ENTERRA
      ENERGY TRUSTMESSAGE
      TO UNITHOLDERS







Dear
Unitholders,






2009 was
a breakthrough year for Enterra.  Our continued focus on reducing our
debt, improving operational and capital efficiencies and replacing reserves was
rewarded with results that exceeded our expectations in a year of tremendous
economic turmoil.  During the year we also established the groundwork
for our transition to a growth oriented E&P corporation by making further
adjustments to our business model and operational approach.






Since
late 2007, we’ve been concentrating on improving our balance sheet, operating as
effectively as possible and living within our cash flow.  By this time
last year, we were able to report significant progress in all those
areas.  During 2009 and early 2010, we have continued with that
positive momentum in terms of our finances and our operations, but also with
regard to several other key achievements.






·
            Bank
      debt was reduced by 27% to $70.0 million in 2009 from $95.5 million at the
      end of 2008.  This was achieved mainly through careful cost
      control and prudent cash
management.






·
            Despite
      a constrained capital expenditure program in 2009, our reserves bookings
      increased on a proved basis by 14 percent to 22.2 mmboe from 19.5 mmboe in
      2008.  On a proved plus probable basis, our reserves increased
      by 16% in 2009 to 31.1 mmboe compared with 26.7 mmboe in
      2008.  These increases were primarily due to the improved
      performance of our Oklahoma assets including the introduction of new
      marketing contracts which give direct recognition of natural gas liquids
      (NGLs) embedded in our gas production, an overall increase in the NGL
      yield at the field level, reduced operating costs and improved reservoir
      performance.






·
            Finding
      and development costs and operating expenses were reduced during 2009
      which strengthens Enterra’s financial position going
    forward.






·
            Average
      production declined slightly to 9,878 boe/d in 2009 from 10,283 boe/d in
      2008, mainly due to our decision to shut-in uneconomical natural gas
      production during Q3 2009.  This shut-in production remains
      behind pipe and is anticipated to be brought back on stream in Q2
      2010.






·
            We
      acquired land assets in both the Cardium trend in Alberta and the Circus
      Viola play in southern Oklahoma, and additional production and acreage in
      our key Hunton play in Oklahoma.  These acquisitions have
      substantially increased our prospect inventory and growth
      potential.






·
            In
      January 2010, we announced our intention to convert to a growth oriented
      E&P corporation called Equal Energy Ltd. which we anticipate will be
      completed in Q2 2010.




All of
this was accomplished in a year where oil prices opened below US$32/bbl and gas
prices hit a seven year low below US$3/mmbtu in September.





Looking
forward, we are excited to be seeking unitholder agreement and other regulatory
approvals in May 2010 to convert from a trust into a corporation and we are
using this event to relaunch Enterra as Equal Energy Ltd.  This name
was chosen to represent the balanced approach that we take to asset development,
financial responsibility and our strategic corporate
direction.  Internally, we are continuing with the transition to a
growth oriented E&P model.




Enterra
entered 2008 with a balanced asset base with which to maintain production and
grow reserves.  During 2009, we acquired several land assets and
assembled additional prospectinventory.






We
expanded our liquids-rich, natural gas resource play in the Hunton formation in
Oklahoma by acquiring additional working interest in the operated production and
purchasing additional land.  The Hunton play is a key asset
representing more than 50 percent of our daily production, with low operating
costs and compelling economics.  F&D costs are less than $9.00 per
boe, reserves per well exceed 327,000 boe, and our recycle ratio is 2.2
times.  We have identified the potential for 120 drilling locations on
one section spacing.  In 2010, we are planning six to 12 wells in the
Hunton area starting midyear.  The scope of the Hunton play will be a
profound contributor to Enterra’s long term growth.  A dozen new wells
in this play have the potential to completely replace our produced reserves for
the year.






Starting
in Q3 2009, we began assembling land assets in the Cardium oil trend in west
central Alberta which represents a new area for Enterra.  The Cardium
formation, an arc-shaped clastic wedge extends over a 1,000 kilometres for
Dawson Creek in northeast BC to the Canadian/U.S. border and includes numerous
discovered fields.  These extensive tight oil reservoirs have been
challenging to exploit economically with vertical wells tending to have low
daily production levels.  More recently the application of horizontal
drilling with multi-stage fracture stimulation have these tight rocks now
yielding far higher initial and improved sustained production rates which is
revitalizing the potential of the traditional areas and opening up new
trends.  We are currently drilling the first of two horizontal wells
on our Cardium land base and have up to 30 additional potential locations
identified on our land and are continuing to acquire additional land to build
our position.






We also
acquired a 40 percent working interest in more than 12,000 acres in the Circus
Viola oil prospect in southern Oklahoma.  This is another potential
resource play that offers us significant growth opportunities and we drilled two
well out of a possible four wells in 2010 and are currently determining the
fracture stimulation program for these wells.






In
addition to the opportunities represented by our Hunton, Cardium and Circus
Viola plays, we have been re-evaluating our existing assets, to clearly
delineate our prospect inventory and growth opportunities in other areas like
our Viking, Dina and Pekisko oil plays for later in 2010 and
beyond.






By the
end of 2009, we had made important progress setting Enterra up for success as a
growth oriented E&P corporation with significant opportunities defined for
2010 and beyond.






Personally,
I’d like to thank my colleagues at Enterra as 2009 was a busy and productive
year for the Trust.  Our positive results this year were delivered
through hard work, passion and conviction.  I’d like to express my
appreciation to our unitholders for their continued support; our units delivered
excellent returns in 2009 and we believe we have the growth potential to deliver
further upside.  And finally, I’d like to acknowledge the Board
members for their guidance to the executive team during an important
transitional year.




Sincerely,









Don
Klapko


President
and Chief Executive Officer


March 29,
2010














ANNUAL 2009
REPORT
 
 ENTERRA
      ENERGY TRUSTMANAGEMENT
      DISCUSSION AND ANALYSIS


INTRODUCTION:  The following is
Management’s Discussion and Analysis (“MD&A”) of Enterra Energy Trust (“the
Trust” or “Enterra”) for the year ended December 31, 2009.  This
MD&A should be read in conjunction with the consolidated financial
statements, together with the accompanying notes, of the Trust for the years
ended December 31, 2009 and 2008.  All amounts are stated in Canadian
dollars and are prepared in accordance with Canadian Generally Accepted
Accounting Principles (“GAAP”) except where otherwise indicated.  This
commentary is based on information available to, and is dated, March 25,
2010.





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





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





This
MD&A also contains other terms such as net debt and operating netbacks which
are not recognized measures under GAAP.  Management believes these
measures are useful supplemental measures of firstly, the total amount of
current and long-term debt and secondly, the amount of revenues received after
transportation, royalties and operating costs.  Readers are cautioned,
however that these measures should not be construed as an alternative to other
terms such as current and long-term debt or net income determined in accordance
with GAAP as measures of performance.  Enterra’s method of calculating
these measures may differ from other entities, and accordingly, may not be
comparable measures used by other trusts or companies.





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


ANNUAL 2009
REPORT
 
 ENTERRA
      ENERGY TRUSTMANAGEMENT
      DISCUSSION AND ANALYSIS


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.









CORPORATE
PROFILE




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).





Enterra’s
portfolio of oil and gas properties is geographically diversified with producing
properties located principally in Alberta, British Columbia, Saskatchewan and
Oklahoma.  Production in 2009 was comprised of approximately 28% oil,
22% natural gas liquids (NGLs) and 50% natural gas.  As a result of
new 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 2010 production mix is expected to be about 29% oil,
25% natural gas liquids and 46% natural gas.




















2009
      Financial and Operations Summary
              (in
      thousands except for volumes, percentages and  per unit and boe
      amounts)
            
            2009
            
            
            2008
            
            
            Change
            
            
            2007FINANCIALRevenue
      before mark-to-market adjustment (1)
            
            
            140,506
            
            
            
            255,268
            
            
            
            (45
            %)
            
            
            233,828Funds
      from operations (1)
            
            
            46,645
            
            
            
            107,345
            
            
            
            (57
            %)
            
            
            72,688Per
      unit – basic (2)
      ($)
            
            
            0.74
            
            
            
            1.74
            
            
            
            
            
            
            
            1.22Per
      unit – diluted (2)
      ($)
            
            
            0.74
            
            
            
            1.70
            
            
            
            
            
            
            
            1.22Net
      income (loss)
            
            
            (41,282
            )
            
            
            7,061
            
            
            
            
            
            
            
            (142,036
            )Per
      unit – basic (2)
      ($)
            
            
            (0.65
            )
            
            
            0.11
            
            
            
            
            
            
            
            (2.38
            )Per
      unit – diluted (2)
      ($)
            
            
            (0.65
            )
            
            
            0.11
            
            
            
            
            
            
            
            (2.38
            )Total
      assets
            
            
            462,272
            
            
            
            587,018
            
            
            
            
            
            
            
            599,790Net
      debt (3)
            
            
            35,955
            
            
            
            52,389
            
            
            
            
            
            
            
            168,209Convertible
      debentures
            
            
            114,863
            
            
            
            113,420
            
            
            
            
            
            
            
            111,692Unitholders’
      equity
            
            
            219,046
            
            
            
            294,416
            
            
            
            
            
            
            
            219,184UNITS
      OUTSTANDINGUnits
      outstanding – basic (2)
      (000s)
            
            
            63,358
            
            
            
            61,661
            
            
            
            
            
            
            
            59,766Units
      outstanding – diluted (2)
      (000s)
            
            
            63,358
            
            
            
            63,012
            
            
            
            
            
            
            
            59,766Units
      outstanding at period end (2)
      (000s)
            
            
            65,103
            
            
            
            62,159
            
            
            
            
            
            
            
            61,436OPERATIONSAverage
      daily productionOil
      (bbls per day)
            
            
            2,779
            
            
            
            3,660
            
            
            
            (24
            %)
            
            
            4,350NGL
      (bbls per day)
            
            
            2,156
            
            
            
            96
            
            
            
            100
            %
            
            
            348Gas
      (mcf per day)
            
            
            29,657
            
            
            
            39,162
            
            
            
            (24
            %)
            
            
            46,378Total
      (boe per day)
            
            
            9,878
            
            
            
            10,283
            
            
            
            (4
            %)
            
            
            12,428Exit
      productionOil
      (bbls per day)
            
            
            2,448
            
            
            
            3,144
            
            
            
            (22
            %)
            
            
            3,595NGL
      (bbls per day)
            
            
            2,515
            
            
            
            1,106
            
            
            
            127
            %
            
            
            357Gas
      (mcf per day)
            
            
            24,802
            
            
            
            33,321
            
            
            
            (26
            %)
            
            
            45,031Total
      (boe per day)
            
            
            9,097
            
            
            
            9,804
            
            
            
            (7
            %)
            
            
            11,457Average
      sales priceOil
      ($ per bbl)
            
            
            62.86
            
            
            
            92.57
            
            
            
            (32
            %)
            
            
            62.33NGL
      ($ per bbl)
            
            
            32.17
            
            
            
            72.15
            
            
            
            (55
            %)
            
            
            55.69Gas
      ($ per mcf)
            
            
            4.75
            
            
            
            8.98
            
            
            
            (47
            %)
            
            
            7.04Cash
      flow netback (1)
      ($ per boe)Revenue
      (4)
            
            
            38.97
            
            
            
            67.83
            
            
            
            (43
            %)
            
            
            49.34Royalties
            
            
            7.37
            
            
            
            15.50
            
            
            
            (52
            %)
            
            
            10.00Production
      expenses
            
            
            10.88
            
            
            
            14.61
            
            
            
            (26
            %)
            
            
            13.53Transportation
      expenses
            
            
            0.70
            
            
            
            0.85
            
            
            
            (18
            %)
            
            
            0.66Operating
      netback
            
            
            20.02
            
            
            
            36.87
            
            
            
            (46
            %)
            
            
            25.15General
      and administrative
            
            
            4.36
            
            
            
            4.21
            
            
            
            4
            %
            
            
            4.50Cash
      interest expense
            
            
            2.66
            
            
            
            4.04
            
            
            
            (34
            %)
            
            
            4.46Other
      cash costs
            
            
            0.06
            
            
            
            0.10
            
            
            
            (40
            %)
            
            
            0.17Cash
      flow netback
            
            
            12.94
            
            
            
            28.52
            
            
            
            (55
            %)
            
            
            16.02


(1)
            Revenues
      before mark-to-market adjustment, funds from operations and cash flow
      netback are non-GAAP financial measures.  Please refer to
      “Revenues” and “Non-GAAP Financial
Measures”.


(2)
            Weighted
      average units outstanding.  See note 10 in Notes to Financial
      Statements.


(3)
            Net
      debt is a non-GAAP term and includes total long-term debt, long-term
      receivables, current assets and current liabilities (excluding commodity
      contracts and future income taxes).


(4)
            Price
      received excludes unrealized mark-to-market gain or
  loss.


ANNUAL 2009
REPORT
 
 ENTERRA
      ENERGY TRUSTMANAGEMENT
      DISCUSSION AND ANALYSIS


QUARTERLY
FINANCIAL INFORMATION(in thousands of Canadian dollars
except for per unit amounts)




2009
            
            
            2008Q4
            
            
            
            Q3
            
            
            
            Q2
            
            
            
            Q1
            
            
            
            Q4
            
            
            
            Q3
            
            
            
            Q2
            
            
            
            Q1Revenues
      before mark-to-market adjustment
            
            
            37,055
            
            
            
            30,354
            
            
            
            31,208
            
            
            
            41,889
            
            
            
            55,924
            
            
            
            68,025
            
            
            
            71,004
            
            
            
            60,315Funds
      from operations
            
            
            11,803
            
            
            
            8,366
            
            
            
            8,561
            
            
            
            17,915
            
            
            
            23,636
            
            
            
            27,865
            
            
            
            31,588
            
            
            
            24,256Income
      (loss) before taxes
            
            
            (8,930
            )
            
            
            (13,259
            )
            
            
            (23,823
            )
            
            
            (12,864
            )
            
            
            13,497
            
            
            
            24,218
            
            
            
            (16,366
            )
            
            
            (9,457
            )Net
      income (loss)
            
            
            (8,939
            )
            
            
            (9,462
            )
            
            
            (14,383
            )
            
            
            (8,498
            )
            
            
            5,907
            
            
            
            14,916
            
            
            
            (11,855
            )
            
            
            (1,907
            )Net
      income (loss) per unit basic ($)
            
            
            (0.14
            )
            
            
            (0.15
            )
            
            
            (0.23
            )
            
            
            (0.14
            )
            
            
            0.10
            
            
            
            0.24
            
            
            
            (0.19
            )
            
            
            (0.03
            )Net
      income (loss) per unit diluted ($)
            
            
            (0.14
            )
            
            
            (0.15
            )
            
            
            (0.23
            )
            
            
            (0.14
            )
            
            
            0.09
            
            
            
            0.23
            
            
            
            (0.19
            )
            
            
            (0.03
            )Distributions
      declared per unit  (US$)
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -





The
losses in 2009 are mainly due to the decrease in commodity prices for oil and
natural gas.  The loss in Q2 2008 was mainly due to the unrealized
loss on the commodity contracts as a result of the high commodity prices which
subsequently reversed during the second half of 2008 resulting in an increase in
net income for Q3 2008 and Q4 2008.  Enterra’s revenue and income,
like others in the oil and gas industry, are driven by the prices of oil and
natural gas.




OVERALL
PERFORMANCE




Enterra
has decreased long-term debt during the year to $70.0 million from $95.5 million
at the beginning of the year through prudent cash management.  The
current credit facility remains at $110.0 million.  This borrowing
capacity in addition to the funds generated from operations, provides Enterra
with sufficient flexibility to continue with its objective of proving up some of
its recently acquired oil plays in the Cardium and Circus Viola prospects and
also drilling in the liquids rich Hunton play in Oklahoma during
2010.





Average
production in 2009 of 9,878 boe per day decreased compared to average production
in 2008 of 10,283 boe per day.  The natural decline rates for
Enterra’s wells and the shut-in of certain uneconomical wells due to low
commodity prices were offset by limited drilling and a small acquisition last
year and a new contractual recognition of NGLs in our Oklahoma production
streams.  During Q3 2009, Enterra shut-in approximately 500 boe per
day of natural gas production because costs exceeded revenues due to low
commodity prices.  This production is anticipated to be restored in Q2
2010 since there has been sustained improvement in the natural gas market and an
interest in a processing facility has been purchased that will help lower
Enterra’s processing costs for that area.  Enterra exited the year
with sales volumes of approximately 9,097 boe per day which was down
significantly compared to the Q4 2009 average production of 9,582 boe per day
due to a severe winter storm that hit Oklahoma near the end of the
year.





Enterra
is now reporting NGL volumes and revenues separate from oil because they have
become significant as a result of the benefits of the new marketing contracts
becoming fully effective in May 2009.





Overall,
oil prices received in 2009 decreased 32% to $62.86 per barrel from $92.57 per
barrel in 2008.  NGL prices received in 2009 decreased 55% to $32.17
per barrel from $72.15 per barrel in 2008.  Natural gas prices
received in 2009 decreased 47% to $4.75 per mcf from $8.98 per mcf in
2008.  Production expenses, excluding non-cash expenses, in 2009
decreased 25% to $10.88 per boe compared to $14.61 per boe in 2008.





G&A
expenses were flat on dollar basis in 2009 but increased to $4.36 per boe
compared to $4.21 per boe in 2008 on a per barrel basis due to lower production
volumes in 2009.  Interest expenses decreased 34% to $11.5 million in
2009 compared to $17.5 million in 2008 due to the combined effect of lower
average borrowings on bank facilities and the decline in interest
rates.


The
overall impact was that funds from operations in 2009 decreased by 57% to $46.6
million from $107.3 million in 2008, primarily as a result of lower commodity
prices.  The loss in 2009 was $41.3 million compared to net income of
$7.1 million from 2008.




SALES
VOLUMES




ProductionThree
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeDaily
      sales volumes – averageOil
      (bbls per day)
            
            
            2,530
            
            
            
            3,544
            
            
            
            (29
            %)
            
            
            2,779
            
            
            
            3,660
            
            
            
            (24
            %)NGL
      (bbls per day)
            
            
            2,749
            
            
            
            96
            
            
            
            100
            %
            
            
            2,156
            
            
            
            96
            
            
            
            100
            %Natural
      gas (mcf per day)
            
            
            25,815
            
            
            
            38,329
            
            
            
            (33
            %)
            
            
            29,657
            
            
            
            39,162
            
            
            
            (24
            %)Total
      (boe per day)
            
            
            9,582
            
            
            
            10,028
            
            
            
            (4
            %)
            
            
            9,878
            
            
            
            10,283
            
            
            
            (4
            %)Daily
      sales volumes – exit rateOil
      (bbls per day)
            
            
            2,448
            
            
            
            3,144
            
            
            
            (22
            %)
            
            
            2,448
            
            
            
            3,144
            
            
            
            (22
            %)NGL
      (bbls per day)
            
            
            2,515
            
            
            
            1,106
            
            
            
            127
            %
            
            
            2,515
            
            
            
            1,106
            
            
            
            127
            %Natural
      gas (mcf per day)
            
            
            24,802
            
            
            
            33,321
            
            
            
            (26
            %)
            
            
            24,802
            
            
            
            33,321
            
            
            
            (26
            %)Total
      (boe per day)
            
            
            9,097
            
            
            
            9,804
            
            
            
            (7
            %)
            
            
            9,097
            
            
            
            9,804
            
            
            
            (7
            %)Sales
      volumes mix by productOil
            
            
            26
            %
            
            
            35
            %
            
            
            
            
            
            
            28
            %
            
            
            36
            %NGL
            
            
            29
            %
            
            
            1
            %
            
            
            
            
            
            
            22
            %
            
            
            1
            %Natural
      gas
            
            
            45
            %
            
            
            64
            %
            
            
            
            
            
            
            50
            %
            
            
            63
            %100
            %
            
            
            100
            %
            
            
            
            
            
            
            100
            %
            
            
            100
            %





Average
production for 2009 was 9,878 boe per day which is a decrease of 4% compared to
10,283 boe per day during 2008.  The overall decrease is mainly due to
the shut-in of certain uneconomical wells during part of the year due to low
commodity prices and natural decline rates offset by the additional wells
drilled during the last year, the increased NGL volumes recognized from new
marketing contracts in Oklahoma and additional production from the acquisition
of additional working interests in certain Hunton properties.





Average
production for Q4 2009 was 9,582 boe per day which is a decrease of 4% compared
to 10,028 boe per day in Q4 2008.  The decrease in production is
mainly due to the natural decline rates on Enterra’s wells and shut-in of
certain uneconomical wells.  Q4 2009 production also decreased 3%
compared to Q3 2009 production of 9,907 boe per day.





Average
production during 2009 consisted of 2,779 bbls per day of oil, 2,156 bbls per
day of NGL and 29,657 mcf per day of natural gas, resulting in a mix of 28% oil,
22% NGL and 50% natural gas.  Enterra exited 2009 with production of
9,097 boe per day.  As a result of new 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 2010
production mix is expected to be about 29% oil, 25% natural gas liquids and 46%
natural gas.





For 2009,
Enterra drilled 4 (1.5 net) gas wells, 1 (1.0 net) salt water disposal well and
1 (1.0 net) dry hole.  Three of the four gas wells were drilled in
Oklahoma with 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.














Production
      by Geographic AreaThree
      months ended December 31, 2009
            
            
            Year
      ended
              December
      31, 2009Canada
            
            
            U.S.
            
            
            Canada
            
            
            U.S.Daily
      sales volumes – averageOil
      (bbls per day)
            
            
            2,176
            
            
            
            354
            
            
            
            2,365
            
            
            
            414NGL
      (bbls per day)
            
            
            90
            
            
            
            2,659
            
            
            
            81
            
            
            
            2,075Natural
      gas (mcf per day)
            
            
            9,857
            
            
            
            15,958
            
            
            
            11,815
            
            
            
            17,842Total
      (boe per day)
            
            
            3,909
            
            
            
            5,673
            
            
            
            4,415
            
            
            
            5,463Daily
      sales volumes - exit rateOil
      (bbls per day)
            
            
            2,157
            
            
            
            291
            
            
            
            2,157
            
            
            
            291NGL
      (bbls per day)
            
            
            83
            
            
            
            2,432
            
            
            
            83
            
            
            
            2,432Natural
      gas (mcf per day)
            
            
            10,092
            
            
            
            14,710
            
            
            
            10,092
            
            
            
            14,710Total
      (boe per day)
            
            
            3,922
            
            
            
            5,175
            
            
            
            3,922
            
            
            
            5,175Sales
      volumes mix by productOil
            
            
            56
            %
            
            
            6
            %
            
            
            54
            %
            
            
            8
            %NGL
            
            
            2
            %
            
            
            47
            %
            
            
            2
            %
            
            
            38
            %Natural
      gas
            
            
            42
            %
            
            
            47
            %
            
            
            44
            %
            
            
            54
            %100
            %
            
            
            100
            %
            
            
            100
            %
            
            
            100
            %





Canadian
Operations




For 2009,
production in Canada of 4,415 boe per day was down 22% compared to 5,643 boe per
day during 2008.  The decrease in production is due to the asset
disposition program which occurred in the first half of 2008, natural decline
rates and the shut-in of certain uneconomical wells during the year due to low
commodity prices.  In the Ricinus area, the equivalent of 240 boe per
day over the course of the year of natural gas production was shut-in due to low
natural gas prices.





For the
three months ended December 31, 2009, production in Canada of 3,909 boe per day
was down 28% compared to Q4 2008 production of 5,445 boe per day due to natural
declines rates and the shut-in of certain uneconomical wells due to low
commodity prices including the Ricinus area.  Q4 2009 production
decreased 7% from Q3 2009 production of 4,203 boe per day which is higher than
normal decline rates mainly due to operational problems experienced at the Desan
gas well sites that currently have been restored to normal producing
levels.





U.S.
Operations




For 2009,
production in the United States of 5,463 boe per day was up 18% compared to
4,640 boe per day during 2008.  The increase in production is due to
the effect of new marketing contracts for NGLs, the acquisition of additional
working interest in certain Hunton properties and inclining production during
the first half of the year from Hunton wells completed in late 2008 and early
2009.





For the
three months ended December 31, 2009, production in the United States of 5,673
boe per day was 24% higher compared to Q4 2008 production of 4,583 boe per
day.  The increase in production is mainly due to the recognition of
NGL volumes due to the revised midstream contracts and the additional production
from the acquisition of additional working interests in certain Hunton
properties.  Q4 2009 production of 5,673 boe per day was similar to Q3
2009 production of 5,704 boe per day.
















COMMODITY
PRICING




Pricing
      BenchmarksThree
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeWTI
      (US$ per bbl)
            
            
            76.19
            
            
            
            58.73
            
            
            
            30
            %
            
            
            61.80
            
            
            
            99.65
            
            
            
            (38
            %)Average
      exchange rate: Cdn$ to US$1.00
            
            
            1.06
            
            
            
            1.21
            
            
            
            (12
            %)
            
            
            1.14
            
            
            
            1.07
            
            
            
            7
            %WTI
      (Cdn$ per bbl)
            
            
            80.76
            
            
            
            71.06
            
            
            
            14
            %
            
            
            70.45
            
            
            
            106.62
            
            
            
            (34
            %)Propane,
      Conway, KS (US$/bbl)
            
            
            45.94
            
            
            
            35.61
            
            
            
            29
            %
            
            
            33.90
            
            
            
            58.86
            
            
            
            (42
            %)AECO
      daily index (Cdn$ per GJ)
            
            
            4.26
            
            
            
            6.34
            
            
            
            (33
            %)
            
            
            3.74
            
            
            
            7.71
            
            
            
            (51
            %)NYMEX
      (US$ per mmbtu)
            
            
            4.27
            
            
            
            6.77
            
            
            
            (37
            %)
            
            
            4.04
            
            
            
            8.93
            
            
            
            (55
            %)





West
Texas Intermediate (“WTI”) is a standard benchmark for the price of oil and is
expressed in U.S. dollars per barrel.  The propane price quoted at
Conway, KS is the closest surrogate benchmark for the blended price Enterra
receives for its NGL produced in Oklahoma.  The price variations at
Conway, KS mirror Enterra’s variations in NGL price but cannot be used to
estimate Enterra’s actual NGL mix due to variations in
composition.  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.





Benchmark
oil prices for 2009 decreased 38% to an average of US$61.80 per bbl WTI from
US$99.65 per bbl WTI in 2008 but the price decrease was off-set by the weakening
of the Canadian dollar which averaged Cdn$1.14 per U.S. dollar during 2009
compared to Cdn$1.07 per U.S. dollar during 2008.





Benchmark
oil prices for Q4 2009 increased 30% to an average of US$76.19 per bbl WTI from
US$58.73 per bbl WTI in Q4 2008 but the price increase was off-set by the
strengthening of the Canadian dollar which averaged Cdn$1.06 per U.S. dollar
during Q4 2009 compared to Cdn$1.21 per U.S. dollar during Q4 2008.





Benchmark
propane prices for 2009 decreased 42% to an average of US$33.90 per bbl from
US$58.86 per bbl in 2008.  Benchmark propane prices for Q4 2009
increased 29% to an average of US$45.94 per bbl from US$35.61 per bbl in Q4
2008.





In
Canada, AECO pricing decreased 51% averaging $3.74 per GJ during 2009 compared
to $7.71 during 2008.  AECO pricing also decreased 33% averaging $4.26
per GJ during Q4 2009 compared to $6.34 during Q4 2008.





In the
U.S., natural gas prices for 2009 on the NYMEX decreased 55% to an average of
US$4.04 per mmbtu from US$8.93 per mmbtu in 2008.  Natural gas prices
for Q4 2009 on the NYMEX decreased 37% to an average of US$4.27 per mmbtu from
US$6.77 per mmbtu in Q4 2008.





Average
      Commodity Prices ReceivedThree
      months ended December 31
            
            
            Year
      ended December 312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeOil
      (1)
      (Cdn$ per bbl)
            
            
            69.81
            
            
            
            53.02
            
            
            
            32
            %
            
            
            58.47
            
            
            
            92.06
            
            
            
            (36
            %)NGL
      (Cdn$ per bbl)
            
            
            41.63
            
            
            
            52.84
            
            
            
            (21
            %)
            
            
            32.17
            
            
            
            72.15
            
            
            
            (55
            %)Natural
      gas (Cdn$ per mcf)
            
            
            4.01
            
            
            
            7.12
            
            
            
            (44
            %)
            
            
            3.69
            
            
            
            8.94
            
            
            
            (59
            %)Oil
      commodity contract settlements (Cdn$ per bbl)
            
            
            1.02
            
            
            
            30.54
            
            
            
            (97
            %)
            
            
            4.39
            
            
            
            0.51
            
            
            
            100
            %Natural
      gas commodity contract settlements  (Cdn$ per
    mcf)
            
            
            0.22
            
            
            
            0.88
            
            
            
            (75
            %)
            
            
            1.06
            
            
            
            0.04
            
            
            
            100
            %Combined
      oil (1)
      (Cdn$ per bbl)
            
            
            70.83
            
            
            
            83.56
            
            
            
            (15
            %)
            
            
            62.86
            
            
            
            92.57
            
            
            
            (32
            %)Combined
      natural gas (Cdn$ per mcf)
            
            
            4.23
            
            
            
            8.00
            
            
            
            (47
            %)
            
            
            4.75
            
            
            
            8.98
            
            
            
            (47
            %)Total
      (2)
      (Cdn$ per boe)
            
            
            42.04
            
            
            
            60.62
            
            
            
            (31
            %)
            
            
            38.97
            
            
            
            67.83
            
            
            
            (43
            %)


(1)
            Includes
      sulphur revenue.


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


For 2009,
the average price received for oil by Enterra, net of commodity contract
settlements, decreased 32% to $62.86 per bbl from $92.57 per bbl during
2008.  The average price received for NGLs in 2009 decreased 55% to
$32.17 per bbl from $72.15 per bbl during 2008.  The average price
received for natural gas in 2009, net of commodity contract settlements,
decreased 47% to $4.75 per mcf from $8.98 per mcf during 2008.





For the
three months ended December 31, 2009, the average price received for oil by
Enterra, net of commodity contract settlements, decreased 15% to $70.83 per bbl
from $83.56 per bbl in Q4 2008.  For the three months ended December
31, 2009, the average price received for NGLs decreased 21% to $41.63 per bbl
from $52.84 per bbl in Q4 2008.  The Q4 2009 average price received
for natural gas, net of commodity contract settlements, decreased 47% to $4.23
per mcf from $8.00 per mcf in Q4 2008.




REVENUES




Revenues(in thousands
      of Canadian dollars except for percentages)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeOil
            
            
            16,485
            
            
            
            27,250
            
            
            
            (40
            %)
            
            
            63,765
            
            
            
            124,021
            
            
            
            (49
            %)NGL
            
            
            10,528
            
            
            
            465
            
            
            
            100
            %
            
            
            25,313
            
            
            
            2,536
            
            
            
            100
            %Natural
      gas
            
            
            10,042
            
            
            
            28,209
            
            
            
            (64
            %)
            
            
            51,428
            
            
            
            128,711
            
            
            
            (60
            %)Revenue
      before mark-to-market adjustments (1)
            
            
            37,055
            
            
            
            55,924
            
            
            
            (34
            %)
            
            
            140,506
            
            
            
            255,268
            
            
            
            (45
            %)Unrealized
      mark-to-market gain (loss) on commodity contracts
            
            
            (1,271
            )
            
            
            16,095
            
            
            
            (108
            %)
            
            
            (13,678
            )
            
            
            20,229
            
            
            
            (168
            %)Oil
      and natural gas revenues
            
            
            35,784
            
            
            
            72,019
            
            
            
            (50
            %)
            
            
            126,828
            
            
            
            275,497
            
            
            
            (54
            %)


(1)  Non–GAAP
measure.





Revenues by Geographic Area(in thousands
      of Canadian dollars)Three
      months ended
              December
      31, 2009
            
            
            Year
      ended
              December
      31, 2009Canada
            
            
            U.S.
            
            
            Canada
            
            
            U.S.Oil
            
            
            13,785
            
            
            
            2,700
            
            
            
            53,710
            
            
            
            10,055NGL
            
            
            466
            
            
            
            10,062
            
            
            
            1,361
            
            
            
            23,952Natural
      gas
            
            
            4,137
            
            
            
            5,905
            
            
            
            19,474
            
            
            
            31,954Revenue
      before mark-to-market adjustments (1)
            
            
            18,388
            
            
            
            18,667
            
            
            
            74,545
            
            
            
            65,961Unrealized
      mark-to-market gain (loss) on commodity contracts
            
            
            (1,159
            )
            
            
            (112
            )
            
            
            (12,896
            )
            
            
            (782
            )Oil
      and natural gas revenues
            
            
            17,229
            
            
            
            18,555
            
            
            
            61,649
            
            
            
            65,179


(1)
            Non–GAAP
      measure.





Oil
revenues for 2009 decreased 49% to $63.8 million from $124.0 million which was
the result of a 32% decrease in the sales price for oil received and a 24%
decrease in production volumes when compared the same period in
2008.  NGL revenues for 2009 increased significantly to $25.3 million
from $2.5 million when compared to the same period in 2008 due to the new
marketing contracts in Oklahoma which recognized the NGL portion which was
extracted from the raw gas produced.  Natural gas revenues for 2009
decreased 60% to $51.4 million from $128.7 million during the same period in
2008 which was the result of a 47% decrease in the sales price of natural gas
received and a 24% decrease in production volumes when compared to the same
period in 2008.  The decrease in natural gas revenues is due to the
lower natural gas prices in 2009 compared to 2008 and the new marketing
contracts in Oklahoma recognizing the NGL production from the liquids rich raw
gas produced.  The new marketing contracts in Oklahoma have given
Enterra greater revenues due to the price recognition for NGLs extracted from
the raw gas produced.  Natural gas prices are now primarily for the
residual dry gas after NGLs have been removed.





Oil
revenues for Q4 2009 decreased 40% to $16.5 million which was the result of a
29% decrease in production volumes and a 15% decrease in sales price received
when compared to Q4 2008.  NGL revenues for the Q4 2009 increased
significantly to $10.5 million from $0.5 million when compared to Q4 2008 due to
the new marketing contracts in Oklahoma.  Natural gas revenues in Q4
2009 decreased 64% from Q4 2008 to $10.0 million which was the result of a 47%
decrease in the sales price of natural gas received and a 33% decrease in
production volumes when compared to Q4 2008.  The decrease in natural
gas revenues is due to the lower natural gas prices in Q4 2009 compared to Q4
2008 and the new marketing contracts in Oklahoma recognizing the NGL production
from the liquids rich raw gas produced.  The new marketing contracts
in Oklahoma have given Enterra greater revenues due to the price recognition for
NGLs extracted from the raw gas produced.  Natural gas prices are now
primarily for the residual dry gas after NGLs have been removed.





For 2009,
the unrealized mark-to-market loss on commodity contracts was $13.7 million
compared to a gain of $20.2 million during the same period in
2008.  The unrealized mark-to-market loss on commodity contracts for
2009 was a result of the expiration of several commodity contracts during 2009
that were in place at the beginning of the year.  During 2009, the
realized gain for commodity price contracts was $15.9 million compared to a gain
of $1.9 million during 2008.





For Q4
2009, the unrealized mark-to-market loss on commodity contracts was to $1.3
million compared to a gain of $16.1 million during the same period in
2008.  The Q4 2009 unrealized mark-to-market loss on commodity
contracts was mainly due to the increase for the price of oil.  During
Q4 2009, the realized gain for commodity price contracts was $0.8 million
compared to a gain of $13.1 million in Q4 2008.




COMMODITY
CONTRACTS




Enterra
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 Enterra’s future production in the event of
adverse commodity price movement, while retaining significant exposure to upside
price movements.  By doing this Enterra seeks to provide a measure of
stability and predictability of cash inflows.





The
mark-to-market value of the commodity contracts is determined based on the
quoted market price as at December 31, 2009 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.  Enterra 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 2010 and based on Enterra’s assessment the counterparties are
believed to be creditworthy.





At
December 31, 2009, the following financial derivatives and fixed price contracts
were outstanding:





Derivative
      Instrument
            Commodity
            Price
            Volume
      (per day)
            PeriodFixed
            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
      mmbtuFixed
            Gas
            5.71
      (US$/mmbtu)
            2,000
      mmbtu
            January
      1, 2010 – March 31, 2010Fixed
      Basis Differential (1)
            Gas
            Differential
      Fixed @ $0.36 US$/mmbtu
            2,000
      mmbtuFixed
            Gas
            5.50
      ($/GJ)
            2,000
      GJ
            January
      1, 2010 – March 31, 2010Fixed
            Gas
            6.22
      (US$/mmbtu)
            2,000
      mmbtu
            April
      1, 2010 –
              October
      31, 2010Fixed
      Basis Differential (1)
            Gas
            Differential
      Fixed @ $0.40 US$/mmbtu
            2,000
      mmbtuFixed
            Gas
            5.70
      (US$/mmbtu)
            2,000
      mmbtu
            April
      1, 2010 –
              October
      31, 2010Fixed
      Basis Differential (1)
            Gas
            Differential
      Fixed @ $0.30 US$/mmbtu
            7,000
      mmbtu
            January
      1, 2010 – December 31, 2010Fixed
            Oil
            85.00
      ($/bbl)
            500
      bbl
            October
      1, 2009 – December 31, 2010Fixed
            Oil
            88.00
      ($/bbl)
            300
      bbl
            January
      1, 2010 – December 31, 2010


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





Enterra
did not have any physical contracts outstanding as at December 31,
2009.





As at
December 31, 2009 the above commodity contracts had a net mark-to-market asset
position of $0.2 million which decreased $14.1 million from the December 31,
2008 balance of $14.3 million.  This change relates primarily to the
expiration of several commodity contracts.





Enterra
entered into the following commodity contracts after the end of
2009:





Type
      of contract
            Commodity
            Price
            Volume
      (per day)
            PeriodFixed
      (financial)
            Gas
            5.45
      ($/GJ)
            1,000
      GJ
            March
      1, 2010 – February 28, 2011Fixed
      Sale (physical)
            Gas
            5.48
      ($/GJ)
            1,000
      GJ
            March
      1, 2010 – February 28, 2011




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. Overall,
royalties decreased in 2009 compared to 2008 due to lower commodity prices and
changes in the Alberta royalty regime.  Under Alberta’s new royalty
regime the oil crown royalty is more dependent on price and production volume
rates and as a result the royalty as a percentage of revenue has
decreased.  As a percentage of revenue before mark-to-market
adjustments, royalties were 19% for 2009 and 23% for 2008.





Royalties(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeRoyalties
            
            
            8,549
            
            
            
            10,185
            
            
            
            (16
            %)
            
            
            26,570
            
            
            
            58,350
            
            
            
            (54
            %)As
      a percentage of revenues
            
            
            23
            %
            
            
            18
            %
            
            
            
            
            
            
            19
            %
            
            
            23
            %Royalties
      per boe ($)
            
            
            9.70
            
            
            
            11.04
            
            
            
            (12
            %)
            
            
            7.37
            
            
            
            15.50
            
            
            
            (52
            %)





Royalties by Geographic Area(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)Three
      months ended December 31, 2009
            
            
            Year
      ended
              December
      31, 2009Canada
            
            
            U.S.
            
            
            Canada
            
            
            U.S.Royalties
            
            
            4,220
            
            
            
            4,329
            
            
            
            13,231
            
            
            
            13,339As
      a percentage of revenues
            
            
            23
            %
            
            
            23
            %
            
            
            18
            %
            
            
            20
            %Royalties
      per boe ($)
            
            
            11.73
            
            
            
            8.29
            
            
            
            8.21
            
            
            
            6.69





During
2009, royalties decreased 54% to $26.6 million from $58.4 million in 2008
primarily as a result of the lower prices received for oil and natural
gas.





During
the three month period ended December 31, 2009, royalties decreased 16% to $8.5
million from $10.2 million in Q4 2008 primarily as a result of the lower price
received for natural gas and a decrease in production during the course of the
quarter.  Q4 2009 royalties increased 39% compared to Q3 2009
royalties of $6.1 million due to improving oil, NGL and natural gas prices in
the fourth quarter of 2009.




PRODUCTION
EXPENSE




Production Expense(in thousands
      Canadian dollars except for percentages and per boe
      amounts)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeProduction
      expense
            
            
            8,948
            
            
            
            15,098
            
            
            
            (41
            %)
            
            
            39,659
            
            
            
            55,123
            
            
            
            (28
            %)Non-cash
      gain (loss) from power contracts
            
            
            89
            
            
            
            20
            
            
            
            100
            %
            
            
            (449
            )
            
            
            (157
            )
            
            
            186
            %Cash
      production costs
            
            
            9,037
            
            
            
            15,118
            
            
            
            (40
            %)
            
            
            39,210
            
            
            
            54,966
            
            
            
            (29
            %)Production
      expense per boe ($)
            
            
            10.15
            
            
            
            16.37
            
            
            
            (38
            %)
            
            
            11.00
            
            
            
            14.65
            
            
            
            (25
            %)Non-cash
      gain (loss) from power contracts per boe ($)
            
            
            0.10
            
            
            
            0.02
            
            
            
            100
            %
            
            
            (0.12
            )
            
            
            (0.04
            )
            
            
            100
            %Cash
      production costs per boe ($)
            
            
            10.25
            
            
            
            16.39
            
            
            
            (37
            %)
            
            
            10.88
            
            
            
            14.61
            
            
            
            (26
            %)





For 2009,
cash production costs decreased 26% to $10.88 per boe compared to $14.61 per boe
in 2008.  The decrease in costs is primarily a result of Enterra
concentrating on cost management and the decrease in costs for materials and
services in the industry during 2009.





For the
three months ended December 31, 2009, cash production costs decreased 37% to
$10.25 per boe compared to $16.39 per boe in Q4 2008 due to Enterra’s focus on
operating cost reduction and well optimization projects.  Q4 2009 cash
production expenses on a per boe basis were higher by 20% compared to $8.56 per
boe in Q3 2009 due to cost efficiencies during the first half of 2009 being
realized in Q3 2009.





Production Expense by
      Geographic Area(in thousands
      except for per boe amounts)Three
      months ended December 31, 2009
            
            
            Year
      ended
              December
      31, 2009Canada
            
            
            U.S.
            
            
            Canada
            
            
            U.S.Cash
      production costs
            
            
            6,175
            
            
            
            2,862
            
            
            
            24,322
            
            
            
            14,888Cash
      production costs per boe ($)
            
            
            17.17
            
            
            
            5.48
            
            
            
            15.09
            
            
            
            7.47





Canadian
Operations




In Canada
for 2009, cash production costs decreased by 32% to $24.3 million from $35.6
million during 2008 and on a per boe basis they decreased by 12% to $15.09 per
boe versus $17.22 per boe during 2008.  Thirty percent of the decrease
in production expenses per boe can be attributed to a decrease in costs for
materials in the industry and 70% can be attributed to a focus on operating cost
reduction and well optimization projects.





Q4 2009
cash production costs decreased by 29% to $6.2 million from $8.7 million in Q4
2008 on an overall cost basis and on a per boe basis they stayed relatively flat
at $17.17 per boe versus $17.31 per boe in Q4 2008.  Q4 2009
production costs per boe were higher by 55% compared to Q3 2009 of $11.05 per
boe due to cost efficiencies during the first half of 2009 being realized in Q3
2009.





U.S.
Operations




In the
U.S. for 2009, cash production costs decreased by 23% to $14.9 million from
$19.4 million during 2008 and on a per boe basis they decreased by 35% to $7.47
per boe versus $11.42 per boe during 2008.  The decrease in production
expenses per boe from 2008 is due to the 31% decrease in water production
volumes due to natural water production declining, fewer wells being drilled
during the year and a decrease in costs for materials and services in the
industry.





Q4 2009
cash production costs decreased by 55% to $2.9 million from $6.4 million in Q4
2008 on an overall cost basis and on a per boe basis they decreased by 64% to
$5.48 per boe versus $15.28 per boe in Q4 2008.  The decrease in
production expenses per boe from Q4 2008 is due to fewer workovers performed in
2009 due to the lower commodity price environment.  Q4 2009 production
costs per boe decreased by 19% compared to Q3 2009 production costs of $6.73 per
boe due to fewer workovers performed.




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)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeTransportation
      expense
            
            
            523
            
            
            
            810
            
            
            
            (35
            %)
            
            
            2,519
            
            
            
            3,215
            
            
            
            (22
            %)Transportation
      expense per boe ($)
            
            
            0.59
            
            
            
            0.88
            
            
            
            (33
            %)
            
            
            0.70
            
            
            
            0.85
            
            
            
            (18
            %)





For 2009,
transportation costs decreased 18% to $0.70 per boe from $0.85 per boe in
2008.  Transportation expense has varied primarily due to changing
industry costs over time.





For the
three months ended December 31, 2009, transportation costs decreased 33% to
$0.59 per boe from $0.88 per boe in Q4 2008.  Q4 2009 transportation
expenses per boe also decreased 23% compared to $0.77 per boe in Q3
2009.




GENERAL
AND ADMINISTRATIVE EXPENSE




General
and administrative expense (“G&A”) decreased by 1% in 2009 compared to 2008
on a total dollar basis and increased 4% on a per boe basis.




General and Administrative
      Expense(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeGross
      G&A expense
            
            
            5,137
            
            
            
            4,807
            
            
            
            7
            %
            
            
            20,103
            
            
            
            20,356
            
            
            
            (1
            %)Capitalized
            
            
            (299
            )
            
            
            (404
            )
            
            
            26
            %
            
            
            (1,153
            )
            
            
            (1,593
            )
            
            
            (28
            %)Recoveries
            
            
            (551
            )
            
            
            (1,383
            )
            
            
            (60
            %)
            
            
            (3,243
            )
            
            
            (2,905
            )
            
            
            12
            %G&A
      expense
            
            
            4,287
            
            
            
            3,020
            
            
            
            42
            %
            
            
            15,707
            
            
            
            15,858
            
            
            
            (1
            %)G&A
      expense per boe ($)
            
            
            4.86
            
            
            
            3.27
            
            
            
            49
            %
            
            
            4.36
            
            
            
            4.21
            
            
            
            4
            %







For 2009,
G&A costs were consistent with 2008 despite Enterra’s implementation of cost
reduction plans due to non-recurring costs which were incurred during Q3
2009.  The increase in G&A on a per boe basis from 2008 was due to
the 4% decrease in production from the prior year.




For the
three months ended December 31, 2009, G&A costs were $4.86 per boe compared
to $3.27 per boe in Q4 2008, a 49% increase primarily due to Q4 2008 having
greater overhead recoveries.  Q4 2009 decreased by 2% from Q3 2009
costs of $4.97 per boe.






PROVISION/RECOVERY
FOR RECEIVABLES




During
2009, Enterra recovered $2.1 million of an $8.5 million receivable that was
fully provided for in 2008.  On July 22, 2008, SemGroup, a midstream
and marketing company through which Enterra marketed a portion of its
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.  In 2008,
Enterra recorded a provision for receivables for the full amount owed by
SemGroup which was a one time charge of $8.5 million.  In 2009,
Enterra recovered $2.1 million of the previously written off amount from
SemGroup and management does not anticipate to recover any further
amounts.






INTEREST
EXPENSE




Interest
expense for 2009 was $11.5 million which was comprised of interest on long-term
debt of $2.8 million and interest on convertible debentures of $11.6 million
less interest income of $3.0 million.





Interest Expense(in thousands
      of Canadian except for percentages and per boe
    amounts)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeCash
      interest expense on long-term debt
            
            
            713
            
            
            
            1,288
            
            
            
            (45
            %)
            
            
            2,814
            
            
            
            7,814
            
            
            
            (64
            %)Cash
      interest expense on convertible debentures
            
            
            2,403
            
            
            
            2,418
            
            
            
            (1
            %)
            
            
            9,719
            
            
            
            9,726
            
            
            
            0
            %Cash
      interest income
            
            
            (542
            )
            
            
            (633
            )
            
            
            (14
            %)
            
            
            (2,960
            )
            
            
            (2,350
            )
            
            
            26
            %Subtotal
      cash interest expense
            
            
            2,574
            
            
            
            3,073
            
            
            
            (16
            %)
            
            
            9,573
            
            
            
            15,190
            
            
            
            (37
            %)Non-cash
      interest expense on long-term debt
            
            
            -
            
            
            
            2
            
            
            
            (100
            %)
            
            
            -
            
            
            
            548
            
            
            
            (100
            %)Non-cash
      interest expense on convertible debentures
            
            
            525
            
            
            
            451
            
            
            
            16
            %
            
            
            1,888
            
            
            
            1,728
            
            
            
            9
            %Total
      interest expense
            
            
            3,099
            
            
            
            3,526
            
            
            
            (12
            %)
            
            
            11,461
            
            
            
            17,466
            
            
            
            (34
            %)Cash
      interest expense per boe on long-term debt ($)
            
            
            0.81
            
            
            
            1.40
            
            
            
            (42
            %)
            
            
            0.78
            
            
            
            2.08
            
            
            
            (63
            %)Cash
      interest expense per boe on convertible debentures ($)
            
            
            2.73
            
            
            
            2.62
            
            
            
            4
            %
            
            
            2.70
            
            
            
            2.58
            
            
            
            5
            %Cash
      interest income per boe ($)
            
            
            (0.62
            )
            
            
            (0.69
            )
            
            
            (10
            %)
            
            
            (0.82
            )
            
            
            (0.62
            )
            
            
            32
            %Total
      cash interest expense per boe ($)
            
            
            2.92
            
            
            
            3.33
            
            
            
            (12
            %)
            
            
            2.66
            
            
            
            4.04
            
            
            
            (34
            %)





For 2009,
interest expense on long-term debt decreased 64% to $2.8 million from $7.8
million in 2008 due to lower debt levels and declining Bank of Canada interest
rates.





For the
three months ended December 31, 2009, interest expense on long-term debt
decreased 45% to $0.7 million from $1.3 million in Q4 2008 due to lower debt
levels and declining Bank of Canada interest rates.  The interest on
long-term debt decreased 36% compared to $1.1 million in Q3 2009 due to
financing charges in Q3 2009 for the renegotiated credit facility.





Enterra’s
long-term debt balance at December 31, 2009 was $70.0 million compared to $95.5
million at the end of 2008.  The average interest rate on long-term
debt for 2009 was 3.12% and the rate as of March 25, 2010 is approximately
3.48%.





The cash
interest expense on convertible debentures for the year and three months ended
December 31, 2009 was comparable to the same periods in 2008.





Interest
income for 2009 increased 26% to $3.0 million from $2.4 million in
2008.  Interest income for Q4 2009 decreased 14% to $0.5 million from
$0.6 million in Q4 2008 and decreased 25% compared $0.7 million in Q3
2009.  The changes in interest income are due to the changing balances
of the long-term receivables during the periods.































UNIT-BASED
COMPENSATION EXPENSE




Unit-Based Compensation Expense(in thousands
      Canadian dollars except for percentages and per boe
      amounts)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeGross
      unit-based compensation expense
            
            
            690
            
            
            
            1,057
            
            
            
            (35
            %)
            
            
            3,843
            
            
            
            4,819
            
            
            
            (20
            %)Capitalized
            
            
            (1
            )
            
            
            (112
            )
            
            
            (99
            %)
            
            
            (263
            )
            
            
            (404
            )
            
            
            (35
            %)Unit-based
      compensation expense
            
            
            689
            
            
            
            947
            
            
            
            (27
            %)
            
            
            3,580
            
            
            
            4,415
            
            
            
            (19
            %)Unit-based
      compensation expense per boe ($)
            
            
            0.78
            
            
            
            1.03
            
            
            
            (24
            %)
            
            
            0.99
            
            
            
            1.17
            
            
            
            (15
            %)





For 2009,
non-cash unit-based compensation expense was $3.6 million compared to $4.4
million in 2008.  The 2009 non-cash unit-based compensation expense
has decreased compared to 2008 due to restricted units that were issued at a
higher grant price in previous years that are no longer being expensed as they
have vested.





For the
three months ended December 31, 2009, non-cash unit-based compensation expense
was $0.7 million compared to $0.9 million in Q4 2008 and $0.7 million in Q3
2009.




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




Depletion, Depreciation and
      Accretion(in thousands
      of Canadian dollars except for percentages and per boe
      amounts)Three
      months ended
              December
      31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeDD&A
            
            
            19,597
            
            
            
            25,821
            
            
            
            (24
            %)
            
            
            86,877
            
            
            
            99,377
            
            
            
            (13
            %)DD&A
      per boe ($)
            
            
            22.23
            
            
            
            27.99
            
            
            
            (21
            %)
            
            
            24.10
            
            
            
            26.40
            
            
            
            (9
            %)





For 2009,
DD&A expenses decreased 13% to $86.9 million compared to $99.4 million in
2008.  The decrease in DD&A expenses is caused by the reduced
property, plant and equipment amounts primarily as a result of asset
dispositions in the first half of 2008 and increased proved reserves from the
recognition of NGL volumes due to the revised midstream contracts.





For the
three months ended December 31, 2009, DD&A expenses decreased by 24% to
$19.6 million compared to $25.8 million in Q4 2008 and decreased by 3% from
$20.2 million in Q3 2009.  The decrease in DD&A expenses in Q4
2009 compared to Q4 2008 is caused by the increase in proved reserves from the
recognition of NGL volumes due to the revised midstream contracts.





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, 2009 to assess the recoverability of costs recorded in respect of
the petroleum and natural gas properties.  The ceiling test
calculations did not result in a write down of the Canadian cost center or the
U.S. cost center.




FOREIGN
EXCHANGE




For 2009,
the combined realized and unrealized foreign exchange was a loss of $1.4 million
compared to a loss of $1.3 million in 2008.  This is a result of the
strengthening Canadian dollar in 2009 compared to 2008.


The
foreign exchange sensitivity in note 12 of the financial statements indicates
that for every $0.02 weakening of the Canadian dollar relative to the U.S.
dollar, the benefit to Enterra is $0.1 million in pre-tax income; therefore, the
weakening of the Canadian dollar relative to the U.S. dollar has had a positive
impact on Enterra.




TAXES




The
future income tax reduction for the year ended December 31, 2009 was $17.6
million compared to a future tax expense of $4.5 million in the prior year
mainly due to the change in the net income (loss).  The federal and
provincial statutory rate was 29.2% at December 31, 2009 compared to an
effective tax rate of 29.9% and a tax rate applied to temporary differences of
29.4%.





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





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





Post
conversion, the SIFT rules will not apply to Equal.  To the extent
Equal has taxable income, such income will be taxable at the applicable federal
and provincial corporate tax rates at that time.




NET
INCOME/LOSS




For 2009,
the loss was $41.3 million (loss of $0.65 per trust unit) compared to net income
of $7.1 million (net income of $0.11 per trust unit) for 2008.  The
loss during the year is mainly due to decreases in the prices for oil and
natural gas which was offset by lower royalties, production expenses,
transportation and cash interest expense.





For Q4
2009, the loss was $8.9 million (loss of $0.14 per trust unit) compared to net
income of $5.9 million (net income of $0.10 per unit) in Q4 2008.  The
loss during Q4 2009 is mainly due to decreases in the prices for oil and natural
gas which was offset by lower royalties, production expenses, transportation and
cash interest expense.




NON-GAAP
FINANCIAL MEASURES




Management
uses certain key performance indicators (“KPIs”) and industry bench marks such
as cash flow netback, funds from operations, working capital and net debt to
analyze financial performance.  Management feels that these KPIs and
benchmarks are key measures of profitability and overall sustainability for
Enterra.  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)Three
      months ended
              December
      31
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            2009
            
            
            2008Net
      income (loss)
            
            
            (8,939
            )
            
            
            5,907
            
            
            
            (41,282
            )
            
            
            7,061Future
      income taxes (reduction)
            
            
            9
            
            
            
            7,629
            
            
            
            (17,594
            )
            
            
            4,487Foreign
      exchange loss (gain)
            
            
            850
            
            
            
            (589
            )
            
            
            1,159
            
            
            
            1,279Depletion,
      depreciation and accretion
            
            
            19,597
            
            
            
            25,821
            
            
            
            86,877
            
            
            
            99,377Non-cash
      interest expense
            
            
            525
            
            
            
            456
            
            
            
            1,888
            
            
            
            2,276Unit
      based compensation expense
            
            
            689
            
            
            
            947
            
            
            
            3,580
            
            
            
            4,415Unrealized
      mark-to-market loss (gain) on commodity contracts
            
            
            1,182
            
            
            
            (15,974
            )
            
            
            14,127
            
            
            
            (20,072
            )Provision
      for non-recoverable receivables
            
            
            (2,110
            )
            
            
            (561
            )
            
            
            (2,110
            )
            
            
            8,522Funds
      from operations
            
            
            11,803
            
            
            
            23,636
            
            
            
            46,645
            
            
            
            107,345Total
      volume (mboe)
            
            
            882
            
            
            
            922
            
            
            
            3,605
            
            
            
            3,764Cash
      flow netback (non-GAAP) ($ per boe)
            
            
            13.38
            
            
            
            25.64
            
            
            
            12.94
            
            
            
            28.52





Funds
from Operations




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





Funds from Operations(in thousands
      of Canadian dollars)Three
      months ended
              December
      31
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            2009
            
            
            2008Cash
      provided by operating activities
            
            
            22,853
            
            
            
            21,743
            
            
            
            55,638
            
            
            
            91,560Changes
      in non-cash working capital items
            
            
            (10,516
            )
            
            
            1,746
            
            
            
            (9,416
            )
            
            
            5,492Asset
      retirement costs incurred
            
            
            1,576
            
            
            
            708
            
            
            
            2,533
            
            
            
            1,771Provision
      for non-recoverable receivables
            
            
            (2,110
            )
            
            
            (561
            )
            
            
            (2,110
            )
            
            
            8,522Funds
      from operations
            
            
            11,803
            
            
            
            23,636
            
            
            
            46,645
            
            
            
            107,345





In 2009,
funds from operations decreased by 57% from 2008 mainly as a result of lower
commodity prices for oil and natural gas.  Q4 2009 fund from
operations decreased by 50% due to the changes in non-cash working capital
items.




DISTRIBUTIONS




On
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 existing credit facility at the time,
Enterra was restricted from paying distributions while it had its second-lien
facility in place which was terminated at Enterra’s option in June
2009.  No distributions were paid in 2008 and 2009.





Enterra
continues to assess how cash flows generated from operations are
used.  In light of the current economic uncertainty, Enterra has
deferred portions of its capital spending and has increased its cash position
and reduced debt.  Enterra has maintained a conservative approach in
2009 and during 2010 will assess how to best allocate cash between capital
spending and debt repayment.  On January 18, 2010, Enterra announced
that it would convert to a growth oriented exploration and production company
under the name Equal Energy Ltd.





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.




CAPITAL
EXPENDITURES




The
following table represents the capital expenditures that were paid for with cash
and trust units in lieu of cash.





Capital Expenditures(in thousands
      of Canadian dollars except for percentages)Three
      months ended December 31
            
            
            
            
            
            Year
      ended
              December
      312009
            
            
            2008
            
            
            Change
            
            
            2009
            
            
            2008
            
            
            ChangeCapital
      expenditures
            
            
            4,815
            
            
            
            10,944
            
            
            
            (56
            %)
            
            
            22,206
            
            
            
            32,891
            
            
            
            (32
            %)Acquisition
      funded by trust unit issuance
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2,720
            
            
            
            -
            
            
            
            100
            %Capital
      expenditures to be recovered (1)
            
            
            103
            
            
            
            6,682
            
            
            
            (98
            %)
            
            
            1,744
            
            
            
            19,976
            
            
            
            (91
            %)Amounts
      recovered under agreement
            
            
            (2,592
            )
            
            
            (1,847
            )
            
            
            40
            %
            
            
            (11,004
            )
            
            
            (5,049
            )
            
            
            118
            %Total
            
            
            2,326
            
            
            
            15,779
            
            
            
            (85
            %)
            
            
            15,666
            
            
            
            47,818
            
            
            
            (67
            %)


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





During
2009, Enterra’s net capital expenditures were $15.7 million.





Enterra
spent $22.2 million in gross capital expenditures for both Canada and the U.S
and issued $2.7 million in trust units in lieu of cash.  Expenditures
in Canada totaled $9.1 million.  The major components of these
expenditures include:


·
            $3.6
      million on land and seismic
acquisitions;


·
            $2.0
      million related to wells, drilling and
  workovers;


·
            $1.9
      million on facilities and other equipment maintenance
  and;


·
            $1.6
      million related to the capitalization of certain G&A costs identified
      as attributable to exploration and development
  activities.





The
capital expenditures in the U.S. for which Enterra is solely responsible were
$13.1 million and $2.7 million in trust units in lieu of cash of which the major
expenditures include:


·
            $5.2
      million on acquisitions of land for future development in
      Oklahoma;


·
            $6.3
      million acquiring additional working interest in wells from non-operated
      working interest partners plus $2.7 million in trust units in lieu of cash
      ;


·
            $1.1
      million on capital enhancements
and;


·
            $0.5
      million on inventory and other
assets.





During
2009, Enterra spent a total of $1.7 million related to a farmout and capital
recovery agreement whereby Enterra recovers infrastructure costs incurred from a
joint venture partner.  Infrastructure costs incurred in the U.S.
under the capital recovery agreement 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.  Interest is charged on the outstanding balance at 12% per
annum and during 2009 $2.9 million in interest was received under this
agreement.





During
the year ended December 31, 2009, Enterra received a total of $11.0 million of
principal repayments under the capital recovery agreement.





On July
28, 2009, Enterra acquired additional working interests in certain properties in
the Hunton area from non-operated working interest partners.  The
combined consideration for the transaction was cash and cash equivalents of
US$6.0 million and 2.0 million trust units for approximately 270 boe per day of
production at the time of acquisition.





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.




BUSINESS
RISKS




The
disclosures under this heading should be read in conjunction with Note 12 to the
consolidated financial statements.





In the
current volatile economic and financial market conditions, Enterra continually
assesses its risks and manages those risks to the best of its
abilities.  Enterra is exposed to normal market risks inherent in the
oil and natural gas business, including commodity prices, credit risk, financing
risk, reserve estimates, foreign currency rates, acquisitions 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 Enterra’s annual filings with securities
regulatory authorities.





Commodity
Prices





Commodity
price fluctuations are among Enterra’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
and LNG imports.  In accordance with policies approved by the Board of
Directors, Enterra, from time to time, manage these risks through the use of
fixed physical contracts, swaps, collars or other commodity
contracts.  For a summary of outstanding oil and natural gas
contracts, please refer to “Commodity Contracts” in this MD&A and in Note 12
to the consolidated financial statements.





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 have not been 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 January
2010, Enterra’s Bank Syndicate completed a borrowing base review and reaffirmed
the borrowing base of $110.0 million.  The borrowing base was set
based on Enterra’s oil, NGL and natural gas reserves using the Bank Syndicate’s
future commodity price deck at the time of review.  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 have not been unduly impacted by the recent turmoil in
credit markets.


ANNUAL 2009
REPORT
 
 ENTERRA
      ENERGY TRUSTMANAGEMENT
      DISCUSSION AND ANALYSIS


Reserve
Estimates





The
reserves information contained in Enterra’s independent reserve evaluations are
only estimates.  The actual production and ultimate reserves from the
properties may be greater or less than the estimates prepared by the independent
reserve evaluators.  The reserve reports were prepared using certain
commodity price assumptions.  If lower prices for oil, NGLs and
natural gas are realized by Enterra and substituted for the price assumptions
utilized in those reserve reports, the present value of estimated future net
cash flows for Enterra’s reserves as well as the amount of Enterra’s reserves
would be reduced and the reduction could be significant.





Foreign
Currency Rates





Enterra’s
U.S. operations accounted for 55% of Enterra’s total 2009 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.





Acquisitions





The price
paid for acquisitions is based on engineering and economic estimates of the
potential reserves made by independent engineers modified to reflect the
technical views of management.  These assessments include a
number


of
material assumptions regarding such factors as recoverability and marketability
of oil, NGLs and natural gas, future prices of oil, NGLs and natural gas and
operating costs, future capital expenditures and royalties and other government
levies that will be imposed over the producing life of the
reserves.  Many of these factors are subject to change and are beyond
the control of the operators of the working interests, management and
Enterra.  In particular, changes in the prices of and markets for oil,
NGLs and natural gas from those anticipated at the time of making such
assessments will affect the value of the units.  In addition, all such
estimates involve a measure of geological and engineering uncertainty that could
result in lower production and reserves than attributed to the working
interests.  Actual reserves could vary materially from these
estimates.  Consequently, the reserves acquired may be less than
expected, which could adversely impact cash flows and distributions to
unitholders.





Environmental





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 below in the Liquidity and Capital Resources
section and in Note 12 to the consolidated financial
statements.


ANNUAL 2009
REPORT
 
 ENTERRA
      ENERGY TRUSTMANAGEMENT
      DISCUSSION AND ANALYSIS


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





Financial
      Instrument – Liability(in
      thousands of Canadian dollars)
            
            2010
            
            
            2011
            
            
            2012
            
            
            
            2013
      – 2014
            
            
            TotalLong-term
      debt (1)
            
            
            -
            
            
            
            70,000
            
            
            
            -
            
            
            
            -
            
            
            
            70,000Interest
      on long-term debt (2)
            
            
            2,275
            
            
            
            1,138
            
            
            
            -
            
            
            
            -
            
            
            
            3,413Convertible
      debentures
            
            
            -
            
            
            
            80,210
            
            
            
            39,648
            
            
            
            -
            
            
            
            119,858Interest
      on convertible debentures
            
            
            9,688
            
            
            
            9,688
            
            
            
            1,635
            
            
            
            -
            
            
            
            21,011Accounts
      payable & accrued liabilities
            
            
            27,997
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            27,997Commodity
      contracts
            
            
            755
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            755Office
      leases (3)
            
            
            1,608
            
            
            
            2,139
            
            
            
            453
            
            
            
            538
            
            
            
            4,738Vehicle
      and other operating leases
            
            
            306
            
            
            
            146
            
            
            
            18
            
            
            
            -
            
            
            
            470Total
      obligations
            
            
            42,629
            
            
            
            163,321
            
            
            
            41,754
            
            
            
            538
            
            
            
            248,242


(1)  Assumes
the credit facilities are not renewed on June 25, 2010.


(2)  Assumes
an interest rate of 3.25% (the rate on December 31, 2009).


(3)  Future
office lease commitments may be reduced by sublease recoveries totaling $1.1
million.




LIQUIDITY
& CAPITAL RESOURCES




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.  Enterra’s future oil and natural gas production
is highly dependent on its success in exploiting its asset base and acquiring or
developing additional reserves.





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 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.  Enterra believes its sources of
cash, including bank debt, will be sufficient to fund its operations and
anticipated capital expenditure program in 2010.  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.  Enterra will monitor commodity prices and adjust the 2010
capital expenditure program accordingly to stay within its
means.  Should external sources of capital become limited or
unavailable, Enterra’s ability to make the necessary development expenditures
and acquisitions to maintain or expand its asset base may be
impaired.





Enterra’s
improved cash position and available credit facility will enable Enterra to
address the current economic uncertainties and management is confident in its
ability to manage through this cycle. Management believes that funds from
operations are sufficient to meet its 2010 capital expenditure program and make
required interest payments.





Enterra’s
capital structure at December 31, 2009 is as follows:





December
      31, 2009
            
            
            December
      31, 2008Capitalization(in thousand
      of Canadian dollars except percentages)
            
            Amount
            
            
            %
            
            
            Amount
            
            
            %Long-term
      debt
            
            
            70,000
            
            
            
            24
            %
            
            
            95,466
            
            
            
            47
            %Working
      capital (1)excluding long-term debt
            
            
            (28,554
            )
            
            
            (10
            %)
            
            
            (23,767
            )
            
            
            (12
            %)Long-term
      receivable
            
            
            (5,491
            )
            
            
            (2
            %)
            
            
            (19,310
            )
            
            
            (9
            %)Net
      debt
            
            
            35,955
            
            
            
            12
            %
            
            
            52,389
            
            
            
            26
            %Convertible
      debentures
            
            
            114,863
            
            
            
            39
            %
            
            
            113,420
            
            
            
            56
            %Trust
      units issued, at market (2)
            
            
            141,499
            
            
            
            49
            %
            
            
            38,341
            
            
            
            18
            %Total
      capitalization
            
            
            292,317
            
            
            
            100
            %
            
            
            204,150
            
            
            
            100
            %


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


(2)
            The
      weighted average price of Enterra’s trust units on December 31, 2009 was
      $2.18 per unit (December 31, 2008 – $0.62 per
  unit).


Long-term
Debt





At
December 31, 2009, Enterra’s long-term debt was $70.0 million a decrease of
$25.5 million from $95.5 million at December 31, 2008.  Enterra has
credit facilities with its banking syndicate that includes revolving and
operating credit facilities which have a borrowing capacity of $110.0 million
which was reaffirmed by the banking syndicate in January 2010.





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(in
      thousands of Canadian dollars except for ratios)
            
            December
      31, 2009
            
            
            December
      31, 2008Interest
      coverage (1):Cash
      flow over the prior four quarters
            
            
            61,288
            
            
            
            116,911Interest
      expenses over the prior four quarters
            
            
            12,533
            
            
            
            18,088Interest
      coverage ratio
            
            4.89
      : 1.00
            
            
            6.46
      : 1.00


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





Working
Capital





The
working capital deficiency has decreased from the beginning of the year due to
Enterra’s reduction in expenditures and focus on debt reduction during
2009.





Enterra’s
working capital excluding long-term debt increased by $4.8 million mainly due to
an increase in cash of $6.0 million, a decrease in accounts payable of $10.0
million, an increase in the current portion of the long term receivable of $0.5
million which were offset by a decrease in accounts receivable of $11.7
million.





As
      atWorking Capital(in thousands of Canadian
      dollars)
            
            December
      31, 2009
            
            
            December
      31, 2008Working
      capital (deficiency)(1)
            
            
            28,554
            
            
            
            (71,699
            )Working
      capital(1)
      excluding long-term debt
            
            
            28,554
            
            
            
            23,767


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





Long-term
Receivable





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 paid 100% of the drilling and completion costs to earn 70% of Enterra’s
interest in each well and Enterra was required to pay 100% of the infrastructure
costs to support these wells, such as pipelines and salt water disposal
wells.  These infrastructure costs were 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
finance lease, therefore, the capital costs incurred are not included in
property, plant and equipment but are recorded as current and long-term
receivables.  The interest income on the receivables is recorded as a
reduction in interest expense.  A director of Enterra who previously
owned less than 2% of the outstanding shares of JV Partner no longer has any
ownership interest in JV Partner.





In
December 2009 Enterra delivered a notice of termination for non-performance
under the terms of the farm-out agreement with JV Partner.  JV Partner
was required to maintain a certain pace of drilling to continue its right to
drill on lands owned by Enterra but ceased drilling in February 2009 and has not
indicated that it will be able to continue drilling with any
certainty.  Final notice of termination of the farm-out agreement was
delivered in January 2010.  Enterra owns undeveloped land of
approximately 41,600 acres which had been subject to the farm-out agreement
which it now plans to drill on its own or with another suitable
partner.  If amounts owing under the long-term receivable are not
recovered from JV Partner, then the balance owing will be reclassified to the
property, plant and equipment, net of impairment, if any, as the receivable
relates to infrastructure assets which are majority owned and operated by
Enterra.  A fee will be charged to JV Partner for use of the
infrastructure assets upon termination of the existing arrangement as a capital
recovery fee against production from the producing wells.  The
recovery of this fee has been secured by placing liens against the producing
wells.  It is anticipated that the recovery of the costs will come
from production revenues on these wells or other legal remedies.





As at
December 31, 2009, a total of $16.7 million, split between $11.2 million of
current receivables and $5.5 million of long-term receivables (December 31, 2008
– $10.8 million and $19.3 million, respectively), relate to infrastructure costs
incurred by Enterra that are due from JV Partner.





For the
year ended December 31, 2009, $2.7 million of interest income was earned on the
long-term receivables from JV Partner (2008 – $1.7 million) and $11.0 million of
principal payments have been received (2008 – $5.0 million).  For the
year ended December 31, 2009, $1.7 million in new capital expenditures were made
by Enterra that are expected to be recovered under the farm-out agreement (2008
– $20.0 million).





Convertible
Debentures





As at
December 31, 2009, Enterra had convertible debentures outstanding with a face
value of $119.9 million.  During Q2 2009, Enterra made the necessary
filings, and received the necessary approvals, to make a normal course issuer
bid for its 8.25% and 8.00% convertible debentures.  In accordance
with the normal course issuer bid, Enterra has repurchased it $0.2 million in
face value of its convertible debentures.  The normal course issuer
bid is effective until May 31, 2010.





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.  During 2009 and
      2008, there was no conversion of ENT.DB convertible
      debentures.


·
            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.  During 2009, $0.3
      million in face value of the ENT.DB.A convertible debentures were
      converted into Enterra trust units (2008 –
nil).





As at
December 31, 2009, Enterra had 64.9 million trust units
outstanding.  If all the outstanding convertible debentures were
converted into units at their respective conversion prices, a total of 79.4
million trust units would be outstanding.




SUBSEQUENT
EVENT




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





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








RESERVES
AND PRESENT VALUE SUMMARY





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





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





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





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





Reserve
volumes and values at December 31, 2009 are based on the interest in total
proved and probable reserves prior to royalties as defined in NI
51-101.  Under NI 51-101 reserves definitions, estimates are prepared
such that the full proved and probable reserves are estimated to be recoverable
(proved plus probable reserves are effectively a "most likely
case").  As such, the probable reserves reported are already
"risked."





The
reserves have been evaluated by independent engineers each
year.  McDaniel and Associates Consultants Ltd. ("McDaniel")
independently evaluated the Canadian reserves as at December 31, 2009 and 2008
and Haas Petroleum Engineering Services, Inc. (“Haas”) evaluated the Oklahoma
reserves as at December 31, 2009 and 2008.  The independent engineers
used the following future price forecasts in order to evaluate Enterra’s
reserves as of December 31, 2009.





Year
            WTI
      Oil
              ($U.S./bbl)
            Edmonton
      Light
              Crude
      Oil
              ($Cdn/bbl)
            AECO
      Gas
              ($Cdn/MMBtu)
            Henry
      Hub
              ($U.S./Mmbtu)
            Foreign
              Exchange
              Rate
      (US$/CAD)2010
            80.00
            83.20
            6.05
            6.05
            0.9502011
            83.60
            87.00
            6.75
            6.90
            0.9502012
            87.40
            91.00
            7.15
            7.30
            0.9502013
            91.30
            95.00
            7.45
            7.70
            0.9502014
            95.30
            99.20
            7.80
            8.15
            0.9502015
            99.40
            103.50
            8.15
            8.50
            0.950Escalate
              Thereafter
            Average
              2%
      per year
            Average
              2%
      per year
            Average
              2%
      per year
            Average
              2%
      per year
            0.950








Reserve
Continuity - Oil and Gas (mboe)


Proved
            
            
            Probable
            
            
            TotalDecember
      31, 2007
            
            
            21,489
            
            
            
            8,770
            
            
            
            30,259Discoveries
      and extensions
            
            
            955
            
            
            
            526
            
            
            
            1,481Purchases
            
            
            6
            
            
            
            2
            
            
            
            8Dispositions
            
            
            (2,659
            )
            
            
            (1,128
            )
            
            
            (3,787
            )Production
            
            
            (3,764
            )
            
            
            -
            
            
            
            (3,764
            )Revision
      of prior estimates
            
            
            3,457
            
            
            
            (955
            )
            
            
            2,502December
      31, 2008
            
            
            19,484
            
            
            
            7,215
            
            
            
            26,699Discoveries
      and extensions
            
            
            128
            
            
            
            31
            
            
            
            159Purchases
            
            
            860
            
            
            
            45
            
            
            
            905Dispositions
            
            
            -
            
            
            
            -
            
            
            
            -Production
            
            
            (3,605
            )
            
            
            -
            
            
            
            (3,605
            )Revision
      of prior estimates
            
            
            5,338
            
            
            
            1,569
            
            
            
            6,907December
      31, 2009
            
            
            22,205
            
            
            
            8,860
            
            
            
            31,065





Total
reserves increased by 16% from 26,699 mboe at the end of 2008 compared to 31,065
mboe by the end of the year.  The increase in the reserves is due to
new wells drilled, acquisitions and positive revisions to the reserve
estimates.  The main factors contributing to the positive revisions
were the recognition of the NGL volumes due to the new marketing contracts in
Oklahoma, increasing NGL yields from the Hunton assets, the reduced operational
costs and improved reservoir performance.





Proved
reserves increased by 14% from December 31, 2008 to December 31, 2009 which was
mainly the result of positive revisions of the reserve estimates of 5,338 mboes
which exceeded the amount produced during 2009 of 3,605 mboes.  The
revisions of the reserve estimates also increased the probable reserves by 23%
from December 31, 2008 to December 31, 2009.





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





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





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





Finding
Development & Acquisition Costs and Recycle Ratio


Years
      Ended December 31
            
            
            3-Year(in
      $/boe, except for capital expenditures, FDC and reserves which are in
      thousands)
            
            2009
            
            
            2008
            
            
            2007
            
            
            AverageCapital
      expenditures (excluding ARO)
            
            
            24,926
            
            
            
            32,891
            
            
            
            88,323
            
            
            
            48,713Future
      Development Costs
              Proved
            
            
            65,083
            
            
            
            2,967
            
            
            
            34,224
            
            
            
            34,091Proved
      Plus Probable
            
            
            101,078
            
            
            
            16,771
            
            
            
            49,268
            
            
            
            55,706Reserves(1)Proved
      reserves added in the year (mboe)
            
            
            6,326
            
            
            
            4,418
            
            
            
            5,276
            
            
            
            5,340Probable
      reserves added in the year (mboe)
            
            
            1,645
            
            
            
            (427
            )
            
            
            2,805
            
            
            
            1,341Proved
      plus probable reserves added in the year  (mboe)
            
            
            7,971
            
            
            
            3,991
            
            
            
            8,080
            
            
            
            6,681FD&A
      costs (excluding FDC)Proved
      reserves ($/boe)
            
            
            3.94
            
            
            
            7.44
            
            
            
            16.74
            
            
            
            9.12Proved
      plus probable reserves ($/boe)
            
            
            3.13
            
            
            
            8.24
            
            
            
            10.93
            
            
            
            7.29FD&A
      costs (including FDC)Proved
      reserves ($/boe)
            
            
            14.23
            
            
            
            8.12
            
            
            
            23.23
            
            
            
            15.51Proved
      plus probable reserves ($/boe)
            
            
            15.81
            
            
            
            12.44
            
            
            
            17.03
            
            
            
            15.63Recycle
      ratiosOperating
      netbacks ($/boe) (2)
            
            
            20.02
            
            
            
            36.87
            
            
            
            25.15
            
            
            
            27.35Operating
      recycle ratio (based on proved plus probable reserves excluding FDC’s)
      ($/boe)
            
            
            6.40
            
            
            
            4.47
            
            
            
            2.30
            
            
            
            3.75Corporate
      netbacks ($/boe)(3)
            
            
            12.94
            
            
            
            28.52
            
            
            
            16.02
            
            
            
            19.16Corporate
      recycle ratio (based on proved plus probable finding costs excluding
      FDC’s) ($/boe)
            
            
            4.14
            
            
            
            3.46
            
            
            
            1.47
            
            
            
            2.63


(1)
            Includes
      revisions and acquisitions.


(2)
            Operating
      netbacks are production revenue less royalties and operating
      expenses.


(3)
            Corporate
      netbacks are production revenue less royalties, operating expenses,
      G&A, interest expense and other cash
costs.





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





Enterra’s
proved plus probable FD&A excluding FDC costs decreased by 76% from $8.24
per boe to $3.13 per boe.  This was primarily a result of the
recognition of the NGL volumes due to the new marketing contracts in Oklahoma,
increasing NGL yields from Hunton gas with time, the reduced operational costs
and improved reservoir performance.





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


December 31, 2009(NPV in
millions)


Light/
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            Net
      Present ValueMedium
            
            
            Heavy
            
            
            
            
            
            Natural
            
            
            
            
            
            Before
      Income Tax ($)Oil
            
            
            Oil
            
            
            NGL
            
            
            Gas
            
            
            Total(mbbl)
            
            
            (mbbl)
            
            
            (mbbl)
            
            
            (mmcf)
            
            
            (mboe)
            
            
            
            0
            %
            
            
            5
            %
            
            
            10
            %Canadian
      AssetsProved
      Producing
            
            
            1,679
            
            
            
            571
            
            
            
            78
            
            
            
            14,200
            
            
            
            4,695
            
            
            
            127,679
            
            
            
            111,710
            
            
            
            99,954Proved
      Non-Producing
            
            
            -
            
            
            
            -
            
            
            
            39
            
            
            
            5,277
            
            
            
            919
            
            
            
            7,582
            
            
            
            6,531
            
            
            
            5,712Proved
      Undeveloped
            
            
            8
            
            
            
            120
            
            
            
            1
            
            
            
            74
            
            
            
            141
            
            
            
            2,557
            
            
            
            2,249
            
            
            
            1,988Total
      Proved
            
            
            1,687
            
            
            
            691
            
            
            
            118
            
            
            
            19,551
            
            
            
            5,755
            
            
            
            137,818
            
            
            
            120,490
            
            
            
            107,654Total
      Probable
            
            
            848
            
            
            
            358
            
            
            
            81
            
            
            
            16,457
            
            
            
            4,029
            
            
            
            99,188
            
            
            
            72,430
            
            
            
            55,426Total
      Proved & Probable
            
            
            2,535
            
            
            
            1,049
            
            
            
            199
            
            
            
            36,008
            
            
            
            9,784
            
            
            
            237,006
            
            
            
            192,920
            
            
            
            163,080United
      States AssetsProved
      Producing
            
            
            603
            
            
            
            -
            
            
            
            5,500
            
            
            
            33,657
            
            
            
            11,713
            
            
            
            340,023
            
            
            
            255,069
            
            
            
            202,970Proved
      Non-Producing
            
            
            48
            
            
            
            -
            
            
            
            194
            
            
            
            1,794
            
            
            
            541
            
            
            
            12,175
            
            
            
            9,226
            
            
            
            7,213Proved
      Undeveloped
            
            
            5
            
            
            
            -
            
            
            
            1,775
            
            
            
            14,503
            
            
            
            4,197
            
            
            
            50,934
            
            
            
            24,106
            
            
            
            7,539Total
      Proved
            
            
            656
            
            
            
            -
            
            
            
            7,469
            
            
            
            49,954
            
            
            
            16,451
            
            
            
            403,132
            
            
            
            288,401
            
            
            
            217,722Total
      Probable
            
            
            26
            
            
            
            -
            
            
            
            2,126
            
            
            
            16,072
            
            
            
            4,830
            
            
            
            139,398
            
            
            
            95,660
            
            
            
            69,221Total
      Proved & Probable
            
            
            682
            
            
            
            -
            
            
            
            9,595
            
            
            
            66,026
            
            
            
            21,281
            
            
            
            543,530
            
            
            
            384,061
            
            
            
            286,943Consolidated
      AssetsProved
      Producing
            
            
            2,282
            
            
            
            571
            
            
            
            5,578
            
            
            
            47,857
            
            
            
            16,408
            
            
            
            467,702
            
            
            
            366,779
            
            
            
            302,924Proved
      Non-Producing
            
            
            48
            
            
            
            -
            
            
            
            233
            
            
            
            7,071
            
            
            
            1,460
            
            
            
            19,757
            
            
            
            15,757
            
            
            
            12,924Proved
      Undeveloped
            
            
            13
            
            
            
            120
            
            
            
            1,776
            
            
            
            14,577
            
            
            
            4,338
            
            
            
            53,491
            
            
            
            26,355
            
            
            
            9,527Total
      Proved
            
            
            2,343
            
            
            
            691
            
            
            
            7,587
            
            
            
            69,505
            
            
            
            22,206
            
            
            
            540,950
            
            
            
            408,891
            
            
            
            325,377Total
      Probable
            
            
            874
            
            
            
            358
            
            
            
            2,207
            
            
            
            32,529
            
            
            
            8,859
            
            
            
            238,586
            
            
            
            168,090
            
            
            
            124,647Total
      Proved & Probable
            
            
            3,217
            
            
            
            1,049
            
            
            
            9,794
            
            
            
            102,034
            
            
            
            31,065
            
            
            
            779,536
            
            
            
            576,981
            
            
            
            450,024


(1)
            The
      U.S. reserve report was converted to Canadian dollars using the McDaniel
      and Associates January 1, 2010 foreign exchange
  forecast.














































TRUST
UNIT INFORMATION




Enterra
is capitalized through a combination of trust units and convertible
debt.  Enterra also has a unit option plan, restricted unit plan,
performance unit plan and warrants to purchase trust units
outstanding.  The following table outlines outstanding equity
instruments:





Outstanding
      Unit Data as at
            
            March
      25, 2010
            
            
            December
      31, 2009
            
            
            December
      31, 2008Trust
      units
            
            
            65,164,760
            
            
            
            65,102,689
            
            
            
            62,158,987Trust
      unit options
            
            
            2,702,000
            
            
            
            706,000
            
            
            
            1,042,000Restricted
      units
            
            
            1,966,515
            
            
            
            1,604,325
            
            
            
            2,279,786Performance
      units
            
            
            -
            
            
            
            -
            
            
            
            174,3988.0%
      Convertible debentures ($1,000 per debenture)
            
            
            80,210
            
            
            
            80,210
            
            
            
            80,3318.25%
      Convertible debentures ($1,000 per debenture)
            
            
            39,648
            
            
            
            39,648
            
            
            
            40,000




ENVIRONMENTAL
AND CLIMATE CHANGE RISK




The oil
and gas industry has a number of environmental risks and hazards and is subject
to regulation by all levels of government.  Environmental legislation
includes, but is not limited to, operational controls, final site restoration
requirements and increasing restrictions on emissions of various substances
produced in association with oil and natural gas
operations.  Compliance with such legislation could require additional
expenditures and a failure to comply may result in fines and penalties which
could, in the aggregate, become material.




DISCLOSURE CONTROLS AND
PROCEDURES




As of
December 31, 2009, an internal evaluation was carried out of the effectiveness
of Enterra’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 Enterra 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 Enterra in the reports that it files or submits
under the Exchange Act or under Canadian Securities Legislation is accumulated
and communicated to Enterra’s management, including the senior executive and
financial officers, as appropriate to allow timely decisions regarding the
required disclosure.




INTERNAL
CONTROL OVER FINANCIAL REPORTING




Internal
control over financial reporting is a process designed to provide reasonable
assurance that all assets are safeguarded, transactions are appropriately
authorized and to facilitate the preparation of relevant, reliable and timely
information.  Because of its inherent limitations, internal control
over financial reporting may not prevent or detect
misstatements.  Management has assessed the effectiveness of Enterra’s
internal control over financial reporting 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.  The assessment was based on the framework in Internal
Control – Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.  Management concluded that
Enterra’s internal control over financial reporting was effective as of December
31, 2009.  The effectiveness of Enterra's internal control over
financial reporting as of December 31, 2009 has been audited by KPMG LLP, an
independent registered public accounting firm.  No changes were made
to Enterra's internal control over financial reporting during the year ending
December 31, 2009, that have materially affected, or are reasonably likely to
materially affect, the internal controls over financial reporting.




CHANGES
IN ACCOUNTING POLICIES




Effective
December 31, 2009, Enterra adopted CICA issued amendments to Handbook Section
3862 “Financial Instruments – Disclosures”.  The amendments include
enhanced disclosures relating to the fair value of financial instruments and the
liquidity risk associated with financial instruments.  Section 3862
now requires that all financial instruments measured at fair value be
categorized into one of three hierarchy levels.  Refer to Note 12 Risk
Management for enhanced fair value disclosures and liquidity risk
disclosures.  The amendments are consistent with recent amendments to
financial instrument disclosure standards in IFRS.





The CICA
issued Handbook Section 1582 "Business Combinations" that replaces the previous
business combinations standard.  Under this guidance, the purchase
price used in a business combination is based on the fair value of shares
exchanged at the market price at acquisition date.  Under the current
standard, the purchase price used is based on the market price of shares for a
reasonable period before and after the date the acquisition is agreed upon and
announced.  In addition, the guidance generally requires all
acquisition costs to be expensed.  Current standards allow for the
capitalization of these costs as part of the purchase price.  This new
Section also addresses contingent liabilities, which will be required to be
recognized at fair value on acquisition, and subsequently remeasured at each
reporting period until settled.  Currently, standards require only
contingent liabilities that are payable to be recognized.  The new
guidance requires negative goodwill to be recognized in earnings rather than the
current standard of deducting from non-current assets in the purchase price
allocation.  This standard applies prospectively to business
combinations on or after January 1, 2011 with earlier application
permitted.  Enterra is currently assessing the impact of the
standard.





The CICA
issued Handbook Sections 1601 "Consolidated Financial Statements", and 1602
"Non-controlling Interests", which replaces existing guidance under Section 1600
"Consolidated Financial Statements".  Section 1601 establishes
standards for the preparation of Consolidated Financial
Statements.  Section 1602 provides guidance on accounting for a
non-controlling interest in a subsidiary in Consolidated Financial Statements
subsequent to a business combination.  These standards will be
effective for Enterra for business combinations occurring on or after January 1,
2011, with early application permitted.  Enterra is currently
assessing the impact of the standards.





International
Financial Reporting Standards




In 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.





Enterra
has commenced the process to transition from current Canadian GAAP to
IFRS.  It has established a project plan and a project
team.  Enterra has appointed internal staff to lead the conversion
project along with sponsorship from the senior leadership team to manage this
transition and to ensure successful implementation within the required
timeframe.





The
project plan consists of three phases: initiation, detailed assessment and
design and implementation.  Enterra has completed the first phase,
which involved the development of a detailed timeline for assessing resources
and training and the completion of a high level review of the major differences
between current Canadian GAAP and IFRS.  Discussions with Enterra’s
external auditors have commenced and will continue throughout the subsequent
phases.  Regular reporting is provided to senior management and to the
Audit Committee of the Board of Directors.





Enterra
is currently engaged in the detailed assessment and design phase of the
project.  The detailed assessment and design phase involves a
comprehensive analysis of the impact of the IFRS differences identified in the
initial scoping assessment.  In addition, an initial evaluation of
IFRS 1 transition exemptions and an analysis of financial systems have been
completed.  Management has not yet finalized its accounting policies
and as such, is unable to quantify the impact of adopting IFRS.  In
addition, changes to IFRS and International Accounting Standards prior to
Enterra’s adoption of IFRS may affect management’s decision on the accounting
policies that Enterra will adopt.





During
the implementation phase, Enterra will execute the required changes to business
processes, financial systems, accounting policies, disclosure controls and
internal controls over financial reporting.  Enterra will provide
disclosures of key elements of its plan and progress on the project as the
information becomes available during the transition period.





The
transition from Canadian GAAP to IFRS is a significant undertaking that may
materially affect our reported financial position and results of operations. At
this time, Enterra has identified key differences that will impact the financial
statements as follows:





·
            Re-classification
      of exploration and evaluation (“E&E”) expenditures from property,
      plant and equipment (”PP&E”) – Upon transition to IFRS, Enterra will
      re-classify all E&E expenditures that are currently included in the
      PP&E balance on the Consolidated Balance Sheet.  This will
      consist of the book value for Enterra’s undeveloped land that relates to
      exploration properties.  E&E assets will not be depleted and
      must be assessed for impairment when indicators suggest the possibility of
      impairment.


·
            Calculation
      of depletion expense for PP&E assets – Upon transition to IFRS,
      Enterra has the option to calculate depletion using a reserve base of
      proved reserves or both proved and probable reserves, as compared to the
      Canadian GAAP method of calculating depletion using only proved
      reserves.  Enterra has not concluded at this time which method
      for calculating depletion will be
used.


·
            Impairment
      of PP&E assets – Under IFRS, impairment of PP&E must be calculated
      at a more granular level than what is currently required under Canadian
      GAAP.  Impairment calculations will be performed at
      the   cash generating unit level which is expected to be at
      a more detailed level than the current Canadian and U.S. full cost
      pools.


·
            Share-based
      payments are expensed based on a graded vesting schedule (currently
      Enterra applies straight line
amortization).


·
            Discount
      rates used in calculating the asset retirement obligation are currently
      under review by the IASB as there is diversity in practice when selecting
      a rate.  Future changes to the standards and further
      interpretations of the guidance could lead to a material change in this
      provision upon adoption of IFRS.





Enterra
will disclose additional information on the impact of the changes throughout
2010.  Any amendments to existing IFRS standards or implementation of
new IFRS standards could lead to additional changes.




CRITICAL
ACCOUNTING ESTIMATES




Enterra
has continuously evolved and documented its management and internal reporting
systems to provide assurance that accurate, timely internal and external
information is gathered and disseminated.





Enterra’s
financial and operating results incorporate certain estimates
including:


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


·
            estimated
      capital expenditures on projects that are in
  progress;


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


·
            estimated
      fair values of derivative contracts that are subject to fluctuation
      depending upon the underlying commodity
prices;


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


·
            estimated
      future recoverable value of property, plant and
  equipment.





Enterra
has hired individuals and consultants who have the skills required to make such
estimates and ensures that individuals or departments with the most knowledge of
the activity are responsible for the estimates.  Further, past
estimates are reviewed and compared to actual results, and actual results are
compared to budgets in order to make more informed decisions on future
estimates.





The
Enterra leadership team’s mandate includes ongoing development of procedures,
standards and systems to allow Enterra staff to make the best decisions possible
and ensuring those decisions are in compliance with Enterra’s environmental,
health and safety policies.




ADDITIONAL
INFORMATION




Additional
information relating to Enterra Energy Trust can be found on SEDAR at
www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, as well as on the website at
www.enterraenergy.com.


ANNUAL 2009
REPORT
 
 ENTERRA
      ENERGY TRUSTMANAGEMENT
      DISCUSSION AND ANALYSIS





GLOSSARY


AECO
            a
      storage and pricing hub for Canadian natural gas market
            
            mcf
      per day
            thousands
      of cubic feet of natural gas per daybbl
      or bbls
            barrels
      of oil
            
            mmbtu
            millions
      of British Thermal Unitsbbls
      per day
            barrels
      of oil per day
            
            mmbtu
      per day
            millions
      of British Thermal Units per dayboe
            barrels
      of oil equivalent (6 mcf equivalent to 1 bbl)
            
            mmcf
            millions
      of cubic feet of natural gasboe
      per day
            barrels
      of oil equivalent per day
            
            Mwh
            megawatt-hourCdn$
            Canadian
      dollars
            
            NGL
            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 30GORR
            Gross
      overriding royalty
            
            Q3
            third
      quarter of the year - July 1 to September 30LNG
            Liquefied
      Natural Gas
            
            Q4
            fourth
      quarter of the year - October 1 to December 31mbbl
            thousand
      barrels of oil
            
            US$
            United
      States dollarsmboe
            thousands
      of barrels of oil equivalent
            
            WTI
            West
      Texas Intermediate (oil reference price)mcf
            thousand
      cubic feet of natural gas
















ANNUAL 2009
REPORT