
                
                
                530.1
                
                
                
                701.0Audit-related
      fees (2)
                
                
                75.0
                
                
                
                82.0Tax
      fees (3)
                
                
                -
                
                
                
                -All
      other fees (4)
                
                
                10.2
                
                
                
                84.0Total
                
                
                615.3
                
                
                
                867.0


Notes:


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


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


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


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




The
Registrant's Audit Committee has implemented a policy restricting the
services that may be provided by the Registrant's auditors.  Prior to
the engagement of the Registrant's auditors to perform both audit and non-audit
services, the Audit Committee pre-approves the provision of the
services.  In making their determination regarding non-audit services,
the Audit Committee considers the compliance with the policy and the
provision of non-audit services in the context of avoiding an adverse impact on
auditor independence.  All audit and non-audit fees paid to
KPMG LLP in 2007 and 2008 were pre-approved by the Registrant's Audit 
Committee and none were approved on the basis of the de minimis exemption set
forth in Rule 2-01(c)(7)(i)(C) of Regulation S-X.  Based on
the Audit Committee's discussions with management and the independent
auditors, the committee is of the view that the provision of the non-audit
services by KPMG LLP described above is compatible with maintaining that
firm's independence from the Registrant.






ITEM16D.  EXEMPTIONS
FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES




Not
applicable.






ITEM16E.
      PURCHASE OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED
      PURCHASERS




Not
applicable.






ITEM16F.  CHANGE
IN REGISTRANTS CERTIFIED ACCOUNTANT




Not
applicable.






ITEM16G.  CORPORATE
GOVERNANCE




The
Registrant has reviewed the New York Stock Exchange's corporate governance
rules and confirms that the Registrant's corporate governance practices are not
significantly nor materially different than those required of domestic companies
under the New York Stock Exchange's listing standards except that, as a
foreign private issuer, the Registrant is not obligated to and does not have an
internal audit function.






PART
III




ITEM
17 – FINANCIAL STATEMENTS




We have responded to Item 18 in lieu of responding to this
item.






ITEM
18 – FINANCIAL STATEMENTS




Index to Financial Statements;




Reports
KPMG LLP, Independent Auditors


Consolidated
Balance Sheets at December 31, 2008 and 2007


Consolidated
Statements of Income (Loss) and Comprehensive Income (Loss)


Consolidated
Statements of Deficit


Consolidated
Statements of Cash Flows


Notes to
Consolidated Financial Statements











Enterra Energy Trust Form 20 –
F







REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM






To the
Board of Directors of Enterra Energy Corp., as Administrator of Enterra Energy
Trust






We have
audited the consolidated balance sheets of Enterra Energy Trust (the “Trust”) as
at December 31, 2008 and 2007 and the consolidated statements of income (loss)
and comprehensive income (loss), deficit and cash flows for each of the years in
the three-year period ended December 31, 2008.  These financial
statements are the responsibility of the Trust's management.  Our
responsibility is to express an opinion on these financial statements based on
our audits.






We
conducted our audits in accordance with Canadian generally accepted auditing
standards. With respect to the consolidated financial statements for the years
ended December 31, 2008 and 2007, we also conducted our audits in accordance
with the standards of the Public Company Accounting Oversight Board (United
States).  Those standards require that we plan and perform an audit to
obtain reasonable assurance whether the financial statements are free of
material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.






In our
opinion, these consolidated financial statements present fairly, in all material
respects, the financial position of the Trust as at December 31, 2008 and 2007
and the results of its operations and its cash flows for each of the years in
the three-year period ended December 31, 2008 in conformity with Canadian
generally accepted accounting principles.






Canadian
generally accepted accounting principles vary in certain significant respects
from US generally accepted accounting principles. Information relating to the
nature and effect of such differences is presented in Note 21 to the
consolidated financial statements.






As
discussed in Note 3 to the consolidated financial statements, the Trust has
changed its method of accounting for financial instruments in 2008 and 2007 due
to the adoption of new Canadian standards on the presentation of financial
instruments.






We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Trust’s internal control over financial
reporting as of December 31, 2008, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO), and our report dated March 26, 2009 expressed
an unqualified opinion on the effectiveness of the Trust’s internal control over
financial reporting.






/s/
KPMG






Chartered
Accountants




Calgary,
Canada


March 26,
2009 except as to note 6 and note 21(k) which is as of June 22,
2009










Enterra Energy Trust Form 20 –
F







REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM






To the
Board of Directors of Enterra Energy Corp., as Administrator of Enterra Energy
Trust






We have
audited Enterra Energy Trust’s ("the Trust") internal control over financial
reporting as of December 31, 2008, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO).  The Trust’s management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Report.  Our
responsibility is to express an opinion on the Trust’s internal control over
financial reporting based on our audit.






We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects.  Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk.  Our
audit also included performing such other procedures as we considered necessary
in the circumstances.  We believe that our audit provides a reasonable
basis for our opinion.






An
entity’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.  An entity’s internal
control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the entity;
(2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the entity are
being made only in accordance with authorizations of management and directors of
the entity; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the entity’s
assets that could have a material effect on the financial
statements.






Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements.  Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.






In our
opinion, the Trust maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2008, based on the criteria
established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO).




We also
have audited, in accordance with Canadian generally accepted auditing standards,
the consolidated balance sheets of the Trust as of December 31, 2008 and 2007,
and the related consolidated statements of income (loss) and comprehensive
income (loss), deficit and cash flows for each of the years in the three-year
period ended December 31, 2008.  With respect to the years ended
December 31, 2008 and 2007, we also have conducted our audit in accordance with
the standards of the Public Company Accounting Oversight Board (United States).
Our report dated March 26, 2009, expressed an unqualified opinion on those
consolidated financial statements.




/s/
KPMG






Chartered
Accountants




Calgary,
Canada


March 26,
2009

















Enterra Energy Trust Form 20 –
F





Enterra
      Energy Trust
                  Consolidated
      Balance Sheets
                  As at December 31(in thousands
      of Canadian dollars)
                
                2008
                
                
                2007AssetsCurrent
      assetsCash and cash
      equivalents
                
                
                13,638
                
                
                
                3,554Accounts receivable (note 13)
                
                
                46,119
                
                
                
                30,391Prepaid expenses, deposits and
      other
                
                
                1,959
                
                
                
                2,270Commodity contracts (note 13)
                
                
                14,338
                
                
                
                607Future income tax asset (note 12)
                
                
                -
                
                
                
                2,18776,054
                
                
                
                39,009Property,
      plant and equipment (note
      4)
                
                
                491,654
                
                
                
                556,778Long
      term receivables (note
      20)
                
                
                19,310
                
                
                
                4,003587,018
                
                
                
                599,790LiabilitiesCurrent
      liabilitiesBank indebtedness (note 6)
                
                
                95,466
                
                
                
                171,953Accounts payable and accrued
      liabilities
                
                
                37,949
                
                
                
                35,763Future income tax liability
      (note
      12)
                
                
                4,187
                
                
                
                -Commodity contracts (note 13)
                
                
                -
                
                
                
                5,764Note payable (note 7)
                
                
                -
                
                
                
                711137,602
                
                
                
                214,191Convertible
      debentures (note
      9)
                
                
                113,420
                
                
                
                111,692Asset
      retirement obligations (note 8)
                
                
                22,151
                
                
                
                29,939Future
      income tax liability (note
      12)
                
                
                19,429
                
                
                
                24,784292,602
                
                
                
                380,606Unitholders’
      equity (note
      10)Unitholders’
      capital
                
                
                669,667
                
                
                
                667,690Equity component of
      convertible debentures (note 9)
                
                
                3,977
                
                
                
                3,977Warrants
                
                
                -
                
                
                
                1,215Contributed
      surplus
                
                
                8,620
                
                
                
                4,660Accumulated other
      comprehensive income (loss) (note 11)
                
                
                18,471
                
                
                
                (44,978
                )Deficit
                
                
                (406,319
                )
                
                
                (413,380
                )(387,848
                )
                
                
                (458,358
                )294,416
                
                
                
                219,184587,018
                
                
                
                599,790


Commitments
and contingencies (notes 17 and 18)


Subsequent
event (note 6)





See
accompanying notes to the consolidated financial statements.








Approved
on behalf of the Board:





Signed
“Peter
Carpenter”                                                                           Signed
“Victor
Dusik”


Director                                                                           Director








Enterra Energy Trust Form 20 –
F





Enterra
      Energy Trust
                  Consolidated
      Statements of Income (Loss) and Comprehensive Income (Loss)
                  For
      year ended December 31
                  (in
      thousands of Canadian dollars except per unit amounts)
                
                2008
                
                
                2007
                
                
                2006RevenuesOil and natural
    gas
                
                
                275,497
                
                
                
                207,036
                
                
                
                244,408Royalties
                
                
                (58,350
                )
                
                
                (45,365
                )
                
                
                (48,288
                )217,147
                
                
                
                161,671
                
                
                
                196,120ExpensesProduction
                
                
                55,846
                
                
                
                62,483
                
                
                
                48,494Transportation
                
                
                2,492
                
                
                
                2,340
                
                
                
                1,867General and
      administrative
                
                
                15,858
                
                
                
                20,414
                
                
                
                17,145Provision for non-recoverable
      receivables (note
      13)
                
                
                8,522
                
                
                
                -
                
                
                
                -Interest expense (note 14)
                
                
                17,466
                
                
                
                22,582
                
                
                
                26,717Financing fees
                
                
                -
                
                
                
                -
                
                
                
                5,447Amortization of deferred
      financing charges
                
                
                -
                
                
                
                -
                
                
                
                11,713Unit-based compensation
      expense
                
                
                4,415
                
                
                
                4,128
                
                
                
                3,229Depletion, depreciation and
      accretion (notes 4 and
      8)
                
                
                99,377
                
                
                
                150,701
                
                
                
                201,448Goodwill impairment (note 5)
                
                
                -
                
                
                
                76,463
                
                
                
                -Foreign exchange
      loss
                
                
                1,279
                
                
                
                546
                
                
                
                1,910205,255
                
                
                
                339,657
                
                
                
                317,970Income
      (loss) before taxes and non-controlling interest
                
                
                11,892
                
                
                
                (177,986
                )
                
                
                (121,850
                )Income
      taxes (note
      12)Current
                
                
                344
                
                
                
                101
                
                
                
                1,324Future
      expense (reduction)
                
                
                4,487
                
                
                
                (36,051
                )
                
                
                (58,899
                )4,831
                
                
                
                (35,950
                )
                
                
                (57,575
                )Net
      income (loss) before non-controlling interest
                
                
                7,061
                
                
                
                (142,036
                )
                
                
                (64,275
                )Non-controlling
      interest
                
                
                -
                
                
                
                -
                
                
                
                (36
                )Net
      income (loss)
                
                
                7,061
                
                
                
                (142,036
                )
                
                
                (64,239
                )Other
      comprehensive income (loss)Foreign currency translation
      adjustment (note
      11)
                
                
                63,449
                
                
                
                (46,908
                )
                
                
                1,930Comprehensive
      income (loss)
                
                
                70,510
                
                
                
                (188,944
                )
                
                
                (62,309
                )Net income (loss) per trust unit(note 10)
                  –
      Basic and diluted
                
                
                0.11
                
                
                
                (2.38
                )
                
                
                (1.46
                )CONSOLIDATED
      STATEMENTS OF DEFICIT(in
      thousands of Canadian dollars)Deficit, beginning of
      year
                
                
                (413,380
                )
                
                
                (240,777
                )
                
                
                (85,840
                )Change in accounting policy
      (note
    3)
                
                
                -
                
                
                
                1,009
                
                
                
                -Net income
(loss)
                
                
                7,061
                
                
                
                (142,036
                )
                
                
                (64,239
                )Distributions
      declared
                
                
                -
                
                
                
                (31,576
                )
                
                
                (90,698
                )Deficit,
      end of year
                
                
                (406,319
                )
                
                
                (413,380
                )
                
                
                (240,777
                )


See accompanying notes to the
consolidated financial statements.








Enterra Energy Trust Form 20 –
F





Enterra
      Energy Trust
                  Consolidated
      Statements of Cash Flows
                  For
      the year ended December 31
                  (in
      thousand of Canadian dollars)
                
                2008
                
                
                2007
                
                
                2006Cash
      provided by (used in):OperatingNet income (loss)
                
                
                7,061
                
                
                
                (142,036
                )
                
                
                (64,239
                )Depletion, depreciation and
      accretion (notes 4 and
      8)
                
                
                99,377
                
                
                
                150,701
                
                
                
                201,448Goodwill impairment (note 5)
                
                
                -
                
                
                
                76,463
                
                
                
                -Future income tax expense
      (reduction) (note
      12)
                
                
                4,487
                
                
                
                (36,051
                )
                
                
                (58,899
                )Amortization of financing
      charges
                
                
                548
                
                
                
                988
                
                
                
                11,713Commodity contracts (gain) loss
      (note
      13)
                
                
                (20,072
                )
                
                
                16,205
                
                
                
                (10,628
                )Foreign exchange
    loss
                
                
                1,279
                
                
                
                951
                
                
                
                1,038Unit-based compensation (note 10)
                
                
                4,415
                
                
                
                4,128
                
                
                
                3,229Financing fees
                
                
                -
                
                
                
                -
                
                
                
                5,065Amortization of marketing
      contract
                
                
                -
                
                
                
                -
                
                
                
                (1,447
                )Non-controlling
      interest
                
                
                -
                
                
                
                -
                
                
                
                (36
                )Non-cash interest on convertible
      debentures
                
                
                1,728
                
                
                
                1,339
                
                
                
                33Loss on sale of
    assets
                
                
                -
                
                
                
                -
                
                
                
                59Cash paid on asset retirement
      obligations (note
      8)
                
                
                (1,771
                )
                
                
                (2,225
                )
                
                
                (1,219
                )97,052
                
                
                
                70,463
                
                
                
                86,117Changes in non-cash working
      capital items (note
      15)
                
                
                (5,492
                )
                
                
                6,381
                
                
                
                (21,632
                )91,560
                
                
                
                76,844
                
                
                
                64,485FinancingIncrease in bank
      indebtedness
                
                
                -
                
                
                
                -
                
                
                
                587,818Repayment of bank
      indebtedness
                
                
                (76,487
                )
                
                
                (15,495
                )
                
                
                (510,353
                )Proceeds from (repayment of)
      notes, net
                
                
                (742
                )
                
                
                878
                
                
                
                (3,990
                )Distributions
    paid
                
                
                -
                
                
                
                (39,486
                )
                
                
                (90,487
                )Issuance of convertible
      debentures, net of issuancecosts
                
                
                -
                
                
                
                37,514
                
                
                
                138,000Issue of trust units, net of
      issuance costs (note
      10)
                
                
                (97
                )
                
                
                27,438
                
                
                
                50,391Capital lease
                
                
                -
                
                
                
                (1,702
                )
                
                
                (878
                )Financing fees
                
                
                -
                
                
                
                -
                
                
                
                (22,405
                )Due to JED Oil
    Inc.
                
                
                -
                
                
                
                -
                
                
                
                (2,009
                )Exercise of trust unit
      options
                
                
                -
                
                
                
                -
                
                
                
                1,399(77,326
                )
                
                
                9,147
                
                
                
                147,486InvestingProperty, plant and equipment
      additions
                
                
                (32,891
                )
                
                
                (25,066
                )
                
                
                (30,918
                )Capital expenditure to be
      recovered (note
      20)
                
                
                (19,976
                )
                
                
                (6,724
                )
                
                
                -Repayment of long-term
      receivable (note
      20)
                
                
                5,049
                
                
                
                1,105
                
                
                
                -Proceeds on disposal of
      property, plant andequipment
                
                
                39,553
                
                
                
                11,349
                
                
                
                6,586Acquisition of Trigger
      Resources (note
      4)
                
                
                -
                
                
                
                (63,257
                )
                
                
                -Acquisition of Oklahoma assets
      (note
    4)
                
                
                -
                
                
                
                -
                
                
                
                (182,183
                )Changes in non-cash working
      capital items (note
      15)
                
                
                4,465
                
                
                
                (1,778
                )
                
                
                (7,645
                )(3,800
                )
                
                
                (84,371
                )
                
                
                (214,160
                )Impact
      of foreign exchange on cash balances
                
                
                (350
                )
                
                
                (228
                )
                
                
                (7,592
                )Change
      in cash and cash equivalents
                
                
                10,084
                
                
                
                1,392
                
                
                
                (9,781
                )Cash
      and cash equivalents, beginning of year
                
                
                3,554
                
                
                
                2,162
                
                
                
                11,943Cash
      and cash equivalents, end of year
                
                
                13,638
                
                
                
                3,554
                
                
                
                2,162


See accompanying notes to the
      consolidated financial
statements.





Enterra Energy Trust Form 20 –
F





1.
            Basis
      of presentation





Enterra
Energy Trust (the “Trust”) was established in November 2003.  The
Trust is an open-end unincorporated investment trust governed by the laws of the
province of Alberta and created pursuant to a trust indenture (the “Trust
Indenture”).  The purpose of the Trust is to indirectly hold interests
in petroleum and natural gas properties, through notes from, and investments in
securities of its subsidiaries.  The beneficiaries of the Trust are
the holders of trust units issued by the Trust (the “unitholders”).





These
consolidated financial statements include the accounts of the Trust and its
subsidiaries (collectively the “Trust” or “Enterra” for purposes of the
following notes to the consolidated financial statements).  All
inter-company accounts and transactions have been eliminated.








2.
            Significant
      accounting policies





Management
      has prepared the consolidated financial statements in accordance with
      Canadian generally accepted accounting principles (“GAAP”).  The
      following significant accounting policies are presented to assist the
      reader in evaluating these consolidated financial statements, and together
      with the following notes, should be considered an integral part of the
      consolidated financial statements.





(a)
            Basis
      of accounting





Substantially
all exploration, development and production activities related to the oil and
gas business are conducted jointly with others and the accounts reflect only
Enterra’s interest therein.





(b)
            Cash
      and cash equivalents




Cash and
cash equivalents consists of cash on hand and balances invested in short-term
securities with original maturities less than 90 days at the date of
acquisition.





(c)
            Revenue
      recognition





Revenue
associated with the sale of crude oil, natural gas and natural gas liquids is
recognized when title passes from the Trust to its customers based on contracts
which establish the price of products sold and when collection is reasonably
assured.





(d)
            Petroleum
      and natural gas properties





Enterra
follows the “full cost” method of accounting for petroleum and natural gas
properties.  All costs related to the exploration for and the
development of oil and gas reserves are capitalized into one of two cost
centers, Canada or the United States.  Costs capitalized include land
acquisition costs, geological and geophysical expenditures, lease rentals on
undeveloped properties and costs of drilling productive and non-productive wells
and production equipment.





General
and administrative costs are capitalized if they are directly related to
development or exploration projects.





Proceeds
from the disposal of oil and natural gas properties are applied as a reduction
of cost without recognition of a gain or loss except where such disposals would
result in a 20% change in the depletion rate.





Repair
and maintenance costs are expensed as incurred.





(e)
            Impairment
      test





The Trust
places a limit on the carrying value of property and equipment, which may be
depleted against revenues of future periods (the “ceiling test”).  The
ceiling test is conducted separately for each cost center, Canada and the United
States.  The carrying value is assessed to be recoverable when the sum
of the undiscounted cash flows expected from the production of proved reserves,
the lower of cost and market of unproved properties and the cost of major
development projects exceeds the carrying value of the cost
center.  When the carrying value is not assessed to be recoverable, an
impairment loss is recognized to the extent that the carrying value of petroleum
and natural gas properties exceeds the sum of the discounted cash flows expected
from the production of proved and probable reserves, the lower of cost and
market of unproved properties and the cost of major development
projects.





Enterra Energy Trust Form 20 –
F





The cash
flows are estimated using expected future product prices and costs and are
discounted using a risk-free interest rate.





(f) Use of
estimates





The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities, and the disclosure of
contingent assets and liabilities at the dates of the financial statements and
the reported amounts of revenue and expenses during the reporting
periods.





The
amounts recorded for depletion, depreciation and the asset retirement obligation
are based on estimates.  The ceiling test calculation is based on
estimates of reserves, oil and natural gas prices, future costs and other
relevant assumptions.  By their nature, these estimates are subject to
measurement uncertainty and may impact the consolidated financial statements of
future periods.





The
amounts recorded for financial derivatives are based on estimates of the price
for oil and natural gas in future periods.  These estimates are
subject to fluctuations in market prices and will impact the consolidated
financial statements of future periods.





(g) Depletion and
depreciation





The
provision for depletion of petroleum and natural gas properties is calculated,
by cost center, using the unit-of-production method based on the Enterra’s share
of estimated proved reserves before royalties.  Natural gas reserves
and production are converted to equivalent units of crude oil using their
approximate relative energy content.





Office
furniture and equipment is depreciated on a 20% declining balance
basis.





(h)           Goodwill





Enterra
recognizes goodwill relating to acquisitions when the total purchase price
exceeds the fair value of the net identifiable assets and liabilities
acquired.  The goodwill balance is assessed for impairment annually at
year-end or as events occur that could result in impairment.  To
assess impairment, the estimated fair value of a reporting unit is compared to
its book value.  If the fair value is less than the book value, a
second test is performed to determine the amount of impairment.  The
amount of impairment is measured by allocating the estimated fair value to a
reporting unit’s identifiable assets and liabilities as if it had been acquired
in a business combination for a purchase price equal to its estimated fair
market value.  If goodwill determined in this manner is less than the
carrying value of goodwill, an impairment loss is recognized in the period in
which it occurs.  Goodwill is stated at cost less
impairment.  Goodwill was tested for impairment separately for the
Canadian and the United States reporting units.





(i) Asset
retirement obligations





Enterra
recognizes a liability for the estimated fair value of the future retirement
obligations associated with property and equipment.  The fair value of
the estimated asset retirement obligations is recorded as a liability with a
corresponding increase in the carrying amount of the related
asset.  The capitalized amount is depleted on the unit-of-production
method based on proved reserves.  The Trust estimates the liability
based on the estimated costs to abandon and reclaim its net ownership interest
in all wells and facilities and the estimated timing of the costs to be incurred
in future periods.  This estimate is evaluated on a periodic basis and
any adjustment to the estimate is prospectively applied.  As time
passes, the change in net present value of the future retirement obligation is
expensed through accretion.  Retirement obligations settled during the
period reduce the future retirement liability.





(j) Income
taxes





Enterra
follows the asset and liability method of accounting for income
taxes.  Under this method, income tax liabilities and assets are
recognized based on the differences between the amounts reported in the
financial statements and their respective tax bases, using enacted or
substantively enacted income tax rates.  The effect of a change in
income tax rates on future income tax liabilities and assets is recognized in
income in the period that the change occurs.  Future tax assets are
recognized to the extent they are more likely than not to be
realized.





The Trust
is a taxable entity under the Canadian Income Tax Act and is currently taxable
only on income that is not distributed or distributable to the
unitholders.  In 2007, changes to Canadian tax legislation resulted in
a new tax on distributions from publicly traded income trusts commencing in
2011.  This has resulted in the recognition of future





Enterra Energy Trust Form 20 –
F





income
taxes at the trust level.  Prior to 2007, future income taxes were
recognized only on the corporate subsidiaries of the Trust.





(k)           Commodity
contracts





Enterra
uses commodity contracts such as collars, floors, calls and swaps to manage its
exposure to commodity price fluctuations.  Actual amounts received, or
paid, on the settlement of the commodity contracts are recorded in oil and gas
revenue.  Enterra uses the fair value method for reporting commodity
contracts whereby a derivative financial instrument is recorded as an asset or a
liability on the balance sheet, and changes in the fair value during a financial
period are recorded in oil and natural gas revenue.





(l) Trust unit
compensation plans





Enterra
has multiple unit based compensation plans, which are described in note
10.  Compensation expense associated with each unit based compensation
plan is recognized in earnings over the vesting period of the plan with a
corresponding increase in contributed surplus.  Any consideration
received upon the exercise of the unit based compensation together with the
amount of non-cash compensation expense recognized in contributed surplus is
recorded as an increase in unitholders’ capital.  Compensation expense
is based on the estimated fair value of the unit based compensation at the date
of grant.





(m)           Foreign
currency transactions





Transactions
completed in foreign currencies are reflected in Canadian dollars at the foreign
currency exchange rates prevailing at the time of the
transactions.  Current assets and liabilities denominated in foreign
currencies are reflected in the financial statements at the Canadian equivalent
at the rate of exchange prevailing at the balance sheet date.  Gains
and losses are included in earnings.





The U.S.
subsidiaries of Enterra are considered to be "self sustaining
operations".  As a result, the revenues and expenses are translated to
Canadian dollars using average exchange rates for the period.  Assets
and liabilities are translated at the period-end exchange rate.  Gains
or losses resulting from the translation are included in accumulated other
comprehensive income (loss) in unitholders’ equity.





(n)           Per
unit amounts





Per unit
amounts are calculated using the weighted average number of units
outstanding.  The Trust follows the treasury stock method to determine
dilutive effect of options, warrants and other dilutive
instruments.  Under the treasury stock method, only “in-the-money”
dilutive instruments impact the diluted calculations.  Convertible
debentures are included in the calculation of diluted income per unit based on
the number of trust units that would be issued on conversion of the convertible
debentures at the end of the year and an add-back of the associated interest
expense for the year as long as the conversion results in a dilution to the
Trust.





(o)           Environmental
liabilities





The Trust
records liabilities on an undiscounted basis for environmental remediation
efforts that are likely to occur and where the cost can be reasonably
estimated.  The estimates, including legal costs, are based on
available information using existing technology and enacted laws and
regulations.  The estimates are subject to revision in future periods
based on actual costs incurred or new circumstances.  Any amounts
expected to be recovered from others, including insurance coverage, are recorded
as an asset separate from the associated liability.





(p)           Non-controlling
interest





Enterra
had, through its subsidiaries four types of exchangeable shares that were
classified as non-controlling interest on the consolidated balance
sheets.  Income after tax attributable to these exchangeable shares is
deducted from net earnings of Enterra on the consolidated statement of
loss.





When the
Enterra Energy Corp. exchangeable shares were exchanged for trust units, they
were measured at the fair value of the trust units issued.  The
amounts in excess of the carrying value of exchangeable shares were allocated to
property, plant and equipment, to the extent possible, with any excess amounts
being allocated to goodwill.  When the other exchangeable shares,
which were initially recorded at estimated fair value, were exchanged for trust
units, they were measured at their carrying value.








Enterra Energy Trust Form 20 –
F





(q) Deferred financing
charges





Prior to
January 1, 2007, deferred financing charges were amortized over the lives of the
related debt.  Subsequent to January 1, 2007 transactions costs are
recorded net of the related financing and amortized using the effective interest
method.





(r) Comparative
figures





Certain
comparative figures have been reclassified to conform with the presentation
adopted in the current year.








3.      Adoption
of new accounting standards





Adopted
in 2008





Financial
instrument and capital disclosures





The CICA
issued the following accounting standards effective for fiscal years beginning
on or after January 1, 2008:  Section 1535 “Capital Disclosures”,
Section 3862 “Financial Instruments – Disclosures” and Section 3863 “Financial
Instruments – Presentation”.





Section
1535 “Capital Disclosures” requires Enterra to provide disclosures about the
capital of Enterra and how it is managed.





Section
3862 “Financial Instruments – Disclosures” and Section 3863 “Financial
Instruments – Presentation” replace Section 3861 “Financial Instruments -
Disclosure and Presentation”, revising disclosures related to financial
instruments, including hedging instruments, and carrying forward unchanged
presentation requirements.





The
adoption of these new accounting standards did not impact the amounts reported
in the financial statements of Enterra; however, it did result in expanded note
disclosure (see note 13 and note 16).





Adopted
in 2007





Effective
January 1, 2007, Enterra adopted new Canadian accounting standards and related
amendments to other standards on financial instruments.




i.           Financial
instruments – recognition and measurement




The
Trust's cash and cash equivalents, investments in marketable securities and
commodity contracts have been classified as held for trading and are recorded at
fair value on the balance sheet.  Changes in the fair value of these
instruments are recorded in net income.  All other financial
instruments are recorded at cost or amortized cost, subject to impairment
reviews.  At December 31, 2008 and 2007 there were no held to maturity
or available for sale financial assets.  Enterra has not voluntarily
elected to record any financial instruments as held for trading.




The
Trust’s physical purchase and sale contracts have been designated as derivatives
and are recorded at estimated fair value on the balance sheet with changes in
estimated fair value each period charged to earnings.




Embedded
derivatives that do not meet certain exemptions are also required to be
separately accounted for at fair value with changes in fair value included in
earnings.  Enterra elected January 1, 2007 as the effective date for
assessing embedded derivatives.  There are no significant embedded
derivatives that required separate accounting for the years ended December 31,
2008 and 2007.




Transaction
costs on the convertible debentures are presented net of the related debt and
amortized to earnings using the effective interest method.




ii.
            Comprehensive
      income




Comprehensive
income includes net loss, holding gains and losses on available for sale
investments, gains and losses on cash flow hedges and foreign currency gains and
losses relating to self-sustaining foreign operations, all of which are not
included in the calculation of earnings until realized.





Enterra Energy Trust Form 20 –
F







The
impact of adopting these standards at January 1, 2007 were as
follows:







(in
      thousands of Canadian dollars)
                
                As
      reported
                
                
                Adjustments
                
                
                
                As
      adjustedAssets:Current
      assets
                
                
                55,166
                
                
                
                2,637
                
                (a)(b)
                
                
                57,803Deferred
      finance charges
                
                
                4,676
                
                
                
                (4,676
                )
                (b)
                
                
                -Liabilities:Convertible
      debentures
                
                
                78,974
                
                
                
                (3,481
                )
                (b)
                
                
                75,493Future
      income tax
                
                
                40,340
                
                
                
                432
                
                (a)
                
                
                40,772Unitholders’
      equityCumulative
      translation adjustment
                
                
                1,930
                
                
                
                (1,930
                )
                (c)
                
                
                -Deficit
                
                
                (240,777
                )
                
                
                1,009
                
                (a)
                
                
                (239,768
                )Accumulated
      other comprehensive income
                
                
                -
                
                
                
                1,930
                
                (c)
                
                
                1,930




Notes:




(a)
Physical purchase and sale contracts have been designated as derivatives and are
measured at their estimated fair value of $1.4 million with the offset, as
required on adoption of the new standards, included in retained earnings ($1.0
million net of income taxes).




(b)
Convertible debenture financing costs of $3.5 million, previously classified as
deferred financing charges, are reclassified to convertible
debentures.  Financing fees of $1.2 million have been reclassified to
prepaid expenses and are amortized over the term of the related credit
facilities.




(c) The
cumulative translation adjustment is reclassified to accumulated other
comprehensive income.  The cumulative translation adjustment as at
December 31, 2006 was reclassified to accumulated other comprehensive income as
required by the new standards.





Future
accounting policies to be adopted





When
Enterra has not adopted a new accounting standard that has been issued but not
yet effective, the entity is required to disclose (a) this fact; and (b) known
or reasonably estimable information relevant to assessing the possible impact
that application of the new standard will have on the Trust’s financial
statements in the period of initial application.





In
December 2008, the CICA issued a new accounting standard for “Business
Combinations”.  This standard outlines new guidance which states that
the purchase price is to be based on trading data at the closing date of the
acquisition, not the announcement date of the acquisition, and that most
acquisition costs are to be expensed as incurred.  The new standard
becomes effective on January 1, 2011 and early adoption is
permitted.  This standard will require the Trust to change its
accounting policies for any new business combinations completed after the
standard is adopted.





In
February 2008, the Canadian Institute of Chartered Accountants confirmed that
Canadian GAAP for publicly accountable enterprises will be converted to
International Financial Reporting Standards (IFRS) on January 1,
2011.  This change in GAAP will be effective for years beginning
January 1, 2011.





In
December 2007, the SEC announced that the U.S. GAAP reconciliations requirement
will be waived for Foreign Private Issuers who file financial statements
prepared in accordance with IFRS for years beginning on or after January 1,
2009.





The Trust
is currently assessing the impact of the conversion from Canadian GAAP to IFRS
on the results of operations, financial position and disclosures.  A
project team has been set up to manage this transition and to ensure successful
implementation within the required timeframe.  The Trust will provide
disclosures of key elements of its plan and progress on the project as the
information becomes available during the transition period.





Enterra Energy Trust Form 20 –
F








4.      Property,
plant and equipment





(in
      thousands of Canadian dollars)
                
                2008
                
                
                2007Oil
      and natural gas properties, including production and processing
      equipment
                
                
                1,107,992
                
                
                
                1,069,891Accumulated
      depletion and depreciation
                
                
                616,338
                
                
                
                513,113Net
      book value
                
                
                491,654
                
                
                
                556,778





At
December 31, 2008 costs of undeveloped land and seismic of $11.8 million (2007 -
$18.6 million; 2006 - $25.9 million) were excluded from and $3.0 million (2007 -
$11.8 million; 2006 - $8.0 million) of future development costs were added to
the Canadian cost centre for purposes of the calculation of depletion
expense.  At December 31, 2008 costs of undeveloped land of $11.9
million (2007 - $7.8 million; 2006 - $16.8 million) were excluded from and $3.7
million (2007 - $3.0 million; 2006 - $3.0 million) of future development costs
were added to the U.S. cost centre for purposes of the calculation of depletion
expense.





Depletion
and depreciation expense related to the Canadian and the U.S. cost centers in
2008 were $61.7 million and $35.8 million respectively (2007 – $77.7 million and
$44.5 million; 2006 – $90.7 million and $42.6 million).





During
2008 $1.8 million of general and administrative expenses and $0.6 million
(including future taxes of $0.2 million) of unit-based compensation were
capitalized and included in the cost of the petroleum and natural gas properties
(2007 - $1.1 million and nil; 2006 – nil and nil, respectively).





The
following table summarizes the benchmark prices used in the ceiling test
calculation.  The petroleum and natural gas prices are based on the
December 31, 2008 commodity price forecast of Enterra’s independent reserve
engineers.





Year
            WTI
      Oil
              ($U.S./bbl)
            Foreign
              Exchange
              Rate
      (US$/CAD)
            Edmonton
      Light
              Crude
      Oil
              ($Cdn/bbl)
            AECO
      Gas
              ($Cdn/GJ)
            Henry
      Hub
              ($U.S./Mmbtu)2009
            60.00
            0.850
            69.60
            7.40
            7.252010
            71.40
            0.850
            83.00
            8.00
            7.752011
            83.20
            0.900
            91.40
            8.45
            8.602012
            90.20
            0.950
            93.90
            8.80
            9.352013
            97.40
            1.000
            96.30
            9.05
            10.102014
            99.40
            1.000
            98.30
            9.25
            10.30Escalate
              Thereafter
            Average
              2%
      per year
            1.000
            Average
              2%
      per year
            Average
              2%
      per year
            Average
              2%
      per year





Enterra
completed ceiling test calculations for the Canadian and U.S. cost centers at
December 31, 2008 to assess the recoverability of costs recorded in respect of
the petroleum and natural gas properties.  The ceiling test did not
result in a write down of the Canadian cost center or the U.S. cost center (2007
- $26.3 million write down in the Canadian cost center and no write down in the
U.S. cost center; 2006 - $48.8 million write down in the Canadian cost center
and $17.2 million write down in the U.S. cost center).  Ceiling test
write downs are included in depletion expense.





Acquisition
of Trigger Resources





On April
30, 2007 Enterra acquired all of the issued and outstanding shares of Trigger
Resources Ltd. (“Trigger Resources”) for total consideration of $63.3
million.  Trigger was acquired to provide additional exposure to oil
and gas developments in Saskatchewan and expand the Trust’s undeveloped
acreage.








Enterra Energy Trust Form 20 –
F





The
acquisition was accounted for using the purchase method of accounting with the
allocation of the purchase price and consideration paid as follows:





(in
      thousands of Canadian dollars)Allocation
      of purchase price:Current
      assets
                
                $
                2,806Property,
      plant and equipment
                
                
                81,382Current
      liabilities
                
                
                (2,781
                )Future
      income tax liability
                
                
                (15,576
                )Asset
      retirement obligations
                
                
                (2,574
                )$
                63,257





(in
      thousands of Canadian dollars)Consideration:Cash
                
                $
                62,965Transaction
      costs
                
                
                292$
                63,257





Acquisition
of Oklahoma Assets





During
2006, Enterra acquired oil and natural gas properties located in Oklahoma
(“Oklahoma Assets”).  The acquisition was completed in four
stages.





Prior to
closing the acquisitions, the Trust acquired $49.7 million of notes payable by
the primary vendors of the Oklahoma Assets; as a result the vendors owed the
Trust $49.7 million.  The primary vendors repaid the Trust $38.5
million of the notes upon closing the second stage of the acquisition of the
Oklahoma Assets.  The acquisition of the notes, by the Trust, was
financed with a US$50.0 million senior bridge credit facility.





On
January 18, 2006, the Trust closed the first stage of the acquisition of the
Oklahoma Assets.  The results of the operations of the assets acquired
are included in the Trust’s consolidated financial statements as of January 18,
2006.





On March
21, 2006, the Trust closed the second stage of the acquisition of the Oklahoma
Assets.  Along with the second stage, the Trust acquired the operating
company of the Oklahoma Assets.  The results of operations of the
assets acquired and the operating company are included in the Trust’s
consolidated financial statements as of March 21, 2006.





On April
4, 2006, the Trust closed the third stage of the acquisition of the Oklahoma
Assets.  The results of operations of the assets acquired are included
in the Trust’s consolidated financial statements as of April 4,
2006.





On April
18, 2006, the Trust closed the fourth stage of the acquisition of the Oklahoma
Assets.  The results of operations of the assets acquired are included
in the Trust’s consolidated financial statements as of April 18,
2006.





The
acquisition was accounted for using the purchase method of accounting with the
allocation of the purchase price and consideration paid as follows:





Allocation
      of purchase price:Current
      assets
                
                $
                6,412Property,
      plant and equipment
                
                
                352,999Current
      liabilities
                
                
                (25,355
                )Financial
      derivatives
                
                
                (485
                )Debt
                
                
                (24,036
                )Asset
      retirement obligations
                
                
                (1,926
                )$
                307,609





Cost
      of acquisitions:Cash
      paid and payable
                
                $
                181,044Transaction
      costs
                
                
                10,0405,685,028
      trust units
                
                
                116,525$
                307,609





The value
assigned to each trust unit of $20.51 (US$17.70) was based on the weighted
average trading price immediately prior to the measurement date.  The
acquisition provides cash flows from currently producing assets and provides the
opportunity for the exploitation of the undeveloped lands.





As a
result of adjustments to the purchase price, as determined by the purchase and
sale agreement, Enterra owed $1.4 million (US$1.5 million) to the vendors as at
December 31, 2007 ($8.9 million (US$7.6 million) in 2006).








5.      Goodwill





During
2007 Enterra recorded a goodwill impairment loss of $76.5 million (2006 – nil)
relating to the Canadian reporting unit.  The goodwill impairment loss
was a result of the Enterra’s net book value exceeding Enterra’s market
capitalization.








6.      Debt




(in
      thousands of Canadian dollars)
                
                2008
                
                
                2007Revolving
      credit facility
                
                
                90,000
                
                
                
                129,500Operating
      credit facility
                
                
                5,466
                
                
                
                2,116Second-lien
      facility
                
                
                -
                
                
                
                40,000Other
                
                
                -
                
                
                
                337Bank
      indebtedness
                
                
                95,466
                
                
                
                171,953





On June
25, 2008 Enterra entered into credit facilities with its banking syndicate that
includes revolving and operating credit facilities which had a borrowing
capacity of $135.0 million and a second-lien credit facility with a maximum of
$12.0 million at December 31, 2008.  The second-lien facility was
undrawn and was cancelled in June 2009 at Enterra’s option.  The
Trust’s Bank Syndicate completed a mid-year borrowing base review in June 2009
and adjusted the borrowing base to $110.0 million.  The next scheduled
annual review of the borrowing base is anticipated to be completed in Q1 2010
and there may be an interim review in the latter part of
2009.  Changes to the amount of credit available may be made after
these reviews are completed.  The revolving and operating credit
facilities are secured with a first priority charge over the assets of
Enterra.  Borrowings under the revolving and operating credit
facilities at December 31, 2008 were $95.5 million with no borrowings under the
second-lien facility.  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.




Interest
rates for the credit facilities are set quarterly according to a grid based on
the ratio of bank debt with respect to cash flow with the lowest rates in the
grid being Canadian dollar BA (“Bankers Acceptance”) or U.S. dollar LIBOR rates
plus a margin of 3.00%, effective with the June 2009 renewal of the credit
facilities.  As at December 31, 2008, borrowings under the revolving
and operating credit facilities were at Canadian dollar BA or U.S. dollar LIBOR
rates plus a margin of 1.25%, or Canadian or U.S. prime rates plus a margin
of 0.25% depending on the form of borrowing.




As at
December 31, 2008 all borrowings under the facilities were denominated in
Canadian dollars and interest was being accrued at a rate of 3.75% per
annum.  At December 31, 2008, letters of credit totaling $0.5 million
reduced the amount that can be drawn under the operating credit
facility.




The
second-lien credit facility was a non-revolving credit facility and is
subordinated to the revolving and the operating credit facilities and as at
December 31, 2008 had not been drawn down.  The facility bore interest
according to a grid similar to the above and as of December 31, 2008 borrowings
were at Canadian dollar BA or







Enterra Energy Trust Form 20 –
F





U.S.
dollar LIBOR rates plus a margin of 3.50%, or Canadian or U.S. prime rates
plus a margin of 2.50% depending on the form of borrowing.




During
2008, Enterra repaid the other debt which had a balance of $0.3 million at
December 31, 2007.




Enterra
is required to maintain several financial and non-financial covenants and an
interest coverage ratio of 3.0:1.0 as calculated pursuant to the terms of the
credit agreement.  In addition, distributions are limited to 100% of
cash flow, as defined in the credit agreement, once distributions are permitted
to be paid pursuant to the restrictions under the second-lien
facility.  The Trust is in compliance with the terms and covenants of
the credit facilities as at December 31, 2008.




At
December 31, 2007, Enterra had a revolving extendible credit facility of $140.0
million and a $40.0 million second-lien non-revolving credit
facility.  The credit facilities were further amended subsequent to
December 31, 2007 such that Enterra had available $129.5 million revolving
extendible facility, an $18.5 million operating facility and a $40.0 million
second-lien non-revolving facility.







7.      Note
payable and capital lease





Note
payable


Enterra
had a note payable that was for the purchase of certain natural gas interests in
the U.S. which was repaid in full during the first quarter of 2008.





Capital
lease


During
2007 and 2006, the capital lease bore a rate of interest of 8.6% and was
repayable in monthly installments of $0.1 million, including interest with a
final payment of $1.0 million.  The lease term was for 60 months
ending on October 1, 2007.    Interest expense on the lease
in 2007 was $0.2 million (2006 - $0.2 million).








8.      Asset
retirement obligations





The asset
retirement obligations were estimated by management based on Enterra’s working
interests in its wells and facilities, estimated costs to remediate, reclaim and
abandon the wells and facilities and the estimated timing of the costs to be
incurred.  At December 31, 2008, the asset retirement obligation is
estimated to be $22.2 million (2007 – $29.9 million), based on a total future
liability of $39.2 million (2007 - $49.4 million).  These obligations
will be settled at the end of the useful lives of the underlying assets, which
currently averages six years, but extends up to 18 years into the
future.  This amount has been calculated using an inflation rate of
2.0% and discounted using a credit-adjusted interest rate of 8.0% to
10.0%.





The
following table reconciles the asset retirement obligations:





(in
      thousands of Canadian dollars)
                
                2008
                
                
                2007
                
                
                2006Balance,
      beginning of year
                
                
                29,939
                
                
                
                28,447
                
                
                
                24,323Acquisitions
                
                
                -
                
                
                
                2,574
                
                
                
                1,926Additions
                
                
                223
                
                
                
                2,108
                
                
                
                1,281Revisions
                
                
                -
                
                
                
                -
                
                
                
                2,000Accretion
      expense
                
                
                1,892
                
                
                
                2,182
                
                
                
                2,166Dispositions
                
                
                (8,712
                )
                
                
                (2,130
                )
                
                
                -Costs
      incurred
                
                
                (1,771
                )
                
                
                (2,225
                )
                
                
                (3,178
                )Foreign
      exchange
                
                
                580
                
                
                
                (1,017
                )
                
                
                (71
                )Balance,
      end of year
                
                
                22,151
                
                
                
                29,939
                
                
                
                28,447








9.      Convertible
debentures





On April
26, 2007, the Trust issued $40.0 million of convertible debentures with a face
value of $1,000 per convertible debenture that mature on June 30, 2012, bear
interest at 8.25% per annum paid semi-annually on June 30 and December 31 of
each year and are subordinated to the bank credit facilities.  The
convertible debentures are convertible at the option of the holder into trust
units at any time prior to the maturity date at the conversion price of $6.80
per trust unit.  During 2008 and 2007, there were no conversions of
the debentures.





Enterra Energy Trust Form 20 –
F








On
November 21, 2006, the Trust issued $138.0 million of convertible debentures
that mature on December 31, 2011, bear interest at 8% per annum paid
semi-annually on June 30 and December 31 of each year and are subordinated to
the bank credit facilities.  The convertible debentures are
convertible at the option of the holder into trust units at any time prior to
the maturity date at the conversion price of $9.25 per trust
unit.  During 2008 and 2007, there were no conversions of the
debentures.





At the
option of the Trust, the repayment of the principal portion of the convertible
debentures may be settled in trust units.  The number of trust units
issued upon redemption by the Trust will be calculated by dividing the principal
by 95% of the weighted average trading price of trust units.  The
8.25% convertible debentures are not redeemable on or before June 30, 2010 (8% -
December 31, 2009).  On or after July 1, 2010 and prior to maturity,
the convertible debentures may be redeemed in whole or in part from time to time
at the option of the Trust on not more than 60 days and not less than 30 days
notice, at a redemption price of $1,050 per convertible debenture on or after
July 1, 2010  (8% - January 1, 2010) and, on or before June 30, 2011
(8% - January 1, 2010), at a redemption price of $1,025 per convertible
debenture and on or after July 1, 2011  (8% - January 1, 2011) and
prior to maturity, in each case, plus accrued and unpaid interest thereon, if
any.  At December 31, 2008, the Trust had $80.3 million in 8%
convertible debentures (2007 - $80.3 million) outstanding with an estimated fair
value of $50.6 million (2007 - $66.6 million) and $40.0 million in 8.25%
convertible debentures (2007 - $40.0 million) outstanding with an estimated fair
value of $25.4 million (2007 - $32.0 million).








(in
      thousands of Canadian dollars)
              
              8%
      Series
              
              
              8.25%
      Series
              
              
              Total
              
              
              Equity
      ComponentNovember
      21, 2006 issuance
              
              
              138,000
              
              
              
              -
              
              
              
              138,000
              
              
              
              -Portion
      allocated to equity
              
              
              (2,387
              )
              
              
              -
              
              
              
              (2,387
              )
              
              
              2,387Issue
      costs
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (107
              )Accretion
              
              
              33
              
              
              
              -
              
              
              
              33
              
              
              
              -Converted
      to trust units
              
              
              (56,672
              )
              
              
              -
              
              
              
              (56,672
              )
              
              
              (953
              )Balance,
      December 31, 2006
              
              
              78,974
              
              
              
              -
              
              
              
              78,974
              
              
              
              1,327April
      28, 2007 issuance
              
              
              -
              
              
              
              40,000
              
              
              
              40,000
              
              
              
              -Portion
      allocated to equity
              
              
              -
              
              
              
              (2,765
              )
              
              
              (2,765
              )
              
              
              2,765Issue
      costs reclassified against carrying value (note 3)
              
              
              (3,481
              )
              
              
              -
              
              
              
              (3,481
              )
              
              
              -Issue
      costs
              
              
              (305
              )
              
              
              (2,069
              )
              
              
              (2,374
              )
              
              
              (115
              )Accretion
              
              
              844
              
              
              
              494
              
              
              
              1,338
              
              
              
              -Balance,
      December 31, 2007
              
              
              76,032
              
              
              
              35,660
              
              
              
              111,692
              
              
              
              3,977Accretion
              
              
              930
              
              
              
              798
              
              
              
              1,728
              
              
              
              -Balance,
      December 31, 2008
              
              
              76,962
              
              
              
              36,458
              
              
              
              113,420
              
              
              
              3,977





The
unsecured convertible debentures are classified as debt with a portion of the
proceeds allocated to equity representing the value of the conversion
option.  If the debentures are converted to trust units, the debt and
equity components are transferred to unitholders’ capital.  The debt
balance associated with the convertible debentures accretes over time to the
amount owing on maturity with such increases reflected as non-cash interest
expense in the consolidated statement of income.








10.           Unitholders’
equity





Authorized
trust units


An
unlimited number of trust units may be issued.





The trust
units are redeemable at the option of the holder based on the lesser of 90% of
the average market trading price of the trust units for the 10 trading days
after the date of redemption or the closing market price of the trust units on
the date of redemption.  Trust units can be redeemed to a cash limit
of $0.1 million per year or a greater limit at the discretion of the
Trust.  Redemptions in excess of the cash limit shall be satisfied
first by the issuance of notes by a subsidiary of the Trust and second by
issuance of promissory notes by the Trust.








Enterra Energy Trust Form 20 –
F





Issued
trust units


(in
      thousands of Canadian dollars except unit amounts)
                
                Number
      of Units
                
                
                AmountBalance
      at December 31, 2005
                
                
                36,504,416
                
                
                
                373,761Issued
      for cash pursuant to private placements
                
                
                657,500
                
                
                
                12,544Issued
      on acquisition of Oklahoma Assets
                
                
                5,685,028
                
                
                
                116,525Issued
      for cash pursuant to prospectus offering
                
                
                4,979,500
                
                
                
                40,334Issued
      on conversion of convertible debentures
                
                
                6,234,483
                
                
                
                57,625Issued
      as financing fees on bridge credit facilities
                
                
                116,054
                
                
                
                2,077Issued
      for exchangeable shares
                
                
                1,779,184
                
                
                
                36,502Issued
      under restricted unit plan
                
                
                41,805
                
                
                
                579Issued
      on exercise of options
                
                
                99,905
                
                
                
                1,427Unit
      issue costs
                
                
                -
                
                
                
                (6,240
                )Balance
      at December 31, 2006
                
                
                56,097,875
                
                
                
                635,134Issued
      for cash pursuant to prospectus offering
                
                
                4,945,000
                
                
                
                29,176Issued
      as financing fees related to the retirement of the 2006 bridge credit
      facilities
                
                
                50,000
                
                
                
                515Issued
      for exchangeable shares
                
                
                104,429
                
                
                
                1,940Issued
      under restricted unit plan
                
                
                238,591
                
                
                
                2,663Unit
      issue costs
                
                
                -
                
                
                
                (1,738
                )Balance
      at December 31, 2007
                
                
                61,435,895
                
                
                
                667,690Issued
      under restricted unit plan
                
                
                723,092
                
                
                
                2,074Unit
      issue costs
                
                
                -
                
                
                
                (97
                )Balance
      at December 31, 2008
                
                
                62,158,987
                
                
                
                669,667





Warrants


In April
2005 as part of an agreement to issue equity, the Trust granted warrants to
Kingsbridge Capital Limited to purchase 301,000 trust units.  The
warrants had a three-year term that expired in April 2008.  The
exercise price of the warrants was initially US$25.77 per trust unit and was
reduced each month by the amount of the Trust’s distribution for such month on
the trust units, provided that the price did not decrease below US$21.55 per
trust unit.  No warrants were exercised from this
issuance.





Contributed
surplus


(in
      thousands of Canadian dollars)Balance
      at December 31, 2005
                
                
                573Trust
      unit option based compensation
                
                
                1,294Restricted
      and performance unit compensation
                
                
                1,935Transfer
      to trust units on restricted and performance unit
exercises
                
                
                (579
                )Transfer
      to trust units on option exercises
                
                
                (28
                )Balance
      at December 31, 2006
                
                
                3,195Trust
      unit option based compensation
                
                
                1,300Restricted
      and performance unit compensation
                
                
                2,828Transfer
      to trust units on restricted and performance unit
exercises
                
                
                (2,663
                )Balance
      at December 31, 2007
                
                
                4,660Trust
      unit option based compensation
                
                
                110Restricted
      and performance unit compensation
                
                
                4,709Transfer
      to trust units on restricted and performance unit
exercises
                
                
                (2,074
                )Expired
      warrants
                
                
                1,215Balance
      at December 31, 2008
                
                
                8,620








Enterra Energy Trust Form 20 –
F





Trust
unit options


Enterra
has granted trust unit options to its directors, officers and
employees.  Each trust unit option permits the holder to purchase one
trust unit at the stated exercise price.  All options vest over a 1 to
3 year period and have a term of 4 to 5 years.  At the time of grant,
the exercise price is equal to the market price.  The forfeiture rate
is estimated to be 60%.  The following options have been
granted:





(in
      Canadian dollars, except for number of options)
                
                2008
                
                
                2007Number
      of
                  options
                
                
                Weighted-
                  average
      exercise
                  price
                
                
                Number
      of
                  options
                
                
                Weighted-
                  average
      exercise
                  priceOptions
      outstanding, beginning of year
                
                
                1,474,334
                
                
                $
                14.51
                
                
                
                1,481,000
                
                
                $
                20.28Options
      granted
                
                
                210,000
                
                
                
                2.81
                
                
                
                485,000
                
                
                
                2.64Options
      forfeited
                
                
                (642,334
                )
                
                
                21.65
                
                
                
                (491,666
                )
                
                
                20.08Options
      outstanding, end of year
                
                
                1,042,000
                
                
                
                7.75
                
                
                
                1,474,334
                
                
                
                14.51Options
      exercisable at end of year
                
                
                685,336
                
                
                $
                8.45
                
                
                
                710,333
                
                
                $
                17.14





(in
      Canadian dollars, except for number of options)Exercise
      price range
              Number
      of options
              Weighted
      average exercise price
              Weighted
      average remaining contract life in years
              Number
      of options exercisable
              Weighted
      average price of exercisable options$1.65
      to $2.81
              660,000
              $2.02
              2.96
              410,000
              $1.96$15.33
      to $19.85
              311,000
              16.38
              2.26
              208,002
              16.38$20.12
      to $26.80
              71,000
              23.27
              1.31
              67,334
              23.441,042,000
              $7.75
              2.64
              685,336
              $8.45





Estimated
fair value of stock options


The
estimated grant date fair value of options was determined using the
Black-Scholes model under the following assumptions:





2008
                
                
                2007
                
                
                2006Weighted-average
      fair value of options granted ($/option)
                
                
                0.70
                
                
                
                0.96
                
                
                
                1.07Risk-free
      interest rate (%)
                
                
                2.5
                
                
                
                4.7
                
                
                
                4.2Estimated
      hold period prior to exercise (years)
                
                
                4
                
                
                
                4
                
                
                
                5Expected
      volatility (%)
                
                
                90
                
                
                
                77
                
                
                
                45Expected
      cash distribution yield (%)
                
                
                -
                
                
                
                1
                
                
                
                14





Restricted
and performance units


Enterra
has granted restricted and performance units to directors, officers, and
employees.  Restricted units vest over a contracted period ranging
from vesting on grant to 3 years and provide the holder with trust units on the
vesting dates of the restricted units.  The units granted are the
product of the number of restricted units times a multiplier.  The
multiplier starts at 1.0 and is adjusted each month based on the monthly
distribution of the Trust divided by the five-day weighted average price of the
trust units based on the New York Stock Exchange for the period preceding the
distribution date.  Performance units vest at the end of two years and
provide the holder





Enterra Energy Trust Form 20 –
F





with
trust units based on the same multiplier as the restricted units as well as a
payout multiplier.  The payout multiplier ranges between 0.0 and 2.0
based on the Trust’s total unitholder return compared to its
peers.  The forfeiture rate is estimated to be 16% for 2008 and
2007.  As at December 31, 2008 and 2007 the payout multiplier was
estimated to be nil based on the Enterra’s total unitholder return compared to
its peers.





The
following restricted and performance units have been granted:





Number
      of restricted units
              Weighted-average
      grant date fair value
              Number
      of performance units
              Weighted-average
      grant date fair valueUnits
      outstanding, December 31, 2005
              -
              $             -
              -
              $            -Granted
              479,466
              14.90
              215,119
              15.06Vested
              (44,375)
              15.08
              -
              -Forfeited
              (11,236)
              15.66
              (2,171)
              15.66Units
      outstanding, December 31, 2006
              423,855
              $     14.91
              212,948
              $    15.41Granted
              1,045,507
              3.53
              363,940
              3.20Vested
              (215,383)
              12.76
              -
              -Forfeited
              (196,496)
              11.22
              (122,717)
              13.46Units
      outstanding, December 31, 2007
              1,057,483
              $       4.77
              454,171
              $     6.29Granted
              2,070,683
              3.77
              -
              -Vested
              (718,111)
              3.99
              -
              -Forfeited
              (130,269)
              4.37
              (279,773)
              7.61Units
      outstanding, December 31, 2008
              2,279,786
              $       4.13
              174,398
              $     4.17





The
estimated value of the restricted units and performance units is based on the
trading price of the trust units on the grant date.  For performance
units the compensation cost is adjusted for the estimated payout multiple, which
at December 31, 2008 and 2007 was nil.





Reconciliation
of earnings per unit calculations





For
      the year ended December 31, 2008(in
      thousands  of Canadian dollars except units and per unit
      amounts)
                
                Net
      Income
                
                
                Weighted
      Average Units Outstanding
                
                
                Per
      UnitBasic
                
                
                7,061
                
                
                
                61,660,971
                
                
                $
                0.11Dilution
      effect from:Restricted
      trust units
                
                
                
                
                
                
                1,173,141Trust
      unit options
                
                
                
                
                
                
                177,433Diluted
                
                
                7,061
                
                
                
                63,011,545
                
                
                $
                0.11








Enterra Energy Trust Form 20 –
F








For
      the year ended December 31, 2007(in
      thousands  of Canadian dollars except units and per unit
      amounts)
              
              Net
      Loss
              
              
              Weighted
      Average Units Outstanding
              
              
              Per
      UnitBasic
      and diluted
              
              
              (142,036
              )
              
              
              59,766,567
              
              
              $
              (2.38
              )








For
      the year ended December 31, 2006(in
      thousands  of Canadian dollars except units and per unit
      amounts)
              
              Net
      Loss
              
              
              Weighted
      Average Units Outstanding
              
              
              Per
      UnitBasic
      and diluted
              
              
              (64,239
              )
              
              
              44,141,688
              
              
              $
              (1.46
              )








For the
calculation of the weighted average number of diluted units outstanding for
2008, 382,000 options, 174,398 performance units and all convertible debentures
and warrants were excluded, as they were anti-dilutive to the
calculation.  For 2007 and 2006, all options, restricted units,
performance units, convertible debentures and warrants were excluded as they
were anti-dilutive to the calculation.





Trust
unit savings plan





Enterra
established a trust unit savings plan whereby it will match an employee’s
contributions to the plan to a maximum of 9.0% of their salary.  Both
the contributions of the employee and the Trust were used to purchase trust
units on the Toronto Stock Exchange.  During 2008 the Trust expensed
approximately $0.4 million (2007 - $0.4 million; 2006 - $0.3 million) relating
to its contributions to the plan.





11.           Accumulated
other comprehensive income (loss)





(in
      thousands of Canadian dollars)
                
                2008
                
                
                2007
                
                
                2006Opening
      balance
                
                
                (44,978
                )
                
                
                1,930
                
                
                
                -Cumulative
      translation of self-sustaining operations
                
                
                61,378
                
                
                
                (48,986
                )
                
                
                1,082Foreign
      exchange loss realized
                
                
                2,071
                
                
                
                2,078
                
                
                
                848Balance
      at December 31
                
                
                18,471
                
                
                
                (44,978
                )
                
                
                1,930





Accumulated
other comprehensive income (loss) is comprised entirely of currency translation
adjustments on the U.S. operations.








12.           Income
taxes





The
income tax provision differs from the amount of tax expense calculated by
applying federal and provincial statutory tax rates to the earnings (loss)
before taxes as follows:





(in
      thousands of Canadian dollars)
                
                2008
                
                
                2007
                
                
                2006Income
      (loss) before income taxes
                
                
                11,892
                
                
                
                (177,986
                )
                
                
                (121,850
                )Combined
      federal and provincial income tax rate
                
                
                29.7
                %
                
                
                32.1
                %
                
                
                34.50
                %Computed
      income tax expense (reduction)
                
                
                3,532
                
                
                
                (57,169
                )
                
                
                (42,038
                )Increase
      (decrease) resulting from:Interest
      component of trust distributions
                
                
                -
                
                
                
                (10,139
                )
                
                
                (13,788
                )Goodwill
      impairment
                
                
                -
                
                
                
                24,560
                
                
                
                -Other
      non-deductible items
                
                
                5,406
                
                
                
                1,880
                
                
                
                1,418Difference
      between U.S. and Canadian tax rates
                
                
                2,528
                
                
                
                (2,076
                )
                
                
                (1,494
                )Change
      in estimated pool balances
                
                
                (3,309
                )
                
                
                567
                
                
                
                -Change
      in tax rates
                
                
                (4,950
                )
                
                
                2,447
                
                
                
                (6,669
                )Other
                
                
                1,280
                
                
                
                3,499
                
                
                
                2,505Capital
      tax
                
                
                344
                
                
                
                481
                
                
                
                341Non-deductible
      crown charges
                
                
                -
                
                
                
                -
                
                
                
                3,614Resource
      allowance
                
                
                -
                
                
                
                -
                
                
                
                (1,464
                )4,831
                
                
                
                (35,950
                )
                
                
                (57,575
                )





The
components of the net future income tax liability at December 31 were as
follows:





(in
      thousands of Canadian dollars)
                
                2008
                
                
                2007Future
      income tax assets:Non-capital
      loss carry-forwards and other
                
                
                42,867
                
                
                
                47,475Valuation
      allowance on non-capital losses
                
                
                (16,612
                )
                
                
                (9,451
                )Asset
      retirement obligations
                
                
                6,123
                
                
                
                8,786Attributed
      Canadian royalty income
                
                
                1,317
                
                
                
                1,317Commodity
      contracts
                
                
                -
                
                
                
                1,516Financing
      charges
                
                
                480
                
                
                
                85034,175
                
                
                
                50,493Future
      income tax liabilities:Property,
      plant and equipment
                
                
                (53,604
                )
                
                
                (72,911
                )Commodity
      contracts
                
                
                (4,187
                )
                
                
                (179
                )Net
      future income tax liability
                
                
                (23,616
                )
                
                
                (22,597
                )





Non-capital
loss carry-forwards, excluding those for which a valuation allowance has been
taken, amongst Canadian and U.S. subsidiaries, totaled $61.3 million (2007 –
$104.4 million) and expire from 2009 to 2025.





The
effect of the enactment of the SIFT tax on the future tax provision for the year
ended December 31, 2007 was not significant.








13.
            Risk
      management





(a)  Fair
value of financial instruments





The fair
value of financial instruments is the amount of consideration that would be
agreed upon in an arm’s length transaction between knowledgeable, willing
parties who are under no compulsion to act.  Fair values are
determined by reference to quoted market prices, as appropriate, in the most
advantageous market for that instrument to which the Trust had immediate
access.  Where quoted market prices are not available, Enterra uses
the closing price of the most recent transaction for that
instrument.  In the absence of an active market, the Trust determines
fair values based on prevailing market rates for instruments with similar
characteristics.





(i)  Convertible
debentures





At
December 31, 2008 the convertible debentures have a carrying value of
approximately $113.4 million (December 31, 2007 - $111.7 million), excluding the
amount allocated to the equity component and a fair value of approximately $76.0
million (December 31, 2007 - $98.6 million).  The fair value of the
convertible debentures is determined based on market prices at December 31, 2008
and December 31, 2007 respectively.





(ii)
Derivative commodity contracts





The
Trust’s financial and physical commodity contracts are recorded at estimated
fair value with changes in estimated fair value each period charged to
earnings.  Fair values are determined based on valuation models, such
as option pricing models and discounted cash flow analysis, that use observable
market based inputs and assumptions.





Enterra Energy Trust Form 20 –
F








The fair
value of the derivatives at December 31, 2008, is estimated to be an asset of
$14.3 million (December 31, 2007 – net liability of $5.2
million).  Included in the oil and natural gas revenues is an
unrealized gain on financial derivatives of $20.2 million for 2008 (2007 - $16.8
million loss).  Included in production expenses for 2008 is an
unrealized loss of $0.2 million (2007 – $0.4 million)





(iii)  Other
financial instruments





Cash and
cash equivalents have been classified as held for trading and are recorded at
fair value on the balance sheet.  Changes in the fair value are
recorded in net earnings.  The fair value of the financial
instruments, except the convertible debentures, cash and cash equivalents and
commodity contracts approximate their carrying value as they are short term in
nature or bear interest at floating rates.





(b)  Financial
risk management





In the
normal course of operations, Enterra is exposed to various market risks such as
liquidity, credit, interest rate, foreign exchange and commodity
risk.  To manage these risks, management determines what activities
must be undertaken to minimize potential exposure to risks.  The
objectives of Enterra to managing risk are as follows:





Objectives:


·
            maintaining
      sound financial condition;


·
            financing
      operations; and


·
            ensuring
      liquidity in the Canadian and U.S.
operations.





In order
to satisfy the objectives above, Enterra has adopted the following
policies:


·
            prepare
      budget documents at prevailing market rates to ensure clear, corporate
      alignment to performance management and achievement of
      targets;


·
            recognize
      and observe the extent of operating risk within the
    business;


·
            identify
      the magnitude of the impact of market risk factors on the overall risk of
      the business and take advantage of natural risk reductions that arise from
      these relationships; and


·
            utilize
      financial instruments, including derivatives to manage the remaining
      residual risk to levels that are within the risk tolerance of the
      Trust.





The
policy objective with respect to the utilization of derivative financial
instruments is to selectively mitigate the impact of fluctuations in commodity
prices.  The use of any derivative instruments is carried out in
accordance with approved limits as authorized by the board of directors and
imposed by external financial covenants.  It is not the intent of
Enterra to use financial derivatives or commodity instruments for trading or
speculative purposes and no financial derivatives have been designated as
accounting hedges.





Enterra’s
process to manage changes in risks has not changed from the prior
period.








Enterra Energy Trust Form 20 –
F





(i)
Market risks





Oil and gas commodity price
risks


Enterra
is exposed to fluctuations in natural gas and crude oil
prices.  Enterra has entered into commodity contracts and fixed price
physical contracts to minimize the exposure to fluctuations in crude oil and
natural gas prices.  At December 31, 2008, the following financial
derivative contracts are outstanding:








Derivative
      Instrument
                Commodity
                Price
                Volume
      (per day)
                PeriodFloor
                Gas
                8.00
      ($/GJ)
                3,000
      GJ
                November
      1, 2008 – March 31, 2009Floor
                Gas
                9.00
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Gas
                9.50
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Gas
                10.00
      (US$/mmbtu)
                5,000
      mmbtu
                November
      1, 2008 – March 31, 2009Floor
                Oil
                72.00
      (US$/bbl)
                1,000
      bbl
                January
      1, 2009 – December 31, 2009Sold
      Call
                Oil
                91.50
      (US$/bbl)
                500
      bbl
                July
      31, 2009 – December 31,
2009





Enterra
did not have any fixed price oil or gas physical contracts as at December 31,
2008.





Electricity commodity price
risks


The Trust
is subject to electricity price fluctuations in its operations and it manages
this risk by entering into forward fixed rate electricity derivative contracts
on a portion of its electricity requirements.  The Trust’s outstanding
electricity derivative contracts as at December 31, 2008 are summarized
below.





Fixed
      purchase
            Power
              (Alberta)
            62.90
              (Cdn$/Mwh)
            72
      Mwh
            July
      1, 2007 – December 31, 2009





The gains
(losses) during the year from the commodity contracts are summarized in the
table below.





(in
      thousands of Canadian dollars)
                
                Years
      ended December 312008
                
                
                2007
                
                
                2006Realized
      commodity contract gain
                
                
                1,915
                
                
                
                6,249
                
                
                
                12,408Unrealized
      commodity contract gain (loss)
                
                
                20,072
                
                
                
                (16,205
                )
                
                
                10,628Net
      gain (loss) on commodity contracts
                
                
                21,987
                
                
                
                (9,956
                )
                
                
                23,036





The
following sensitivities show the impact to pre-tax net income for the year ended
December 31, 2008 related to commodity contracts of the respective changes in
crude oil prices, natural gas and electricity.





Increase
      (decrease) to pre-tax net income(in
      thousands of Canadian dollars)
                
                Decrease
      in market price ($1.00 per bbl and $0.50 per mcf)
                
                
                Increase
      in market price ($1.00 per bbl and $0.50 per mcf)Crude
      oil derivative contracts (bbl)
                
                
                413
                
                
                
                (413
                )Natural
      gas derivative contracts (mcf)
                
                
                987
                
                
                
                (987
                )$1.00
      per Mwh decrease in market price
                
                
                $1.00
      per Mwh increase in market priceElectricity
      derivative contracts (Mwh)
                
                
                (32
                )
                
                
                32








Enterra Energy Trust Form 20 –
F


Foreign exchange currency
risks


Enterra
is exposed to foreign currency risk as approximately 45% of its production is
from the U.S. division.  In addition, the Canadian division has
derivative financial instruments denominated in U.S. dollars.  Enterra
has not entered into any derivative contracts to mitigate its currency risks as
at December 31, 2008.





Changes
in the U.S. to Canadian foreign exchange rates with respect to the U.S. division
affect other comprehensive income as the division is considered a
self-sustaining foreign operation.  The following financial
instruments were denominated in U.S. dollars:





(in
      thousands  of dollars)
                
                Canadian
      division
                  (in
      U.S. dollars)
                
                
                U.S.
      division
                  (in
      U.S. dollars)Cash
      and cash equivalents
                
                
                7,830
                
                
                
                1,295Accounts
      receivable
                
                
                4,977
                
                
                
                26,893Commodity
      contracts
                
                
                10,963
                
                
                
                -Accounts
      payable
                
                
                (1,596
                )
                
                
                (9,935
                )Net
      exposure
                
                
                22,174
                
                
                
                18,253Effect
      of a $0.02 increase in U.S. to Cdn
    exchange  rate:
                
                
                -
                
                
                
                -Increase
      (Decrease) to pre-tax net income
                
                
                443
                
                
                
                -Increase
      (Decrease) to other comprehensive income
                
                
                -
                
                
                
                365Effect
      of a $0.02 decrease in U.S. to Cdn exchange rate:
                
                
                -
                
                
                
                -Increase
      (Decrease) to pre-tax net income
                
                
                (443
                )
                
                
                -Increase
      (Decrease) to other comprehensive income
                
                
                -
                
                
                
                (365
                )





Interest rate
risk


Interest
rate risk arises on the outstanding bank indebtedness that bears interest at
floating rates.  The results of Enterra are impacted by fluctuations
in interest rates as its outstanding bank indebtedness carries floating interest
rates.  The convertible debentures bear interest at fixed
rates.





Enterra
has not entered into any derivative contracts to mitigate the risks related to
fluctuations in interest rates as at December 31, 2008.  The following
sensitivities show the impact to pre-tax net income for the period ended
December 31, 2008 of the respective changes in interest rates (increase /
(decrease)).





Change
      to pre-tax net income(in
      thousands  of Canadian dollars)
              
              1%
      decrease in market interest rates
              
              
              1%
      increase in market interest ratesInterest
      on bank indebtedness
              
              
              1,256
              
              
              
              (1,256
              )








(ii)  Credit
risk





Credit
risk is the risk of loss if counterparties do not fulfill their contractual
obligations and arises principally from trade, joint venture receivables,
long-term receivables as well as any derivative financial instruments in a
receivable position.  Enterra does not hold any collateral from
counterparties.  The maximum exposure to credit risk is the carrying
amount of the related amounts receivable.





The
significant balances receivable are set out below.  Accounts
receivable include trade receivables, joint venture receivables and non-aging
accounts such as cash calls, taxes receivable and operating
advances.





(in
      thousands  of Canadian dollars)
                
                December
      31, 2008
                
                
                December
      31, 2007Accounts
      receivable – trade
                
                
                39,178
                
                
                
                23,264Accounts
      receivable – joint venture
                
                
                2,882
                
                
                
                3,724Accounts
      receivable – other (1)
                
                
                14,340
                
                
                
                4,517Allowance
      for doubtful accounts
                
                
                (10,281
                )
                
                
                (1,114
                )46,119
                
                
                
                30,391Long-term
      receivables
                
                
                19,310
                
                
                
                4,003








Enterra Energy Trust Form 20 –
F





1)
Included in accounts receivable – other is $8.6 million related to the current
portion of the receivable from Petroflow Energy Ltd. (note 20).





Should
Enterra determine that the ultimate collection of a receivable is in doubt based
on the processes for managing credit risk, it will provide the necessary
provision in its allowance for doubtful accounts with a corresponding charge to
earnings.  If Enterra subsequently determines an account is
uncollectible, the account is written off with a corresponding charge to
allowance for doubtful accounts.  During 2008 Enterra did provide for
an allowance as discussed below.





On July
22, 2008, SemGroup, a midstream and marketing company through which the Trust
marketed a portion of the Trust’s production, filed a voluntary petition for
reorganization under Chapter 11 of the Bankruptcy Code in the U.S. and the
Canadian units of SemGroup filed for protection under the Companies’ Creditors
Arrangement Act.  As a result, the Trust has recorded a provision for
non-recoverable receivables for the full amount owed by SemGroup of $8.5 million
with a corresponding decrease to net income ($6.0 million net of
tax).





The aging
of accounts receivable is set out below:





(in
      thousands  of Canadian dollars)As
      at December 31, 2008
                
                Trade
                
                
                Joint
      VentureCurrent
                
                
                25,907
                
                
                
                629Over
      30 days
                
                
                3,582
                
                
                
                203Over
      60 days
                
                
                2,055
                
                
                
                283Over
      90 days
                
                
                7,634
                
                
                
                1,76739,178
                
                
                
                2,882





The
credit quality of financial assets that are neither past due nor impaired has
been assessed and adequately evaluated for impairment based on historical
information about the nature of the counterparties.





Purchasers
of the natural gas, crude oil and natural gas liquids of Enterra comprise a
substantial portion of accounts receivable.  A portion of accounts
receivable are with joint venture partners in the oil and gas
industry.  Enterra takes the following precautions to reduce credit
risk:





·
            the
      financial strength of the counterparties is
  assessed;


·
            the
      total exposure is reviewed regularly and extension of credit is limited;
      and


·
            collateral
      may be required from some
counterparties.





As
described in note 20, Enterra has a long-term receivable with a joint venture
partner.  The credit risk as a result of this arrangement is mitigated
by the ability of Enterra to withhold a portion of the joint venture partner’s
share of production until such time as the amounts receivable are paid or the
production withheld exceeds the amounts owed to Enterra.





(iii)  Liquidity
risks





Liquidity
risk is the risk that Enterra will not be able to meet its financial obligations
as they come due.  Enterra mitigates this risk through actively
managing its capital, which it defines as unitholders’ equity, convertible
debentures, note payable, bank indebtedness and cash and cash
equivalents.  Management of liquidity risk over the short and longer
term, includes continual monitoring of forecasted and actual cash flows to
ensure sufficient liquidity to meet financial obligations when due and
maintaining a flexible capital management structure.  Enterra strives
to balance the proportion of debt and equity in its capital structure given its
current oil and gas assets and planned investment opportunities.








Enterra Energy Trust Form 20 –
F





All
financial liabilities have short-term maturities with the exception of the
convertible debentures (note 9), as set out below:





Financial
      Instrument – Liability(in
      thousands of Canadian dollars)
                
                1
      Year
                
                
                2
      Years
                
                
                3
      Years
                
                
                3-5
      Years
                
                
                Total
                
                
                Fair
      ValueBank
      indebtedness (1)
                
                
                -
                
                
                
                95,466
                
                
                
                -
                
                
                
                -
                
                
                
                95,466
                
                
                
                95,466Interest
      on bank indebtedness (2)
                
                
                3,580
                
                
                
                1,790
                
                
                
                -
                
                
                
                -
                
                
                
                5,370
                
                
                
                5,370Convertible
      debentures
                
                
                -
                
                
                
                -
                
                
                
                80,331
                
                
                
                40,000
                
                
                
                120,331
                
                
                
                76,049Interest
      on convertible debentures
                
                
                9,726
                
                
                
                9,726
                
                
                
                9,726
                
                
                
                1,650
                
                
                
                30,828
                
                
                
                30,828Accounts
      payable & accrued liabilities
                
                
                37,949
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                37,949
                
                
                
                37,949Total
      obligations
                
                
                51,255
                
                
                
                106,982
                
                
                
                90,057
                
                
                
                41,650
                
                
                
                289,944
                
                
                
                245,662


(1)  Assumes
the credit facilities are not renewed on June 24, 2009.


(2)  Assumes
an interest rate of 3.75% (the rate on December 31, 2008).





The
repayment terms and maturity dates of the credit facilities of Enterra are
disclosed in note 6.








14.           Interest
expense





During
2008, Enterra’s interest expense of $17.5 million (2007 – $22.6 million and 2006
– $26.7 million) was comprised of the following below.





(in thousands  of
      Canadian dollars)
                
                2008
                
                
                2007
                
                
                2006Interest
      on bank indebtedness
                
                
                8,362
                
                
                
                13,108
                
                
                
                25,898Interest
      on convertible debentures
                
                
                11,454
                
                
                
                9,963
                
                
                
                819Interest
      income
                
                
                (2,350
                )
                
                
                (489
                )
                
                
                -17,466
                
                
                
                22,582
                
                
                
                26,717








15.           Changes
in non-cash working capital





(in thousands  of
      Canadian dollars)
                
                2008
                
                
                2007
                
                
                2006Accounts
      receivable
                
                
                (15,728
                )
                
                
                8,589
                
                
                
                1,369Prepaid
      expenses, deposits and other
                
                
                311
                
                
                
                979
                
                
                
                (175
                )Accounts
      payable and accrued liabilities
                
                
                2,186
                
                
                
                (10,320
                )
                
                
                (26,536
                )Foreign
      exchange on working capital
                
                
                12,204
                
                
                
                5,355
                
                
                
                (3,935
                )Changes
      in non-cash working capital
                
                
                (1,027
                )
                
                
                4,603
                
                
                
                (29,277
                )Changes
      in non-cash operating working capital
                
                
                (5,492
                )
                
                
                6,381
                
                
                
                (21,632
                )Changes
      in non-cash investing working capital
                
                
                4,465
                
                
                
                (1,778
                )
                
                
                (7,645
                )





During
the year ended December 31, 2008 the Trust paid interest of $15.2 million (2007
- $20.3 million; 2006 – $26.5 million) and taxes of $0.3 million (2007 – $0.5
million; 2006 – $2.9 million).








Enterra Energy Trust Form 20 –
F








16.
            Capital
      disclosures





The
capital structure of Enterra consists of unitholders’ equity, convertible
debentures, note payable, bank indebtedness and cash and cash equivalents as
noted below.





(in
      thousands  of Canadian dollars)
                
                December
      31, 2008
                
                
                December
      31, 2007Components
      of capital:Unitholders’
      equity
                
                
                294,416
                
                
                
                219,184Convertible
      debentures
                
                
                113,420
                
                
                
                111,692Note
      payable
                
                
                -
                
                
                
                711Bank
      indebtedness
                
                
                95,466
                
                
                
                171,953Less:Cash
      and cash equivalents
                
                
                (13,638
                )
                
                
                (3,554
                )489,664
                
                
                
                499,986





The
objectives of Enterra when managing capital are:


·
            to
      reduce debt, with the long term goal to improve the balance
      sheet;


·
            to
      manage capital in a manner which balances the interest of equity and debt
      holders;


·
            to
      manage capital in a manner that will maintain compliance with its
      financial covenants; and


·
            to
      maintain a capital base so as to maintain investor, creditor and market
      confidence and to sustain future exploration and
    development.





Enterra
manages its capital structure as determined by management and approved by the
board of directors.  Adjustments are made to the capital structure
based on changes in economic conditions and planned
requirements.  Enterra has the ability to adjust its capital structure
by issuing new equity or debt, selling assets to reduce debt or balance equity,
controlling the amount it returns to unitholders, and making adjustments to its
capital expenditures program.





Enterra
monitors capital using an interest coverage ratio that has been externally
imposed as part of the credit agreement.  Enterra is required to
maintain an interest coverage ratio greater than 3.00 to 1.00; this ratio is
calculated as follows:





(in
      thousands of Canadian dollars except for ratios)
                
                December
      31, 2008
                
                
                December
      31, 2007Interest
      coverage (1):Cash flow over the prior four
      quarters
                
                
                116,911
                
                
                
                94,015Interest expenses over the prior
      four quarters
                
                
                18,088
                
                
                
                21,7326.46
      : 1.00
                
                
                4.33
      : 1.00


(1)
            Note
      these amounts are defined terms within the credit
    agreements





As at
December 31, 2008 and December 31, 2007, Enterra complied with the terms of the
credit facilities.  There have been no changes to Enterra’s capital
structure, objectives, policies and processes since December 31, 2007 other than
the changes to its credit facilities as described in note 6.








Enterra Energy Trust Form 20 –
F








17.           Commitments





During
2008 total rental expense was $1.1 million (2007 – $1.2 million and 2006 – $0.8
million).  Enterra has commitments for the following payments over the
next five years:





(in
      thousands of Canadian dollars)
                
                2009
                
                
                2010
                
                
                2011
                
                
                2012
                
                
                2013
                
                
                There-afterOffice
      leases (1)
                
                
                1,506
                
                
                
                1,597
                
                
                
                2,130
                
                
                
                635
                
                
                
                290
                
                
                
                -Vehicle
      and other operating leases
                
                
                373
                
                
                
                117
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -1,879
                
                
                
                1,714
                
                
                
                2,130
                
                
                
                635
                
                
                
                290
                
                
                
                -


(1)
Future office lease commitments may be reduced by sublease recoveries totaling
$1.6 million.







18.           Contingencies




Certain
claims have been brought against Enterra in the ordinary course of
business.  In the opinion of management, all such claims are
adequately covered by insurance, or if not so covered, are not expected to
materially affect its financial position.








19.           Segmented
information




The Trust
has one operating segment that is divided amongst two geographical
areas.  The following is selected financial information from the two
geographic areas.





(in
      thousands of Canadian dollars)
              
              2008
              
              
              2007
              
              
              2006RevenueCanada
              
              
              170,534
              
              
              
              128,406
              
              
              
              156,859U.S.
              
              
              104,963
              
              
              
              78,630
              
              
              
              87,549275,497
              
              
              
              207,036
              
              
              
              244,408Property,
      plant and equipmentCanada
              
              
              232,335
              
              
              
              315,569
              
              
              
              333,911U.S.
              
              
              259,319
              
              
              
              241,209
              
              
              
              325,357491,654
              
              
              
              556,778
              
              
              
              659,268GoodwillCanada
              
              
              -
              
              
              
              -
              
              
              
              76,256U.S.
              
              
              -
              
              
              
              -
              
              
              
              --
              
              
              
              -
              
              
              
              76,256








20.
            Related
      party transactions







On
November 23, 2007, Enterra entered into a consulting agreement with Trigger
Projects Ltd. for management services that would effectively be expected of the
most senior manager of the Trust.  This relationship was entered into
to provide temporary executive management services after the former Chief
Executive Officer resigned.  This contract had terms that required
payment for services of $40,000 per month and a bonus of up to $0.5 million on
termination.  The contract expired on May 31, 2008 and was extended to
June 26, 2008.  During 2008, total payments of $0.8 million were made
to Trigger Projects Ltd. and no balance was outstanding at December 31,
2008.




In 2006
Enterra entered into a farm-out agreement with Petroflow Energy Ltd. (“JV
Partner”), a public oil and gas company, to fund the drilling and completion
costs of the undeveloped lands in Oklahoma.  Per the agreement, JV
Partner pays 100% of the drilling and completion costs to earn 70% of Enterra’s
interest in the well and Enterra is required to pay 100% of the infrastructure
costs to support these wells, such as pipelines and salt water disposal
wells.  The infrastructure costs paid by Enterra are recoverable from
JV Partner over three years







Enterra Energy Trust Form 20 –
F





with
interest charged at a rate of 12% per annum.  Infrastructure costs
paid by Enterra are accounted for as a capital lease, therefore, the capital
costs incurred are not included in property, plant and equipment but are current
and long-term receivables.  The interest income on the long-term
receivables is recorded as a reduction in interest expense.  The
former Chief Executive Officer and former director of Enterra owned, directly
and indirectly, approximately 16% of the outstanding shares of JV Partner during
his tenure at Enterra.  A current director of Enterra owns
approximately 2% of the outstanding shares of JV Partner.  As at
December 31, 2008, a total of $27.9 million, split between $8.6 million of trade
receivables and $19.3 million of long-term receivables, relate to infrastructure
costs incurred by Enterra on behalf of JV Partner that are due from JV
Partner.  The receivables are for infrastructure costs incurred that
are to be repaid by JV Partner over a three-year period and is subject to
interest of 12% per annum.  For the year ended December 31, 2008, $1.7
million of interest income was earned on the long-term receivables from JV
Partner (2007 – $0.4 million).  In 2008, $5.0 million of principal
payments have been received (2007 - $1.1 million).




In 2007,
Enterra paid Macon Resources Ltd. (“Macon”) $0.7 million, a company 100% owned
by the former Chief Executive Officer, for management services provided by the
former Chief Executive Officer.  Macon did not provide any services to
Enterra during 2008 and therefore there were no payments made in
2008.  During Q1 2007, 50,000 restricted units (valued at $0.4 million
based on the unit price of trust units on the grant date) were granted to
Macon.  On February 28, 2007, these restricted units vested and were
converted to 50,441 trust units.  The former Chief Executive Officer
resigned as an officer and director on November 27, 2007 and February 20, 2008
respectively.






Relationship
with JED Oil Inc. and JMG Exploration Inc.


On
January 1, 2006, Enterra terminated a Technical Services Agreement with JED Oil
Inc (“JED”), which had provided for services required to manage the Trust’s
field operations and governed the allocation of general and administrative
expenses between the two entities.  The Trust now manages its own
management, development, exploitation, operations and general and administrative
activities.




On
September 28, 2006, Enterra terminated the existing farmout, joint services and
an Agreement of Business Principles with JED.  Concurrent with the
termination of the agreements, the Trust settled all amounts owing to
JED.




In
September 2006, Enterra sold $44.0 million of petroleum and natural gas
properties to JED in exchange for $30.9 million of petroleum and natural gas
properties and the settlement of the $13.1 million balance due to
JED.




Previously,
under an Agreement of Business Principles, properties acquired by the Trust were
contract operated and drilled by JMG Exploration, Inc. (“JMG”), a publicly
traded oil and gas exploration company, if they were exploration properties, and
contract operated and drilled by JED, a publicly traded oil and gas development
company, if they were development projects.  Exploration of the properties
was done by JMG, which paid 100% of the exploration costs to earn a 70% working
interest in the properties. If JMG discovered commercially viable reserves on
the exploration properties, the Trust had the right to purchase 80% of JMG’s
working interest in the properties at a fair value as determined by independent
engineers.  Had the Trust elected to have JED develop the properties,
development would have been done by JED, which would pay 100% of the development
costs to earn 70% of the interests of both JMG and the Trust.  The Trust
had a first right to purchase assets developed by JED.












Enterra Energy Trust Form 20 –
F





21.  Differences
between Canadian and United States Generally Accepted Accounting
Principles




The
consolidated financial statements of Enterra Energy Trust (“Enterra”) have been
prepared in accordance with Canadian GAAP (in thousands of Canadian dollars
except unit and per unit information) which differs in some respects from U.S.
GAAP.  Differences in accounting principles as they pertain to the
consolidated financial statements are immaterial except as described
below.




The
application of U.S. GAAP would have the following effect on net income (loss) as
reported for the year ended December 31, 2008, 2007 and 2006:





2008
                
                
                2007
                
                
                2006Net
      income (loss) under Canadian GAAP
                
                $
                7,061
                
                
                $
                (142,036
                )
                
                $
                (64,239
                )Adjustments
      for U.S. GAAPDepletion
      expense (a)
                
                
                (60,560
                )
                
                
                59,731
                
                
                
                (357,312
                )Related
      income taxes
                
                
                14,885
                
                
                
                (17,917
                )
                
                
                135,822Gain
      on commodity contracts (b)
                
                
                -
                
                
                
                -
                
                
                
                1,289Related
      income taxes
                
                
                -
                
                
                
                -
                
                
                
                (441
                )Reverse
      unit based compensation expense under Canadian GAAP (f)
                
                
                4,415
                
                
                
                4,128
                
                
                
                3,229Unit-based
      compensation recovery (expense) under U.S. GAAP (f)
                
                
                (160
                )
                
                
                1,230
                
                
                
                (935
                )Non-controlling
      interest (e)
                
                
                -
                
                
                
                -
                
                
                
                (36
                )Interest
      accretion on convertible debentures under Canadian GAAP
(h)
                
                
                1,728
                
                
                
                1,339
                
                
                
                35Amortization
      of other assets (h)
                
                
                (1,242
                )
                
                
                (848
                )
                
                
                -Gain
      on warrants (c)
                
                
                -
                
                
                
                -
                
                
                
                1,215Foreign
      exchange (g)
                
                
                2,071
                
                
                
                2,078
                
                
                
                848Adjustment
      to goodwill impairment due to EIC-151 (e)
                
                
                -
                
                
                
                26,631
                
                
                
                -Net
      loss under U.S. GAAP before cumulative effect of change in accounting
      policy under SFAS 123R
                
                $
                (31,802
                )
                
                $
                (65,664
                )
                
                $
                (280,525
                )Cumulative
      effect of change in accounting policy under SFAS 123R (f)
                
                
                -
                
                
                
                -
                
                
                
                177Net
      loss under U.S. GAAP
                
                $
                (31,802
                )
                
                $
                (65,664
                )
                
                $
                (280,348
                )Other
      comprehensive loss:Cumulative
      translation adjustment (g)
                
                
                34,869
                
                
                
                (23,558
                )
                
                
                (1,082
                )Other
      comprehensive income (loss) under U.S. GAAP
                
                $
                3,067
                
                
                $
                (89,222
                )
                
                $
                (281,430
                )Net
      loss under U.S. GAAP
                
                $
                (31,802
                )
                
                $
                (65,664
                )
                
                $
                (280,348
                )Deficit,
      beginning of year, under U.S. GAAP
                
                
                (25,928
                )
                
                
                (352,054
                )
                
                
                (422,991
                )Distributions
      declared (Canadian and U.S. GAAP)
                
                
                -
                
                
                
                (31,576
                )
                
                
                (90,698
                )Temporary
      equity adjustment (d)
                
                
                33,259
                
                
                
                423,366
                
                
                
                441,983Deficit,
      end of year, under U.S. GAAP
                
                $
                (24,471
                )
                
                $
                (25,928
                )
                
                $
                (352,054
                )Weighted
      average units for U.S. GAAP (000’s)Basic
      and diluted
                
                
                61,661
                
                
                
                59,767
                
                
                
                44,846Net
      loss per unit under U.S. GAAP before cumulative effect of change in
      accounting policy under SFAS 123R:Basic
      and diluted
                
                $
                (0.52
                )
                
                $
                (1.10
                )
                
                $
                (6.26
                )Net
      loss per unit under U.S. GAAPBasic
      and diluted
                
                $
                (0.52
                )
                
                $
                (1.10
                )
                
                $
                (6.25
                )








Enterra Energy Trust Form 20 –
F





The
application of U.S. GAAP would have the following effect on the consolidated
balance sheets as reported at December 31, 2008 and 2007:







2008
                
                
                2007Canadian
      GAAP
                
                
                U.S.
      GAAP
                
                
                Canadian
      GAAP
                
                
                U.S.
      GAAPAssets:Current
      assets
                
                $
                76,054
                
                
                $
                76,054
                
                
                $
                39,009
                
                
                $
                39,009Property,
      plant and equipment (a)
                
                
                491,654
                
                
                
                68,010
                
                
                
                556,778
                
                
                
                241,665Long-term
      receivables
                
                
                19,310
                
                
                
                19,310
                
                
                
                4,003
                
                
                
                4,003Other
      assets (h)
                
                
                -
                
                
                
                3,944
                
                
                
                -
                
                
                
                5,186Future/deferred
      income tax (a)
                
                
                -
                
                
                
                112,071
                
                
                
                -
                
                
                
                97,182$
                587,018
                
                
                $
                279,389
                
                
                $
                599,790
                
                
                $
                387,045Liabilities:Current
      liabilities (f)
                
                $
                137,602
                
                
                $
                133,912
                
                
                $
                214,191
                
                
                $
                214,528Convertible
      debentures (h)
                
                
                113,420
                
                
                
                120,331
                
                
                
                111,692
                
                
                
                120,331Asset
      retirement obligations
                
                
                22,151
                
                
                
                22,151
                
                
                
                29,939
                
                
                
                29,939Future/deferred
      income tax (a)
                
                
                19,429
                
                
                
                -
                
                
                
                24,784
                
                
                
                -292,602
                
                
                
                276,394
                
                
                
                380,606
                
                
                
                364,798Mezzanine
      equity (d)
                
                
                -
                
                
                
                37,295
                
                
                
                -
                
                
                
                70,651Unitholder's
      EquityUnitholders’
      capital (d)
                
                
                669,667
                
                
                
                -
                
                
                
                667,690
                
                
                
                -Equity
      component of convertible
                  debentures
      (h)
                
                
                3,977
                
                
                
                -
                
                
                
                3,977
                
                
                
                -Warrants
      (c)
                
                
                -
                
                
                
                -
                
                
                
                1,215
                
                
                
                -Contributed
      surplus (f)
                
                
                8,620
                
                
                
                -
                
                
                
                4,660
                
                
                
                -Accumulated
      other comprehensive income (loss) (g)
                
                
                18,471
                
                
                
                (9,829
                )
                
                
                (44,978
                )
                
                
                (22,476
                )Deficit
      (d)
                
                
                (406,319
                )
                
                
                (24,471
                )
                
                
                (413,380
                )
                
                
                (25,928
                )294,416
                
                
                
                (34,300
                )
                
                
                219,184
                
                
                
                (48,404
                )$
                587,018
                
                
                $
                279,389
                
                
                $
                599,790
                
                
                $
                387,045








(a)  Property,
plant and equipment




Under
Canadian GAAP, the impairment test limits the capitalized costs of oil and
natural gas assets to the discounted estimated future net revenue from proved
and probable oil and natural gas reserves using forecast prices plus the costs
of unproved properties less impairment.  The discount rate used is a
risk free interest rate.




Under
U.S. GAAP, the full cost method of accounting for oil and natural gas activities
requires Enterra to perform an impairment test using after-tax future net
revenue from proved oil and natural gas reserves, discounted at 10% plus the
cost of unproved properties less impairment.  The prices and costs
used in the U.S. GAAP ceiling test are those in effect at the consolidated
balance sheet date.  Where the amount of a ceiling test write-down
under Canadian GAAP differs from the amount of the write-down under U.S. GAAP,
the charge for depletion will differ.




There
were ceiling test impairments recognized under U.S. GAAP at December 31,
2008, 2007, 2006, 2005, 2004 and 2001.  At December 31, 2008, Enterra
recognized a U.S. GAAP ceiling test write-down of $113.1 million ($81.0 million
after tax) in its Canadian cost center.  No ceiling test impairment
was recorded at December 31, 2008 in the U.S. cost center.  At
December 31, 2007, Enterra recognized a U.S. GAAP ceiling test write-down of
$1.0 million ($0.7 million after tax) in its Canadian cost center and no ceiling
test impairment was recognized in the U.S. cost center.  At December
31, 2006, Enterra recognized an additional ceiling test write-down under U.S.
GAAP of $76.9 million ($53.8 million after tax) in its Canadian cost center and
$292.0 million ($175.2 million after tax) in its U.S. cost
center.  Prior to 2006, Enterra recognized ceiling test write-downs
under U.S. GAAP of $72.8 million ($46.3 million after tax) in its Canadian cost
center and $3.0 million ($2.0 million after tax) in its U.S. cost
center.





Enterra Energy Trust Form 20 –
F







Under
Canadian GAAP, pursuant to EIC-151, property, plant and equipment increased as a
result of the conversion of one class of exchangeable shares into trust
units.  Under U.S. GAAP, all classes of exchangeable shares are
classified as mezzanine equity, valued at their redemption
value.  Conversion of exchangeable shares does not result in an
increase in property, plant and equipment.  This GAAP difference in
the valuation of property, plant and equipment results in an increase in
depletion expense during the periods presented for Canadian GAAP as compared
with U.S. GAAP.




These
differences in the carrying value of property, plant and equipment results in
depletion expense being different under U.S. GAAP as compared with Canadian
GAAP.  For the years ended December 31, 2008, 2007 and 2006,
depletion expense under U.S. GAAP was lower by $52.5 million ($35.3 million net
of tax), $60.7 million ($42.5 million net of tax) and $12.6 million ($8.3
million net of tax), respectively.





(b)  Commodity
contracts and marketing contracts




Prior to
January 1, 2007, under Canadian GAAP, Enterra’s physical delivery contracts were
not considered commodity contracts and were not measured at fair value on the
consolidated balance sheet.  Beginning January 1, 2007, Enterra
records physical delivery contracts at fair value on the balance sheet at each
reporting date, consistent with the accounting required under U.S.
GAAP.





(c)  Warrants




Enterra
accounted for purchase warrants as equity under Canadian GAAP.  Under
US GAAP the share purchase warrants were accounted for as liabilities with
changes in fair value recorded in the statement of operations.  In
April of 2008 the warrants expired and at December 31, 2007, the estimated fair
value of the warrants were nil.







(d)  Unitholder's
mezzanine equity




Under
Canadian GAAP, the trust units are considered to be permanent equity and are
classified as unitholders' capital.  A U.S. GAAP difference exists due
to the redemption feature attached to each trust unit.  Trust units
are redeemable at the option of the holder based on the lesser of 90% of the
average market trading price of the trust units for the 10 trading days after
the date of redemption or the closing market price of the trust units on the
date of redemption.  Trust units can be redeemed to a cash limit of
$100,000 per year or a greater limit at the discretion of
Enterra.  Redemptions in excess of the cash limit shall be satisfied
first by the issuance of notes by a subsidiary of Enterra and second by issuance
of promissory notes by Enterra.




The
redemption feature causes the trust units to be classified as mezzanine equity
under U.S. GAAP.  Mezzanine equity is valued at an amount equal to the
redemption value of the trust units at the balance sheet
date.  Included in the redemption value of the trust units is the
redemption value of the exchangeable shares, if any, as if all exchangeable
shares had previously been converted into trust units.  Any increase
or decrease in the redemption value during a period is charged to the
deficit.




As at
December 31, 2008, unitholders’ capital was reduced by $669.7 million (December
31, 2007 - $ 667.7 million) and the redemption value of the trust units of $37.3
million (December 31, 2007 - $70.7 million) was recorded as mezzanine
equity.  The change in the redemption value of the trust units is
recorded as a reduction or increase to the deficit.  For the year
ended December 31, 2008, the deficit was reduced by $33.3 million (December 31,
2007 – $423.4 million and December 31, 2006 – $442.0 million).





(e)  Exchangeable
securities issued by subsidiaries of income trusts pursuant to
EIC-151




On
January 19, 2005, the CICA issued EIC-151 “Exchangeable Securities Issued by
Subsidiaries of Income Trusts” which states that equity interests held by third
parties in subsidiaries of an income trust should be reflected as either
non-controlling interest or debt in the consolidated balance sheet unless they
meet certain criteria.  EIC-151 requires that non-transferable shares
be classified as equity.  Enterra's exchangeable shares are
transferable and, in accordance with EIC-151, have been classified as
non-controlling interest on the Canadian GAAP consolidated balance
sheets.




Since a
portion of Enterra's exchangeable shares were not initially recorded at fair
value, subsequent exchanges for trust units are measured at the fair value of
the trust units issued.  The excess of fair values over book values on
the exchange are recorded as additions to property, plant and equipment and
goodwill.  In addition, non-controlling interest is reflected as a
reduction of such earnings in the Enterra’s consolidated statements of loss and
comprehensive loss.





Enterra Energy Trust Form 20 –
F







During
2008, Enterra did not have any exchangeable shares outstanding; therefore, there
was no impact from EIC-151 during the year.  The cumulative effect
from prior years of EIC-151 as of December 31, 2008 increased property, plant
and equipment by $1.8 million (December 31, 2007 - $1.8 million), increased
goodwill by $26.6 million (December 31, 2007 - $26.6 million), increased future
income tax liability by $0.7 million (December 31, 2007 - $0.7 million),
increased unitholder’s capital by $28.3 million (December 31, 2006 - $28.3
million), and increased the deficit by $0.4 million (December 31, 2007 - $0.4
million).  Under US GAAP, these adjustments are reversed as the
exchangeable shares are included in temporary equity.







(f)  Unit-based
compensation




Effective
January 1, 2006, Enterra adopted SFAS No. 123 (revised 2004), “Share-Based
Payment”, (“SFAS 123R”) which is a revision of SFAS No. 123, “Accounting for
Stock-based Compensation”.  SFAS 123R requires all unit-based payments
to employees, including grants of employee unit options, be recognized in the
financial statements based on their fair values.  Liability classified
awards, such as Enterra’s restricted units, performance units and unit options
are remeasured to fair value at each consolidated balance sheet date until the
award is settled rather than being treated as an equity classified award on the
grant date as required under Canadian GAAP.  Enterra has adopted this
standard by applying the modified prospective method.  As a result of
the adoption of SFAS 123R, in the year ended December 31, 2006, Enterra has
increased current liabilities by $0.6 million, which represented the fair value
of all outstanding unit options at January 1, 2006, in proportion to the
requisite service period rendered to that date.  In addition,
contributed surplus was reduced by $0.5 million and net earnings have been
increased by $0.2 million representing previously recognized compensation cost
for all outstanding unit options and a credit to record the cumulative effect of
a change in accounting principle.  Changes in fair value between
periods are charged or credited to earnings with a corresponding change in
current liabilities.  As at December 31, 2008, the fair value increase
recognized within current liabilities was $0.2 million (December 31, 2007 –
decrease of $1.2 million and December 31, 2006 – increase of $0.9
million).




The
number of Enterra trust units reserved for issuance for the Trust’s outstanding
options, restricted units and performance units shall not exceed 10% of the
aggregate number of issued and outstanding trust units of
Enterra.  Enterra issues units out of treasury upon the exercise of
all unit options, restricted units and performance units.




For the
years ended December 31, 2008 and 2007, Enterra recorded the following
unit-based compensation (000s):





Restricted
      and performance units
            Unit
      options
            Total2008
            2007
            2006
            2008
            2007
            2006
            2008
            2007
            2006Unit-based
      compensation (recovery) expense
            $145
            $(1,012)
            $1,280
            $
      15
            $(218)
            ($345)
            $
      160
            ($1,230)
            $935








Enterra Energy Trust Form 20 –
F







A summary
of the status of the unvested options, restricted units and performance units as
of December 31, 2008, and changes during the years then ended, is presented
below:





Number
      of unvested options
              Weighted
      average grant date fair value
              Number
      of unvested restricted units
              Weighted
      average grant date fair value
              Number
      of unvested performance units
              Weighted
      average grant date fair valueUnvested,
      December 31, 2007
              764,001
              $    1.04
              1,057,482
              $     4.77
              454,171
              $      6.29Granted
              210,000
              0.70
              2,070,683
              3.77
              -
              -Vested
              (387,333)
              0.98
              (718,111)
              3.99
              -
              -Forfeited
              (230,004)
              1.05
              (130,269)
              4.37
              (279,773)
              7.61Unvested,
      December 31, 2008
              356,664
              $    0.90
              2,279,786
              $     4.13
              174,398
              $     4.17




The
following tables provide information related to unit option, restricted unit and
performance unit activity during the years ended December 31, 2008:





Number
      of unit options
              Weighted
      average exercise price
              Weighted
      average contract life
              Aggregate
      intrinsic value (000’s)Options
      outstanding, January 1, 2008
              1,474,334
              $        14.51Options
      granted
              210,000
              2.81Options
      forfeited
              (642,334)
              21.65Options
      outstanding, December 31, 2008
              1,042,000
              $          7.75
              2.65
              $                  -Options
      expected to vest, December 31, 2008
              685,336
              $          8.45
              2.59
              $                  -Options
      exercisable, December 31, 2008
              685,336
              $          8.45
              2.59
              $                  -





Number
      of units
              Weighted
      average contract life
              Aggregate
      intrinsic value (000’s)Restricted
      units outstanding, January 1, 2008
              
              1,057,483Restricted
      units granted
              
              2,070,683Restricted
      units exercised
              
              (718,111)Restricted
      units forfeited
              
              (130,269)Restricted
      units outstanding, December 31, 2008
              
              2,279,786
              1.63
              $        1,368Restricted
      units expected to vest, December 31, 2008
              
              1,915,020
              1.63
              $         1,149Restricted
      units exercisable, December 31, 2008
              
              -
              -
              $                 -








Enterra Energy Trust Form 20 –
F










Number
      of units
              Weighted
      average contract life
              Aggregate
      intrinsic value (000’s)Performance
      units outstanding, January 1, 2008
              
              454,171Performance
      units granted
              
              -Performance
      units exercised
              
              -Performance
      units forfeited
              
              (279,773)Performance
      units outstanding, December 31, 2008
              
              174,398
              0.77
              $                   -Performance
      units expected to vest, December 31, 2008
              
              146,494
              0.77
              $                   -Performance
      units exercisable, December 31, 2008
              
              -
              -
              $                   -







The
intrinsic value of a unit option is the amount by which the current market value
of the underlying unit exceeds the exercise price of the option.  The
intrinsic value of a restricted unit is the current market value of the
underlying unit.  The intrinsic value of a performance unit is the
market value of the underlying unit multiplied by the performance factor at year
end which was estimated to be nil in 2008, 2007 and 2006.




The fair
value of each stock option award is estimated using the Black-Scholes option
pricing model based on assumptions noted in the following table.







2008
              2007
              2006Risk-free
      interest rate (%)
              1.25
              4.5
              4.5Expected
      term (years)
              1.1
      –  3.1
              2.1
      – 3.9
              2.0
      – 4.6Expected
      cash distribution yield (%)
              -
              -
              14Expected
      volatility (%)
              130
      – 159
              63
      – 66
              41
      – 69




The
intrinsic value of options exercised in 2008 was nil (2007 – nil and 2006 – $0.1
million).  The weighted average grant date fair value for options
granted in 2008 was $0.70 (2007 - $1.02 and 2006 – $1.03).




The fair
value of each restricted unit was based on Enterra’s weighted average unit price
around the date of grant and each subsequent reporting period until the date of
settlement.




The
intrinsic value of restricted units exercised in 2008 was $1.4 million (2007 -
$1.2 million and 2006 - $0.4 million).  The weighted average grant
date fair value of the restricted units granted was $3.77 (2007 – $3.53 and 2006
– $14.90).




The fair
value of each performance unit was based on Enterra’s weighted average unit
price around the date of grant and each subsequent reporting period until the
date of settlement adjusted for the estimated payout multiple.




The
intrinsic value of performance units exercised in 2008 was nil (2007 and 2006 –
nil) since there were no performance units vested.  There were no
performance units granted during 2008, therefore, the weighted average grant
date fair value of the performance units granted was nil (2007 – $3.20 and 2006
– $15.06).




As of
December 31, 2008, there was $0.1 million (2007 – $0.1 million and 2006
–  $0.5 million) of total unrecognized compensation cost related to
unvested unit options.  The cost is expected to be recognized over a
weighted average period of 0.7 years (2007 – 1.2 years and 2006 – 1.9
years).





Enterra Energy Trust Form 20 –
F







As of
December 31, 2008, there was $1.0 million (2007 - $0.9 million and 2006 - $2.7
million) of unrecognized compensation cost related to unvested restricted
units.  The cost is expected to be recognized over a weighted average
period of 1.6 years (2007 – 1.2 years and 2006 – 2.0 years).




As of
December 31, 2008, 2007 and 2006, there was no amount of unrecognized
compensation cost related to unvested performance units.




Under
U.S. GAAP, the amount of compensation costs related to options, restricted units
and performance units to be capitalized was insignificant.





(g)
Cumulative translation adjustment and other comprehensive income




Enterra’s
U.S. oil and natural gas properties are considered to be self
sustaining.  Under Canadian GAAP, a portion of the cumulative
translation adjustment is recognized in income as the investment in the foreign
operations is reduced.  Under U.S. GAAP, the cumulative translation
adjustment is only recognized in income upon disposition of the
segment.  For the year ended December 31, 2008, $2.1 million (2007 -
$2.1 million and 2006 - $0.8 million) of the cumulative translation adjustment
was recognized as a foreign exchange loss under Canadian GAAP.  The
difference in other comprehensive income under U.S. GAAP as compared to Canadian
GAAP is a result of differences between the carrying values of the assets and
liabilities of the U.S. self sustaining operations under U.S. GAAP versus
Canadian GAAP.  These differences in the carrying values result in
differences in the foreign exchange gains and losses on translation of the U.S.
operations.





(h)
Convertible debentures




In
November 2006 and April 2007, Enterra issued convertible
debentures.  Under Canadian GAAP, Enterra’s convertible debentures are
classified as debt with a portion representing the value associated with the
conversion feature being allocated to equity and the issue costs netted against
the debt.  Under U.S. GAAP, the convertible debentures in their
entirety are classified as debt and the issue costs classified as other
assets.  In addition, under Canadian GAAP, a non-cash interest expense
representing the effective yield of the debt component is recorded in the
consolidated statements of loss and comprehensive loss with a corresponding
credit to the convertible debenture liability balance to accrete that balance to
the full principal due on maturity.  Under U.S. GAAP, this non-cash
interest expense is not recorded but the issue costs are amortized over the life
of debentures.





(i)
Additional disclosure under U.S. GAAP





2008
              2007Components
      of accounts receivable:Trade
              
              $     40,581
              $     11,497Accruals
              
              15,156
              19,983Allowance
      for doubtful accounts
              (9,618)
              (1,089)$     46,119
              $     30,391Components
      of prepaid expenses:Prepaid
      expenses
              
              $          992
              $      1,290Funds
      on deposit
              
              967
              980$       1,959
              $      2,270Components
      of accounts payable:Accounts
      payable
              
              $     18,741
              $    22,316Accrued
      liabilities
              
              19,208
              13,447$     37,949
              $    35,763








Enterra Energy Trust Form 20 –
F








(j)
Select pro forma financial information for the acquisition of Trigger Resources
(unaudited)





On April
30, 2007, Enterra acquired Trigger Resources Ltd. Under U.S. GAAP, select pro
forma financial information is disclosed under FAS 141.54 as if the acquisition
had occurred on January 1, 2007 and January 1, 2006 respectively instead of the
actual closing of April 30, 2007.  The following table shows select
pro forma financial information:





2007
                (unaudited)
              2006
                (unaudited)Oil
      and natural gas revenue
              
              $        217,994
              $       272,239Net
      loss
              
              (67,681)
              (288,116)Per
      unit – basic and diluted
              
              $            (1.10)
              $          (5.87)





(k)
Uncertainty in tax positions





On
January 1, 2007, Enterra adopted the provisions of FASB Interpretation No.
48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an
interpretation of FASB Statement No. 109, “Accounting for Income
Taxes.”   FIN 48 prescribes a recognition threshold and
measurement attribute for the financial statement recognition and measurement of
a tax position taken or expected to be taken in a tax return.  The
interpretation requires that Enterra recognize the impact of a tax position in
the financial statements if that position is more likely than not of being
sustained on audit, based on the technical merits of the
position.  FIN 48 also provides guidance on derecognition,
classification, interest and penalties, and accounting in interim periods and
disclosure.  In accordance with the provisions of FIN 48, any
cumulative effect resulting from the change in accounting principle is to be
recorded as an adjustment to the opening deficit balance.





As at
December 31, 2008 and 2007, Enterra did not have any amounts recorded pertaining
to uncertain tax positions.  The adoption of FIN 48 did not impact
Enterra’s tax provision.




Enterra
files federal and provincial income tax returns in Canada and federal, state and
local income tax returns in the U.S., as applicable.  Enterra may be
subject to a reassessment of federal and provincial income taxes by Canadian tax
authorities for a period of four years from the date of mailing of the original
notice of assessment in respect of any particular taxation year.  For
the Canadian tax returns, the open taxation years range from 2004 to
2008.  For the U.S. tax returns, the open taxation years range
from 2006 to 2008.  The U.S. federal statute of limitations for
assessment of income tax is generally closed for the tax years ending on or
prior to 2002.  In certain circumstances, the U.S. federal
statute of limitations can reach beyond the standard three year
period.  U.S. state statutes of limitations for income tax
assessment vary from state to state.  Tax authorities of Canada and
U.S. have not audited any of Enterra’s, or its subsidiaries’, income tax
returns for the open taxation years noted above.




Enterra
recognizes interest and penalties related to uncertain tax positions in tax
expense.  During the years ended December 31, 2008, 2007 and
2006, there were no charges for interest or penalties.





(l)
Fair value of commodity contracts





Certain
of Enterra’s assets and liabilities are reported at fair value in the balance
sheets.  The following tables provide fair value measurement
information for such assets and liabilities as of December 31, 2008 and
December 31, 2007 including items where the fair value is disclosed on a
reoccurring basis.





The
carrying values of cash and cash equivalents, accounts receivable, bank
indebtedness, accounts payable and accrued liabilities, and note payable
included in the accompanying consolidated balance sheets approximated fair value
at December 31, 2008 and December 31, 2007 as the amounts were short term
in nature or bore interest at floating rates.  These assets and
liabilities are not presented in the following tables.





Enterra Energy Trust Form 20 –
F








As
      at December 31, 2008Fair
      Value Measurements Using:Carrying
      Amount
                
                
                Fair
                  Value
                
                
                Level
      1
                
                
                Level
      2
                
                
                Level
      3Commodity
      contracts
                
                
                14,338
                
                
                
                14,338
                
                
                
                -
                
                
                
                14,338
                
                
                
                -Convertible
      debentures
                
                
                (113,420
                )
                
                
                (76,049
                )
                
                
                (76,049
                )
                
                
                -
                
                
                
                -





SFAS 157
establishes a fair value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value.  This hierarchy consists of
three broad levels.  Level 1 inputs on the hierarchy consist of
unadjusted quoted prices in active markets for identical assets and liabilities
and have the highest priority.  Level 2 and 3 inputs have lower
priorities.  The Trust uses appropriate valuation techniques based on
the available inputs to measure the fair values of assets and
liabilities.  When available, Enterra measures fair value using
Level 1 inputs because they generally provide the most reliable evidence of
fair value.





The
following methods and assumptions were used to estimate the fair values of the
assets and liabilities in the table above.




Level 1
Fair Value Measurements


Convertible
debentures – The fair values of the convertible debentures are estimated using
unadjusted quoted prices in active markets.





Level 2
Fair Value Measurements


Commodity
contracts – The fair values of the commodity contracts are estimated using
discounted cash flow calculations based upon forward commodity price curves and
quotes obtained from brokers for contracts with similar terms or quotes obtained
from counterparties to the contracts taking into consideration the credit
worthiness of those brokers or counterparties.





Level 3
Fair Value Measurements


The Trust
does not have any financial assets or financial liabilities whose fair value is
measured using this method.





(k)
New accounting pronouncements not yet adopted





In
December 2008, the SEC released Final Rule, Modernization of Oil and Gas
Reporting to revise the existing Regulation S-K and Regulation S-X reporting
requirements to align with current industry practices and technological
advances.  The new disclosure requirements include provisions that
permit the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions
about reserve volumes.  In addition, the new disclosure requirements
require an entity to (a) disclose its internal control over reserves estimation
and report the independence and qualification of its reserves preparer or
auditor, (b) file reports when a third party is relied upon to prepare reserves
estimates or conducts a reserve audit and (c) report oil and gas reserves using
an average price based upon the prior 12-month period rather than period-end
prices.  The provisions of this final ruling are effective for
disclosures in the Trust’s Annual Report for the year ended December 31,
2009.  Early adoption is not permitted.  The Trust is
currently assessing the impact that the adoption will have on its disclosures,
operating results, financial position and cash flows.




In May
2008, FASB issued FASB Staff Position No. APB 14-1, “Accounting for Convertible
Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial
Cash Settlement)”.  An issuer of a convertible debt instrument within
the scope of the staff position is required to separate the instrument into a
liability-classified component and an equity-classified
component.  The staff position is effective for the fiscal year
beginning after December 15, 2008.  Enterra is currently assessing the
impact of the staff position and expects that the guidance will bring U.S. GAAP
in line with Canadian GAAP.




In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities”.  SFAS 161 requires entities
with derivative instruments to disclose information that should enable financial
statement users to understand how and why an entity uses derivative instruments,
how derivative instruments and related hedged items are accounted for under
SFAS 133, how derivative instruments and related hedged items affect an
entity’s financial position, financial performance and cash
flows.  SFAS 161 is effective for financial statements issued for
fiscal years and interim periods beginning after November 15,
2008.  The adoption of this statement is not expected to have a
material effect on the Trust’s disclosures within the consolidated financial
statements.





Enterra Energy Trust Form 20 –
F








In
December 2007, FASB issued SFAS No. 141 (revised 2007) “Business Combinations”
which replaces SFAS No. 141 “Business Combinations”.  The new standard
requires the acquiring entity in a business combination to recognize all the
assets acquired and liabilities assumed in the transaction; and recognize and
measure the goodwill acquired in the business combinations for which the
acquisition date is on or after January 1, 2009.  The adoption of this
accounting standard will impact business combinations, if any, after the
adoption date.





In
December 2007, FASB issued SFAS No. 160 “Non-controlling Interests in
Consolidated Financial Statements” (“SFAS 160”) which requires the Trust to
report non-controlling interests in subsidiaries as equity in the consolidated
financial statements; and all transactions between an entity and
non controlling interests as equity transactions.  SFAS 160 is
effective for Enterra commencing on January 1, 2009 and it will not impact the
current consolidated financial statements of the Trust.





In
September 2006, the FASB issued SFAS No. 157 “Fair Value
Measurements”.  SFAS 157 defines fair value, establishes a framework
for measuring fair value under US GAAP and expands disclosures about fair value
measurements.  This statement was adopted by the Trust in
2008.  In February 2008, the FASB issued FASB Staff Position (“FSP”)
SFAS 157-2 which delayed the effective date of SFAS 157 for all
non-financial assets and non-financial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually), until fiscal years beginning after November 15,
2008, and interim periods within those fiscal years.  These
non-financial items include assets and liabilities such as asset retirement
obligations and non-financial assets acquired and liabilities assumed in a
business combination.  Beginning January 1, 2009, the Trust will adopt
the provisions for non-financial assets and non-financial liabilities that are
not required or permitted to be measured at fair value on a recurring
basis.  The Trust does not expect the provisions of SFAS 157
related to these items to have a material impact on the consolidated
financial statements.





In May
2009, the FASB issued SFAS No. 165, “Subsequent Events”. SFAS No. 165 is
intended to establish general standards of accounting for and disclosure of
events that occur after the balance sheet date but before financial statements
are issued or are available to be issued.  In particular, this
Statement sets forth the period after the balance sheet date during which
management of a reporting entity should evaluate events or transactions that may
occur for potential recognition or disclosure in the financial statements; the
circumstances under which an entity should recognize events or transactions
occurring after the balance sheet date in its financial statements; and the
disclosures that an entity should make about events or transactions that
occurred after the balance sheet date. This Statement is effective for interim
and annual periods ending after June 15, 2009. The adoption of this statement
may impact the accounting or disclosure of future subsequent events, if any,
after the effective date.





Enterra Energy Trust Form 20 –
F





22.         SUPPLEMENT
INFORMATION – OIL AND GAS PRODUCING ACTIVITIES (unaudited)





The following disclosures have been
prepared in accordance with SFAS No. 69 – “Disclosures about Oil and Gas
Producing Activities”.  Amounts are in Canadian dollars unless
otherwise denoted.





OIL
AND GAS RESERVES




Users of
this information should be aware that the process of estimating quantities of
“proved” and “proved developed” crude oil and natural gas reserves is very
complex, requiring significant subjective decisions in the evaluation of all
available geological, engineering and economic data for each
reservoir.  The data for a given reservoir may also change
substantially over time as a result of numerous factors including, but not
limited to, additional development activity, evolving production history, and
continual reassessment of the viability of production under varying economic
conditions.  Consequently, material revisions to existing reserve
estimates occur from time to time.  Although every reasonable effort
is made to ensure that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective decisions required and
variances in available data for various reservoirs make these estimates
generally less precise than other estimates presented in connection with
financial statement disclosures.




Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids (“NGL”) that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.




Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating
methods.




Canadian
provincial royalties are determined based on a graduated percentage scale that
varies with prices and production volumes.  Canadian reserves, as
presented on a net basis, assume prices and royalty rates in existence at the
time that estimates were made and the Trust’s estimate of future production
volumes.  Future fluctuations in prices, production rates, or changes
in political or regulatory environments could cause the Trust’s share of future
production from Canadian reserves to be materially different from that
presented.







Enterra Energy Trust Form 20 –
F





RESULTS
OF OPERATIONS FOR PRODUCING ACTIVITIES




The
following table sets forth revenue and direct cost information relating to the
Trust’s oil and gas producing activities for the years ended
December 31:




(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2008
      TotalRevenue
                
                
                136,946
                
                
                
                80,201
                
                
                
                217,147Deduct:Production
      costs
                
                
                38,937
                
                
                
                19,401
                
                
                
                58,338Depletion,
      depreciation and amortization
                
                
                155,762
                
                
                
                4,175
                
                
                
                159,937Results
      of operations from producing activities
                
                
                (57,753
                )
                
                
                56,625
                
                
                
                (1,128
                )








(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2007
      TotalRevenue
                
                
                99,492
                
                
                
                62,179
                
                
                
                161,671Deduct:Production
      costs
                
                
                45,600
                
                
                
                19,223
                
                
                
                64,823Depletion,
      depreciation and amortization
                
                
                85,015
                
                
                
                5,955
                
                
                
                90,970Results
      of operations from producing activities
                
                
                (31,123
                )
                
                
                37,001
                
                
                
                5,878








(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2006
      TotalRevenue
                
                
                128,607
                
                
                
                67,514
                
                
                
                196,121Deduct:Production
      costs
                
                
                35,513
                
                
                
                14,848
                
                
                
                50,361Depletion,
      depreciation and amortization
                
                
                207,079
                
                
                
                351,681
                
                
                
                558,760Results
      of operations from producing activities
                
                
                (113,985
                )
                
                
                (299,015
                )
                
                
                (413,000
                )





Enterra Energy Trust Form 20 –
F





COSTS
INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES




Costs
incurred by the Trust in oil and gas producing activities for the years ended
December 31 are as follows:




(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2008
      TotalProperty
      acquisition costs:Proved
                
                
                -
                
                
                
                -
                
                
                
                -Unproved
                
                
                3,049
                
                
                
                10,805
                
                
                
                13,854Exploration
      costs
                
                
                -
                
                
                
                -
                
                
                
                -Development
      costs
                
                
                18,399
                
                
                
                861
                
                
                
                19,260Property
      acquisition, exploration, and development expenditures
                
                
                21,448
                
                
                
                11,666
                
                
                
                33,114







(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2007
      TotalProperty
      acquisition costs:Proved
                
                
                81,382
                
                
                
                -
                
                
                
                81,382Unproved
                
                
                -
                
                
                
                5,300
                
                
                
                5,300Exploration
      costs
                
                
                -
                
                
                
                -
                
                
                
                -Development
      costs
                
                
                17,759
                
                
                
                10,839
                
                
                
                28,598Property
      acquisition, exploration, and development expenditures
                
                
                99,141
                
                
                
                16,139
                
                
                
                115,280








(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2006
      TotalProperty
      acquisition costs:Proved
                
                
                25,621
                
                
                
                332,290
                
                
                
                357,911Unproved
                
                
                6,736
                
                
                
                26,384
                
                
                
                33,120Exploration
      costs
                
                
                -
                
                
                
                -
                
                
                
                -Development
      costs
                
                
                20,868
                
                
                
                8,031
                
                
                
                28,899Property
      acquisition, exploration, and development expenditures
                
                
                53,225
                
                
                
                366,705
                
                
                
                419,930








Acquisition
costs include costs incurred to purchase, lease or otherwise acquire oil and gas
properties.




Development
costs include the costs of drilling and equipping development wells and
facilities to extract, treat and gather and store oil and gas as well as
additions to asset retirement obligations.




Enterra
capitalizes a portion of general and administrative costs associated with
exploration activities and development activities.  Transaction costs
directly attributable to successful acquisitions are also
capitalized.










Enterra Energy Trust Form 20 –
F





CAPITALIZED
COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES




The
capitalized costs and related accumulated depreciation, depletion and
amortization, including impairments, relating to the Trust’s oil and gas
exploration, development and producing activities for the years ended
December 31 consist of:




(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2008
      TotalOil
      and gas properties
                
                
                716,814
                
                
                
                391,178
                
                
                
                1,107,992Less:Accumulated
      depletion, depreciation and amortization
                
                
                (680,733
                )
                
                
                (359,249
                )
                
                
                (1,039,982
                )Net
      capitalized costs
                
                
                36,081
                
                
                
                31,929
                
                
                
                68,010







(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2008
      TotalUnproven
      oil and gas properties
                
                
                11,779
                
                
                
                11,854
                
                
                
                23,633Proven
      oil and gas properties
                
                
                24,302
                
                
                
                20,075
                
                
                
                44,377Net
      capitalized costs
                
                
                36,081
                
                
                
                31,929
                
                
                
                68,010








(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2007
      TotalOil
      and gas properties
                
                
                739,172
                
                
                
                328,945
                
                
                
                1,068,117Less:Accumulated
      depletion, depreciation and amortization
                
                
                (526,573
                )
                
                
                (299,879
                )
                
                
                (826,452
                )Net
      capitalized costs
                
                
                212,599
                
                
                
                29,066
                
                
                
                241,665







(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2007
      TotalUnproven
      oil and gas properties
                
                
                18,571
                
                
                
                -
                
                
                
                18,571Proven
      oil and gas properties
                
                
                194,028
                
                
                
                29,066
                
                
                
                223,094Net
      capitalized costs
                
                
                212,599
                
                
                
                29,066
                
                
                
                241,665











Enterra Energy Trust Form 20 –
F





OIL
AND GAS RESERVE INFORMATION




At
December 31, 2008, Enterra reserves were located in Canada in the provinces of
Alberta, British Columbia and Saskatchewan as well as in the United States in
the state of Oklahoma.  McDaniel & Associates Consultants Ltd.
(“McDaniel”) reviewed the reserves in Canada and Haas Petroleum Engineering
Services, Inc. (“Haas”) reviewed the reserves in Oklahoma.   The
tables below provide a summary of the Trust’s proved developed and undeveloped
reserves after deductions of royalties as evaluated by McDaniel and Haas based
on constant price and cost assumptions.




CANADA
                
                Crude
      oil and NGL (mbbl)
                
                
                Natural
      gas (mmcf)Net
      proved developed and undeveloped reserves after royaltiesEnd
      of year 2005
                
                
                5,343
                
                
                
                33,096Revision
      of previous estimates
                
                
                368
                
                
                
                (1,639
                )Extensions
      and discoveries
                
                
                -
                
                
                
                -Purchase
      of reserves in place
                
                
                406
                
                
                
                2,558Production
                
                
                (1,342
                )
                
                
                (5,474
                )Sales
      of reserves in place
                
                
                (402
                )
                
                
                (4,874
                )End
      of year 2006
                
                
                4,373
                
                
                
                23,667Revision
      of previous estimates
                
                
                149
                
                
                
                2,250Extensions
      and discoveries
                
                
                92
                
                
                
                (23
                )Purchase
      of reserves in place
                
                
                757
                
                
                
                8,813Production
                
                
                (1,209
                )
                
                
                (5,930
                )Sales
      of reserves in place
                
                
                (277
                )
                
                
                (623
                )End
      of year 2007
                
                
                3,885
                
                
                
                28,154Revision
      of previous estimates
                
                
                (341
                )
                
                
                (3,449
                )Extensions
      and discoveries
                
                
                128
                
                
                
                457Purchase
      of reserves in place
                
                
                3
                
                
                
                9Production
                
                
                (914
                )
                
                
                (4,070
                )Sales
      of reserves in place
                
                
                (767
                )
                
                
                (6,524
                )End
      of year 2008
                
                
                1,994
                
                
                
                14,577Net
      proved developed reserves after royaltiesEnd
      of year 2006
                
                
                4,253
                
                
                
                22,003End
      of year 2007
                
                
                3,637
                
                
                
                26,399End
      of year 2008
                
                
                1,994
                
                
                
                14,577





UNITED
      STATES
                
                Crude
      oil and NGL (mbbl)
                
                
                Natural
      gas (mmcf)Net
      proved developed and undeveloped reserves after royaltiesEnd
      of year 2005
                
                
                -
                
                
                
                1,601Revision
      of previous estimates
                
                
                (698
                )
                
                
                (12,409
                )Extensions
      and discoveries
                
                
                2
                
                
                
                2,560Purchase
      of reserves in place
                
                
                2,232
                
                
                
                54,332Production
                
                
                (179
                )
                
                
                (7,287
                )Sales
      of reserves in place
                
                
                -
                
                
                
                -End
      of year 2006
                
                
                1,357
                
                
                
                38,797Revision
      of previous estimates
                
                
                (334
                )
                
                
                9,479Extensions
      and discoveries
                
                
                59
                
                
                
                3,293Purchase
      of reserves in place
                
                
                -
                
                
                
                -Production
                
                
                (185
                )
                
                
                (7,722
                )Sales
      of reserves in place
                
                
                -
                
                
                
                -End
      of year 2007
                
                
                897
                
                
                
                43,847Revision
      of previous estimates
                
                
                2,911
                
                
                
                (11,150
                )Extensions
      and discoveries
                
                
                278
                
                
                
                2,399Purchase
      of reserves in place
                
                
                -
                
                
                
                -Production
                
                
                (159
                )
                
                
                (7,194
                )Sales
      of reserves in place
                
                
                -
                
                
                
                (951
                )End
      of year 2008
                
                
                3,927
                
                
                
                26,951Net
      proved developed reserves after royaltiesEnd
      of year 2006
                
                
                1,104
                
                
                
                31,637End
      of year 2007
                
                
                797
                
                
                
                37,454End
      of year 2008
                
                
                3,649
                
                
                
                23,105





Notes:


1.
            Net
      after royalty reserves are the Trust’s overriding royalty and working
      interest share of the gross remaining reserves, after deduction of any
      crown, freehold and overriding royalties.  Such royalties are
      subject to change by legislation or regulation and can also vary depending
      on production rates, selling prices and timing of initial
      production.


2.
            Reserves
      are the estimated quantities of crude oil, natural gas and related
      substances anticipated from geological and engineering data to be
      recoverable from known accumulations, from a given date forward, by known
      technology, under existing operating conditions and prices in effect at
      year end.


3.
            Proved
      oil and gas reserves are the estimated quantities of crude oil, natural
      gas and natural gas liquids which geological and engineering data
      demonstrate with reasonable certainty to be recoverable in future years
      from known reservoirs under existing economic and operating
      conditions.


4.
            Proved
      developed oil and gas reserves are reserves that can be expected to be
      recovered through existing wells with existing equipment and operating
      methods.  Proved undeveloped reserves are reserves that are
      expected to be recovered from known accumulations where a significant
      expenditure is required.







STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS
RESERVES




The
following information has been developed utilizing procedures described by SFAS
No. 69 and based on crude oil and natural gas reserve and production
volumes estimated by the independent engineering consultants of the
Trust.  It may be useful for certain comparison purposes, but should
not be solely relied upon in evaluating the Trust or its
performance.  Further, information contained in the following table
should not be considered as representative of realistic assessments of future
cash flows, nor should the Standardized Measure of Discounted Future Net Cash
Flows be viewed as representative of the current value of Enterra’s
reserves.




The
future cash flows presented below are based on sales prices, cost rates, and
statutory income tax rates in existence as of the date of the
projections.  It is expected that material revisions to some estimates
of crude oil and natural gas reserves may occur in the future, development and
production of the reserves may occur in periods other than those assumed, and
actual prices realized and costs incurred may vary significantly from those
used.




Management
does not rely upon the following information in making investment and operating
decisions.  Such decisions are based upon a wide range of factors,
including estimates of probable as well as proved reserves, and varying price
and cost assumptions considered more representative of a range of possible
economic conditions that may be anticipated.




The
computation of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves at December 31, 2008 was based on
the following benchmark prices: Edmonton light crude price of $45.12/bbl,
Alberta average plant gate price of $6.15/mcf, WTI oil price of US$44.60/bbl and
US Henry Hub gas prices of US$5.71/mcf.  The computation of the
standardized measure of discounted future net cash flows relating to proved oil
and gas reserves at December 31, 2007 was based on the following benchmark
prices: Edmonton light crude price of $93.76/bbl, Alberta average plant gate
price of $6.32/mcf, WTI oil price of US$95.48/bbl and US Henry Hub gas prices of
US$7.83/mcf.  The computation of the standardized measure of
discounted future net cash flows relating to proved oil and gas reserves at
December 31, 2006 was based on the following benchmark prices: Edmonton
light crude price of $67.06/bbl, Alberta average plant gate price of $5.93/mcf,
and US Henry Hub gas prices of US$5.63/mcf.




The
following table sets forth the standardized measure of discounted future net
cash flows from projected production of the Trust’s crude oil and natural gas
reserves at December 31 for the years presented.




(million
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2008
      TotalFuture
      cash inflows
                
                
                210
                
                
                
                369
                
                
                
                579Future
      costs:Future
      production and development costs
                
                
                (160
                )
                
                
                (181
                )
                
                
                (341
                )Future
      income taxes
                
                
                -
                
                
                
                (32
                )
                
                
                (32
                )Future
      net cash flows
                
                
                50
                
                
                
                156
                
                
                
                206Deduct:
      10% annual discount factor
                
                
                (9
                )
                
                
                (45
                )
                
                
                (54
                )Standardized
      measure of discounted future net cash flows
                
                
                41
                
                
                
                111
                
                
                
                152







(millions
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2007
      TotalFuture
      cash inflows
                
                
                431
                
                
                
                389
                
                
                
                820Future
      costs:Future
      production and development costs
                
                
                (212
                )
                
                
                (153
                )
                
                
                (365
                )Future
      income taxes
                
                
                (18
                )
                
                
                (15
                )
                
                
                (33
                )Future
      net cash flows
                
                
                201
                
                
                
                221
                
                
                
                422Deduct:
      10% annual discount factor
                
                
                (43
                )
                
                
                (72
                )
                
                
                (115
                )Standardized
      measure of discounted future net cash flows
                
                
                158
                
                
                
                149
                
                
                
                307







(millions
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2006
      TotalFuture
      cash inflows
                
                
                390
                
                
                
                297
                
                
                
                687Future
      costs:Future
      production and development costs
                
                
                (185
                )
                
                
                (107
                )
                
                
                (292
                )Future
      income taxes
                
                
                (10
                )
                
                
                (7
                )
                
                
                (17
                )Future
      net cash flows
                
                
                195
                
                
                
                183
                
                
                
                378Deduct:
      10% annual discount factor
                
                
                (43
                )
                
                
                (52
                )
                
                
                (95
                )Standardized
      measure of discounted future net cash flows
                
                
                152
                
                
                
                131
                
                
                
                283










Enterra Energy Trust Form 20 –
F





CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL
AND GAS RESERVES




The
following table sets forth the changes in the standardized measure of discounted
future net cash flows at December 31 for the years presented:




(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2008
      TotalFuture
      discounted net cash flows at beginning of year
                
                
                158,353
                
                
                
                149,495
                
                
                
                307,848Revenues,
      net of royalties and production costs
                
                
                (18,939
                )
                
                
                (32,880
                )
                
                
                (51,819
                )Change
      due to prices, net of production costs
                
                
                (111,783
                )
                
                
                (98,040
                )
                
                
                (209,823
                )Development
      costs during the year
                
                
                11,121
                
                
                
                19,143
                
                
                
                30,264Changes
      in estimated future development costs
                
                
                (1,000
                )
                
                
                (20,022
                )
                
                
                (21,022
                )Changes
      due to extensions, discoveries and improved recovery
                
                
                2,428
                
                
                
                17,609
                
                
                
                20,037Change
      due to revisions
                
                
                (10,893
                )
                
                
                27,346
                
                
                
                16,453Acquisitions
      of reserves
                
                
                54
                
                
                
                -
                
                
                
                54Disposition
      of reserves
                
                
                (22,055
                )
                
                
                (4,117
                )
                
                
                (26,172
                )Accretion
      of discount
                
                
                15,835
                
                
                
                14,950
                
                
                
                30,785Other
      significant factors
                
                
                -
                
                
                
                32,587
                
                
                
                32,587Changes
      in income taxes
                
                
                17,879
                
                
                
                5,212
                
                
                
                23,091Future
      discounted net cash flows at end of year
                
                
                41,000
                
                
                
                111,283
                
                
                
                152,283







(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2007
      TotalFuture
      discounted net cash flows at beginning of year
                
                
                152,330
                
                
                
                131,313
                
                
                
                283,643Revenues,
      net of royalties and production costs
                
                
                (55,309
                )
                
                
                (35,187
                )
                
                
                (90,496
                )Change
      due to prices, net of production costs
                
                
                60,702
                
                
                
                33,099
                
                
                
                93,801Development
      costs during the year
                
                
                16,060
                
                
                
                15,730
                
                
                
                31,790Changes
      in estimated future development costs
                
                
                (20,143
                )
                
                
                (12,282
                )
                
                
                (32,425
                )Changes
      due to extensions, discoveries and improved recovery
                
                
                6,802
                
                
                
                12,942
                
                
                
                19,744Change
      due to revisions
                
                
                (32,518
                )
                
                
                16,330
                
                
                
                (16,188
                )Acquisitions
      of reserves
                
                
                31,769
                
                
                
                -
                
                
                
                31,769Disposition
      of reserves
                
                
                (8,469
                )
                
                
                -
                
                
                
                (8,469
                )Accretion
      of discount
                
                
                15,233
                
                
                
                13,131
                
                
                
                28,364Other
      significant factors
                
                
                -
                
                
                
                (17,071
                )
                
                
                (17,071
                )Changes
      in income taxes
                
                
                (8,104
                )
                
                
                (8,510
                )
                
                
                (16,614
                )Future
      discounted net cash flows at end of year
                
                
                158,353
                
                
                
                149,495
                
                
                
                307,848








(thousands
      of dollars)
                
                Canada
                
                
                United
      States
                
                
                2006
      TotalFuture
      discounted net cash flows at beginning of year
                
                
                283,965
                
                
                
                2,812
                
                
                
                286,777Revenues,
      net of royalties and production costs
                
                
                (88,488
                )
                
                
                (46,702
                )
                
                
                (135,190
                )Change
      due to prices, net of production costs
                
                
                (71,845
                )
                
                
                (1,000
                )
                
                
                (72,845
                )Development
      costs during the year
                
                
                17,883
                
                
                
                7,735
                
                
                
                25,618Changes
      in estimated future development costs
                
                
                (17,906
                )
                
                
                (11,183
                )
                
                
                (29,089
                )Changes
      due to extensions, discoveries and improved recovery
                
                
                -
                
                
                
                9,695
                
                
                
                9,695Change
      due to revisions
                
                
                (47,326
                )
                
                
                47,615
                
                
                
                289Acquisitions
      of reserves
                
                
                25,405
                
                
                
                130,291
                
                
                
                155,696Disposition
      of reserves
                
                
                (25,672
                )
                
                
                -
                
                
                
                (25,672
                )Accretion
      of discount
                
                
                28,397
                
                
                
                281
                
                
                
                28,678Other
      significant factors
                
                
                -
                
                
                
                -
                
                
                
                -Changes
      in income taxes
                
                
                47,917
                
                
                
                (8,231
                )
                
                
                39,686Future
      discounted net cash flows at end of year
                
                
                152,330
                
                
                
                131,313
                
                
                
                283,643





Note:




1.The schedules
above are calculated using year-end prices, costs, statutory tax rates and
existing proved oil and gas reserves.  The value of exploration
properties and probable reserves, future exploration costs, future changes in
oil and gas prices and in production and development costs are
excluded.










Enterra Energy Trust Form 20 –
F







ITEM
19 – EXHIBITS




1.  By-laws of
Enterra Energy Trust, incorporated by reference.





2.
            Voting
      Trust agreement, incorporated by
reference.





3.
            Material
      Contracts, incorporated by
reference.





8.
            List
      of Subsidiaries





11.
            Code
      of Conduct





12.1
            Certification
      pursuant to Rule 13a-14(a) of the Securities Exchange
  Act.





12.2
            Certification
      pursuant to Rule 13a-14(a) of the Securities Exchange
  Act.





13.1
Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange
Act (such certificate is not deemed filed for purpose of Section 18 of the
Exchange Act and not incorporate by reference with any filings under the
Securities Act).





13.2
Certification furnished pursuant to Rule 13a-14(b) of the Securities Exchange
Act (such certificate is not deemed filed for purpose of Section 18 of the
Exchange Act and not incorporate by reference with any filings under the
Securities Act).












Enterra Energy Trust Form 20 –
F







SIGNATURES






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






Date:
June 22, 2009








Enterra
Energy Trust


‘signed’
Blaine Boerchers


Senior
V.P.  Finance and CFO










Enterra Energy Trust Form 20 –
F