AUDITORS'
REPORT ON RECONCILIATION TO UNITED STATES GAAP





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





On March
25, 2010, we reported on the consolidated balance sheets of Enterra Energy Trust
(the “Trust”) as at December 31, 2009 and 2008 and the consolidated statements
of income (loss) and comprehensive income (loss), deficit, and cash flows for
the years then ended, which are included in the annual report on Form 40-F. In
connection with our audits of the aforementioned consolidated financial
statements, we also have audited the related supplemental note entitled
"Differences between Canadian and United States Generally Accepted Accounting
Principles". This supplemental note is the responsibility of the Trust's
management. Our responsibility is to express an opinion on this supplemental
note based on our audits.





In our
opinion, such supplemental note, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.











Signed
“KPMG LLP”





Chartered
Accountants


Calgary,
Canada


March 25,
2010
















The
consolidated financial statements of Enterra Energy Trust (“Enterra”) as at and
for the years ended December 31, 2009 and 2008 have been prepared in accordance
with Canadian GAAP (in thousands of Canadian dollars except unit and per unit
information) which differs in some respects from U.S.
GAAP.  Differences in accounting principles as they pertain to the
consolidated financial statements are immaterial except as described
below.




The
application of U.S. GAAP would have the following effect on net income (loss) as
reported for the years ended December 31, 2009 and 2008:





2009
            
            
            2008Net
      income (loss) under Canadian GAAP
            
            $
            (41,282
            )
            
            $
            7,061Adjustments
      for U.S. GAAPDepletion
      expense (a)
            
            
            72,679
            
            
            
            (60,560
            )Related
      income taxes
            
            
            (24,571
            )
            
            
            14,885Reverse
      unit-based compensation expense under Canadian GAAP (c)
            
            
            3,580
            
            
            
            4,415Unit-based
      compensation expense under U.S. GAAP (c)
            
            
            (2,164
            )
            
            
            (160
            )Accretion
      of convertible debentures under Canadian GAAP (e)
            
            
            1,888
            
            
            
            1,728Amortization
      of other assets (e)
            
            
            (1,242
            )
            
            
            (1,242
            )Foreign
      exchange (d)
            
            
            (170
            )
            
            
            2,071Future
      tax adjustments
            
            
            5,415
            
            
            
            -Net
      income (loss) under U.S. GAAP
            
            $
            14,133
            
            
            $
            (31,802
            )Other
      comprehensive income:Cumulative
      translation adjustment (d)
            
            
            31,380
            
            
            
            34,869Other
      comprehensive income under U.S. GAAP
            
            $
            45,513
            
            
            $
            3,067Net
      income (loss) under U.S. GAAP
            
            $
            14,133
            
            
            $
            (31,802
            )Deficit,
      beginning of year, under U.S. GAAP
            
            
            (24,471
            )
            
            
            (25,928
            )Temporary
      equity adjustment (b)
            
            
            (93,353
            )
            
            
            33,259Deficit,
      end of year, under U.S. GAAP
            
            $
            (103,691
            )
            
            $
            (24,471
            )Weighted
      average units for U.S. GAAP (000’s)Basic
            
            
            63,358
            
            
            
            61,661Diluted
            
            
            64,832
            
            
            
            61,661Net
      income (loss) per unit under U.S. GAAPBasic
      and diluted
            
            $
            0.22
            
            
            $
            (0.52
            )








The
application of U.S. GAAP would have the following effect on the consolidated
balance sheets as reported at December 31, 2009 and 2008:





2009
            
            
            2008Canadian
      GAAP
            
            
            U.S.
      GAAP
            
            
            Canadian
      GAAP
            
            
            U.S.
      GAAPAssets:Current
      assets
            
            $
            57,544
            
            
            $
            57,544
            
            
            $
            76,054
            
            
            $
            76,054Property,
      plant and equipment (a)
            
            
            399,237
            
            
            
            76,738
            
            
            
            491,654
            
            
            
            68,010Long-term
      receivables
            
            
            5,491
            
            
            
            5,491
            
            
            
            19,310
            
            
            
            19,310Other
      assets (e)
            
            
            -
            
            
            
            2,702
            
            
            
            -
            
            
            
            3,944Future/deferred
      income tax (a)
            
            
            -
            
            
            
            110,456
            
            
            
            -
            
            
            
            112,071$
            462,272
            
            
            $
            252,931
            
            
            $
            587,018
            
            
            $
            279,389Liabilities:Current
      liabilities (c)
            
            $
            28,821
            
            
            $
            30,990
            
            
            $
            137,602
            
            
            $
            133,912Long-term
      debt
            
            
            70,000
            
            
            
            70,000
            
            
            
            -
            
            
            
            -Convertible
      debentures (e)
            
            
            114,863
            
            
            
            119,860
            
            
            
            113,420
            
            
            
            120,331Asset
      retirement obligations
            
            
            21,055
            
            
            
            21,055
            
            
            
            22,151
            
            
            
            22,151Future/deferred
      income tax (a)
            
            
            8,487
            
            
            
            -
            
            
            
            19,429
            
            
            
            -243,226
            
            
            
            241,905
            
            
            
            292,602
            
            
            
            276,394Mezzanine
      equity (b)
            
            
            -
            
            
            
            134,111
            
            
            
            -
            
            
            
            37,295Unitholder's
      EquityUnitholders’
      capital (b)
            
            
            674,106
            
            
            
            -
            
            
            
            669,667
            
            
            
            -Equity
      component of convertible
              debentures
      (e)
            
            
            3,951
            
            
            
            -
            
            
            
            3,977
            
            
            
            -Contributed
      surplus (c)
            
            
            11,064
            
            
            
            -
            
            
            
            8,620
            
            
            
            -Accumulated
      other comprehensive income (loss) (d)
            
            
            (22,474
            )
            
            
            (19,394
            )
            
            
            18,471
            
            
            
            (9,829
            )Deficit
      (a) (b)
            
            
            (447,601
            )
            
            
            (103,691
            )
            
            
            (406,319
            )
            
            
            (24,471
            )219,046
            
            
            
            (123,085
            )
            
            
            294,416
            
            
            
            (34,300
            )$
            462,272
            
            
            $
            252,931
            
            
            $
            587,018
            
            
            $
            279,389








(a)  Property,
plant and equipment




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




Under
U.S. GAAP, the full cost method of accounting for oil and natural gas activities
requires Enterra to perform an impairment test using after-tax future net
revenue from proved oil and natural gas reserves, discounted at 10% plus the
lower of cost and recoverable amount of unproved
properties.  Effective for the year ended December 31, 2009, prices
used in the U.S. GAAP ceiling test are the 12-month average price prior to the
end of the reporting period.  Prior to December 31, 2009 the prices
used in the U.S. GAAP ceiling test were those in effect on the date the ceiling
test was performed.  Where the amount of a ceiling test write-down
under Canadian GAAP differs from the amount of the write-down under U.S. GAAP,
the charge for depletion will differ.




There
were ceiling test impairments recognized under U.S. GAAP at December 31,
2008, 2007, 2006, 2005, 2004 and 2001.  At December 31, 2008, Enterra
recognized a U.S. GAAP ceiling test write-down of $113.1 million ($81.0 million
after tax) in its Canadian cost center.  No U.S. GAAP ceiling test
impairment was recorded at December 31, 2008 in the U.S. cost
center.  Prior to 2008, Enterra recognized additional ceiling test
write-downs under U.S. GAAP of $150.7 million ($100.8 million after tax) in its
Canadian cost center and $295.0 million ($177.2 million after tax) in its U.S.
cost center.




For the
years ended December 31, 2009 and 2008, depletion expense under U.S. GAAP
was lower by $72.7 million ($48.1 million net of tax) and $52.5 million ($35.3
million net of tax), respectively.








(b)  Unitholder's
mezzanine equity




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




The
redemption feature causes the trust units to be classified as mezzanine equity
under U.S. GAAP.    Mezzanine equity is valued at an amount
equal to the redemption value of the trust units at the balance sheet
date.  Any increase or decrease in the redemption value during a
period is charged to the deficit.




As at
December 31, 2009, unitholders’ capital was reduced by $674.1 million (December
31, 2008 - $ 669.7 million) and the redemption value of the trust units of
$134.1 million (December 31, 2008 - $37.3 million) was recorded as mezzanine
equity.  The change in the redemption value of the trust units is
recorded as a reduction or increase to the deficit.  For the year
ended December 31, 2009, the deficit was increased by $92.4 million (December
31, 2008 – deficit decreased by $33.3 million).







(c)  Unit-based
compensation




Under
Canadian GAAP, Enterra’s unit-based compensation plans are accounted for as
equity settled awards.  Under U.S. GAAP, the redemption feature of the
trust units results in the unit-based compensation plans being accounted for as
liability based awards, which are recorded at fair value with changes in fair
value included in earnings.  As at December 31, 2009, the estimate
fair value of vested unit-based compensation awards of $2.2 million is included
in current liabilities (December 31, 2008 - $0.5 million) with $0.5 million in
unit-based compensation vesting and issued on December 31, 2009.  The
change in the fair value of unit-based compensation plan liability of $2.2
million is charged to earnings (2008 –$0.2 million).




Enterra
issues units out of treasury upon the exercise of all unit options, restricted
units and performance units.




For the
years ended December 31, 2009 and 2008, Enterra recorded the following
unit-based compensation (000s):





Restricted
      and performance units
            
            
            Unit
      options
            
            
            Total2009
            
            
            2008
            
            
            2009
            
            
            2008
            
            
            2009
            
            
            2008Unit-based
      compensation  expense
            
            $
            1,941
            
            
            $
            145
            
            
            $
            223
            
            
            $
            15
            
            
            $
            2,164
            
            
            $
            160










A summary
of the status of the unvested options, restricted units and performance units as
of December 31, 2009 and changes during 2009 is presented below:





Number
      of unvested options
            
            
            Weighted
      average grant date fair value
            
            
            Number
      of unvested restricted units
            
            
            Weighted
      average grant date fair value
            
            
            Number
      of unvested performance units
            
            
            Weighted
      average grant date fair valueUnvested,
      December 31, 2008
            
            
            356,664
            
            
            $
            0.90
            
            
            
            2,279,786
            
            
            $
            4.13
            
            
            
            174,398
            
            
            $
            4.17Granted
            
            
            -
            
            
            
            -
            
            
            
            337,337
            
            
            
            1.64
            
            
            
            -
            
            
            
            -Exercised
            
            
            (219,665
            )
            
            
            0.92
            
            
            
            (669,515
            )
            
            
            4.85
            
            
            
            (97,387
            )
            
            
            2.30Forfeited
            
            
            (106,999
            )
            
            
            0.92
            
            
            
            (343,283
            )
            
            
            3.38
            
            
            
            (77,011
            )
            
            
            6.53Unvested,
      December 31, 2009
            
            
            30,000
            
            
            $
            0.70
            
            
            
            1,604,325
            
            
            $
            3.47
            
            
            
            -
            
            
            $
            -




The
following tables provide information related to unit option, restricted unit and
performance unit activity during the year ended December 31, 2009:





Number
      of unit options
            
            
            Weighted
      average exercise price
            
            
            Weighted
      average contract life
            
            
            Aggregate
      intrinsic value (000’s)Options
      outstanding, January 1, 2009
            
            
            1,042,000
            
            
            $
            7.75Options
      granted
            
            
            -
            
            
            
            -Options
      forfeited
            
            
            (336,000
            )
            
            
            10.17Options
      outstanding, December 31, 2009
            
            
            706,000
            
            
            $
            6.60
            
            
            
            1.70
            
            
            $
            156Options
      expected to vest, December 31, 2009
            
            
            676,000
            
            
            $
            6.77
            
            
            
            1.68
            
            
            $
            156Options
      exercisable, December 31, 2009
            
            
            676,000
            
            
            $
            6.77
            
            
            
            1.68
            
            
            $
            156





Number
      of units
            
            
            Weighted
      average contract life
            
            
            Aggregate
      intrinsic value (000’s)Restricted
      units outstanding, January 1, 2009
            
            
            2,279,786Restricted
      units granted
            
            
            337,337Restricted
      units exercised
            
            
            (669,515
            )Restricted
      units forfeited
            
            
            (343,283
            )Restricted
      units outstanding, December 31, 2009
            
            
            1,604,325
            
            
            
            1.16
            
            
            $
            3,481Restricted
      units expected to vest, December 31, 2009
            
            
            1,347,633
            
            
            
            1.16
            
            
            $
            2,924Restricted
      units exercisable, December 31, 2009
            
            
            -
            
            
            
            -
            
            
            $
            -













Number
      of units
            
            
            Weighted
      average contract life
            
            
            Aggregate
      intrinsic value (000’s)Performance
      units outstanding, January 1, 2009
            
            
            174,494Performance
      units granted
            
            
            -Performance
      units exercised
            
            
            (97,387
            )Performance
      units forfeited
            
            
            (77,011
            )Performance
      units outstanding, December 31, 2009
            
            
            -
            
            
            
            -
            
            
            $
            -Performance
      units expected to vest, December 31, 2009
            
            
            -
            
            
            
            -
            
            
            $
            -Performance
      units exercisable, December 31, 2009
            
            
            -
            
            
            
            -
            
            
            $
            -







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




The fair
value of each stock option award is estimated on grant date and each reporting
period until vesting using the Black-Scholes option pricing model based on
assumptions noted in the following table.







2009
            
            
            2008Risk-free
      interest rate (%)
            
            
            0.50
            
            
            
            1.25Expected
      term (years)
            
            
            0.1
      – 2.1
            
            
            
            1.1
      – 3.1Expected
      cash distribution yield (%)
            
            
            -
            
            
            
            -Expected
      volatility (%)
            
            
            83
      – 157
            
            
            
            130
      – 159




The
intrinsic value of options exercised in 2009 was nil (2008 –
nil).  There were no options issued during 2009, therefore, the
weighted average grant date fair value for options granted in was nil (2008 -
$0.70).




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




The
intrinsic value of restricted units exercised in 2009 was $0.9 million (2008 -
$1.4 million).  The weighted average grant date fair value of the
restricted units granted was $1.64 (2008 – $3.77).




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




The
intrinsic value of performance units exercised in 2009 was $0.4 million (2008 –
nil).  There were no performance units granted during 2009, therefore,
the weighted average grant date fair value of the performance units granted was
nil (2008 – nil as no performance units were granted).




As of
December 31, 2009, there was a negligible amount (2008 – $0.1 million) of total
unrecognized compensation cost related to unvested unit options.  The
cost is expected to be recognized over a weighted average period of 1.1 years
(2008 – 0.7 years).




As of
December 31, 2009, there was $1.6 million (2008 - $1.0 million) of unrecognized
compensation cost related to unvested restricted units.  The cost is
expected to be recognized over a weighted average period of 1.1 years (2008 –
1.6 years).




As of
December 31, 2009 and 2008, there was no amount of unrecognized compensation
cost related to unvested performance units.




Under
U.S. GAAP, the amount of compensation costs related to options, restricted units
and performance units to be capitalized was $0.1 million (2008 –
nil).





(d)
Cumulative translation adjustment and other comprehensive income




Enterra’s
U.S. oil and natural gas properties are considered to be self
sustaining.  Under Canadian GAAP, a portion of the cumulative
translation adjustment is recognized in income as the investment in the foreign
operations is reduced.  Under U.S. GAAP, the cumulative translation
adjustment is only recognized in income upon disposition of the
segment.  For the year ended December 31, 2009, $0.2 million (2008 -
$2.1 million) of the cumulative translation adjustment was recognized as a
foreign exchange loss under Canadian GAAP.  The difference in other
comprehensive income under U.S. GAAP as compared to Canadian GAAP is a result of
differences between the carrying values of the assets and liabilities of the
U.S. self sustaining operations under U.S. GAAP versus Canadian
GAAP.  These differences in the carrying values result in differences
in the foreign exchange gains and losses on translation of the U.S.
operations.





(e)
Convertible debentures




In
November 2006 and April 2007, Enterra issued convertible
debentures.  Under Canadian GAAP, Enterra’s convertible debentures are
classified as debt with a portion representing the value associated with the
conversion feature being allocated to equity and the issue costs netted against
the debt.  Under U.S. GAAP, the convertible debentures in their
entirety are classified as debt and the issue costs classified as other
assets.  In addition, under Canadian GAAP, a non-cash interest expense
representing the effective yield of the debt component is recorded in the
consolidated statement of loss with a corresponding credit to the convertible
debenture liability balance to accrete that balance to the full principal due on
maturity.  Under U.S. GAAP, this non-cash interest expense is not
recorded but the issue costs are amortized over the life of
debentures.





(f)
Additional disclosure under U.S. GAAP





2009
            2008Components
      of accounts receivable:Trade
            
            $       7,650
            $     29,821Accruals
            
            17,171
            15,156Allowance
      for doubtful accounts
            (1,154)
            (9,618)$     23,667
            $     35,359Components
      of prepaid expenses:Prepaid
      expenses
            
            $       1,414
            $          992Funds
      on deposit
            
            584
            967$       1,998
            $       1,959Components
      of accounts payable:Accounts
      payable
            
            $     18,196
            $     18,741Accrued
      liabilities
            
            9,801
            19,208$     27,997
            $     37,949














(g)
Uncertainty in tax positions





As at
December 31, 2009 and 2008, Enterra did not have any amounts recorded pertaining
to uncertain tax positions.





Enterra
files federal and provincial income tax returns in Canada and federal, state and
local income tax returns in the U.S., as applicable.  Enterra may be
subject to a reassessment of federal and provincial income taxes by Canadian tax
authorities for a period of four years from the date of mailing of the original
notice of assessment in respect of any particular taxation year.  For
the Canadian tax returns, the open taxation years range from 2004 to
2009.  For the U.S. tax returns, the open taxation years range from
2007 to 2009.  The U.S. federal statute of limitations for
assessment of income tax is generally closed for the tax years ending on or
prior to 2002.  In certain circumstances, the U.S. federal
statute of limitations can reach beyond the standard three year period.
U.S. state statutes of limitations for income tax assessment vary from
state to state.  Tax authorities of Canada and U.S. have not audited
any of Enterra’s, or its subsidiaries’, income tax returns for the open taxation
years noted above.





Enterra
recognizes interest and penalties related to uncertain tax positions in tax
expense.  During the years ended December 31, 2009 and 2008,
there were no charges for interest or penalties.





(h)
Fair value of commodity contracts


Certain
of Enterra’s assets and liabilities are reported at fair value in the balance
sheets.  The following tables provide fair value measurement
information for such assets and liabilities as of December 31, 2009 and 2008
including items where the fair value is disclosed on a reoccurring
basis.





The
carrying values of cash and cash equivalents, accounts receivable, long-term
debt and accounts payable and accrued liabilities included in the accompanying
consolidated balance sheets approximated fair value at December 31, 2009 and
2008 as the amounts were short term in nature or bore interest at floating
rates.  These assets and liabilities are not presented in the
following tables.





As
      at December 31, 2009Fair
      Value Measurements Using:Carrying
      Amount
            Fair
              Value
            Level
      1
            Level
      2
            Level
      3Commodity
      contracts (net)
            238
            238
            -
            238
            -Convertible
      debentures
            (114,863)
            (114,764)
            (114,764)
            -
            -





As
      at December 31, 2008Fair
      Value Measurements Using:Carrying
      Amount
            Fair
              Value
            Level
      1
            Level
      2
            Level
      3Commodity
      contracts (net)
            14,338
            14,338
            -
            14,338
            -Convertible
      debentures
            (113,420)
            (76,049)
            (76,049)
            -
            -





Enterra
uses a fair value hierarchy that prioritizes the inputs to valuation techniques
used to measure fair value.  This hierarchy consists of three broad
levels.  Level 1 inputs on the hierarchy consist of unadjusted
quoted prices in active markets for identical assets and liabilities and have
the highest priority.  Level 2 and 3 inputs have lower priorities. The
Trust uses appropriate valuation techniques based on the available inputs to
measure the fair values of assets and liabilities.  When available,
Enterra measures fair value using Level 1 inputs because they generally
provide the most reliable evidence of fair value.





The
following methods and assumptions were used to estimate the fair values of the
assets and liabilities in the table above.





Level 1
Fair Value Measurements


Convertible
debentures – The fair values of the convertible debentures are estimated using
unadjusted quoted prices in active markets.





Level 2
Fair Value Measurements


Commodity
contracts – The fair values of the commodity contracts are estimated using
discounted cash flow calculations based upon forward commodity price curves and
quotes obtained from brokers for contracts with similar terms or quotes obtained
from counterparties to the contracts taking into consideration the credit
worthiness of those brokers or counterparties.





Level 3
Fair Value Measurements


The Trust
does not have any financial assets or financial liabilities whose fair value is
measured using this method.





(i)
Accounting policy changes under U.S. GAAP





In June
2009, the Financial Accounting Standards Board (“FASB”) developed the Accounting
Standards Codification (“codification”) that consolidates all authoritative
accounting guidance into a single source that uses a simple, consistent
structure for organizing accounting topics.  The codification does not
change U.S. GAAP but reorganizes it into a consistent structure for ease of
research and cross-reference.  All other non-grandfathered non-SEC
accounting literature not included in the codification will become
non-authoritative.  The codification became effective for interim and
annual periods ending after September 15, 2009 and implementation had no effect
on Enterra’s financial position, results of operations or cash
flow.





Effective
January 1, 2009, Enterra adopted new U.S. GAAP standards with respect to
business combinations which require an acquirer to be identified for all
business combinations and applies the same method of accounting for business
combinations (the acquisition method) to all transactions.  In
addition, transaction costs associated with acquisitions are required to be
expensed.  The application of these new standards did not create a
significant Canadian to US GAAP difference in 2009.





On
December 31, 2009, Enterra adopted new rules and regulations issued by the SEC
with respect to reserves and reporting of reserves.  The new rules
impacted the calculation of the U.S. GAAP ceiling test.  Effective
December 31, 2009, the ceiling test is based on the proven reserves discounted
at ten percent using the average of the commodity prices on the first day of
each month in the year rather than the year end commodity
prices.





SUPPLEMENT
INFORMATION – OIL AND GAS PRODUCING ACTIVITIES (unaudited)




The
following are supplementary oil and gas disclosures required under U. S.
generally accepted accounting principles.  Amounts are in Canadian
dollars unless otherwise denoted.




OIL
AND GAS RESERVES




In
December 2009, Enterra adopted revised oil and gas reserve estimation and
disclosure requirements.  The primary impact of the new disclosures is
to conform the definition of proved reserves with the SEC Modernization of Oil
and Gas Reporting rules, which were issued by the SEC at the end of
2008.  The accounting standards update revised the definition of oil
and gas reserves to require that the average first day of the month price during
the 12 month period before the end of the year, rather than the yearend price,
must be used when estimating whether reserve quantities are economical to
produce.  This same 12 month average price is also used in calculating
the aggregate amount (and changes in) future cash inflows related to the
standardized measure of discounted net cash flows.  The rules also
allow for the use of reliable technology to estimate proved oil and gas reserves
if those technologies have been demonstrated to result in reliable conclusions
about reserve volumes.  The unaudited supplemental information on oil
and gas exploration and production activities for 2009 has been presented in
accordance with the new reserve estimation and disclosure rules, which may not
be applied retrospectively.  The 2008 data is presented in accordance
with FASB oil and gas disclosure requirements effective during this
period.




Users of
this information should be aware that the process of estimating quantities of
“proved” and “proved developed” crude oil and natural gas reserves is very
complex, requiring significant subjective decisions in the evaluation of all
available geological, engineering and economic data for each
reservoir.  The data for a given reservoir may also change
substantially over time as a result of numerous factors including, but not
limited to, additional development activity, evolving production history, and
continual reassessment of the viability of production under varying economic
conditions.  Consequently, material revisions to existing reserve
estimates occur from time to time.  Although every reasonable effort
is made to ensure that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective decisions required and
variances in available data for various reservoirs make these estimates
generally less precise than other estimates presented in connection with
financial statement disclosures.




Proved
oil and gas reserves are those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to
be economically producible from a given date forward, from known reservoirs, and
under existing economic conditions, operating methods and government
regulations.




Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating
methods.




Canadian
provincial royalties are determined based on a graduated percentage scale that
varies with prices and production volumes.  Canadian reserves, as
presented on a net basis, assume prices and royalty rates in existence at the
time that estimates were made and the Trust’s estimate of future production
volumes.  Future fluctuations in prices, production rates, or changes
in political or regulatory environments could cause the Trust’s share of future
production from Canadian reserves to be materially different from that
presented.







COSTS
INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES




Costs
incurred by the Trust in oil and gas producing activities for the years ended
December 31 are as follows:




(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2009
      TotalProperty
      acquisition costs:Proved
            
            
            -
            
            
            
            9,026
            
            
            
            9,026Unproved
            
            
            3,208
            
            
            
            5,182
            
            
            
            8,390Exploration
      costs
            
            
            428
            
            
            
            -
            
            
            
            428Development
      costs
            
            
            5,494
            
            
            
            1,639
            
            
            
            7,133Property
      acquisition, exploration, and development expenditures
            
            
            9,130
            
            
            
            15,847
            
            
            
            24,977







(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2008
      TotalProperty
      acquisition costs:Proved
            
            
            -
            
            
            
            -
            
            
            
            -Unproved
            
            
            3,049
            
            
            
            10,805
            
            
            
            13,854Exploration
      costs
            
            
            -
            
            
            
            -
            
            
            
            -Development
      costs
            
            
            18,399
            
            
            
            861
            
            
            
            19,260Property
      acquisition, exploration, and development expenditures
            
            
            21,448
            
            
            
            11,666
            
            
            
            33,114





Acquisition
costs include costs incurred to purchase, lease or otherwise acquire oil and gas
properties.




Development
costs include the costs of drilling and equipping development wells and
facilities to extract, treat and gather and store oil and gas as well as
additions to asset retirement obligations.




Enterra
capitalizes a portion of general and administrative costs associated with
exploration activities and development activities.  Prior to 2009,
transaction costs directly attributable to successful acquisitions were also
capitalized.  In 2009, transaction costs are expensed under U.S.
accounting standards.










CAPITALIZED
COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES




The
capitalized costs and related accumulated depreciation, depletion and
amortization, including impairments, relating to the Trust’s oil and gas
exploration, development and producing activities for the years ended
December 31 consist of:




(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2009
      TotalOil
      and gas properties
            
            
            705,224
            
            
            
            371,679
            
            
            
            1,076,903Less:Accumulated
      depletion, depreciation and amortization
            
            
            667,792
            
            
            
            332,373
            
            
            
            1,000,165Net
      capitalized costs
            
            
            37,432
            
            
            
            39,306
            
            
            
            76,738







(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2009
      TotalUnproven
      oil and gas properties
            
            
            9,813
            
            
            
            10,283
            
            
            
            20,096Proven
      oil and gas properties
            
            
            27,619
            
            
            
            29,023
            
            
            
            56,642Net
      capitalized costs
            
            
            37,432
            
            
            
            39,306
            
            
            
            76,738








(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2008
      TotalOil
      and gas properties
            
            
            716,814
            
            
            
            391,178
            
            
            
            1,107,992Less:Accumulated
      depletion, depreciation and amortization
            
            
            (680,733
            )
            
            
            (359,249
            )
            
            
            (1,039,982
            )Net
      capitalized costs
            
            
            36,081
            
            
            
            31,929
            
            
            
            68,010







(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2008
      TotalUnproven
      oil and gas properties
            
            
            11,779
            
            
            
            11,854
            
            
            
            23,633Proven
      oil and gas properties
            
            
            24,302
            
            
            
            20,075
            
            
            
            44,377Net
      capitalized costs
            
            
            36,081
            
            
            
            31,929
            
            
            
            68,010











OIL
AND GAS RESERVE INFORMATION




At
December 31, 2009, Enterra reserves were located in Canada in the provinces of
Alberta, British Columbia and Saskatchewan as well as in the United States in
the state of Oklahoma.  McDaniel & Associates Consultants Ltd.
(“McDaniel”) reviewed the reserves in Canada and Haas Petroleum Engineering
Services, Inc. (“Haas”) reviewed the reserves in Oklahoma.   The
tables below provide a summary of the Trust’s proved developed and undeveloped
reserves after deductions of royalties as evaluated by McDaniel and Haas based
on constant price and cost assumptions.




CANADA
            
            Crude
      oil and NGL (mbbl)
            
            
            Natural
      gas (mmcf)Net
      proved developed and undeveloped reserves after royaltiesEnd
      of year 2007
            
            
            3,885
            
            
            
            28,154Revision
      of previous estimates
            
            
            (341
            )
            
            
            (3,449
            )Extensions
      and discoveries
            
            
            128
            
            
            
            457Purchase
      of reserves in place
            
            
            3
            
            
            
            9Production
            
            
            (914
            )
            
            
            (4,070
            )Sales
      of reserves in place
            
            
            (767
            )
            
            
            (6,524
            )End
      of year 2008
            
            
            1,994
            
            
            
            14,577Revision
      of previous estimates
            
            
            946
            
            
            
            368Extensions
      and discoveries
            
            
            4
            
            
            
            83Purchase
      of reserves in place
            
            
            -
            
            
            
            -Production
            
            
            (732
            )
            
            
            (3,537
            )Sales
      of reserves in place
            
            
            -
            
            
            
            -End
      of year 2009
            
            
            2,212
            
            
            
            11,491Net
      proved developed reserves after royaltiesEnd
      of year 2007
            
            
            3,637
            
            
            
            26,399End
      of year 2008
            
            
            1,994
            
            
            
            14,577End
      of year 2009
            
            
            2,125
            
            
            
            11,426





UNITED
      STATES
            
            Crude
      oil and NGL (mbbl)
            
            
            Natural
      gas (mmcf)Net
      proved developed and undeveloped reserves after royaltiesEnd
      of year 2007
            
            
            897
            
            
            
            43,847Revision
      of previous estimates
            
            
            2,911
            
            
            
            (11,150
            )Extensions
      and discoveries
            
            
            278
            
            
            
            2,399Purchase
      of reserves in place
            
            
            -
            
            
            
            -Production
            
            
            (159
            )
            
            
            (7,194
            )Sales
      of reserves in place
            
            
            -
            
            
            
            (951
            )End
      of year 2008
            
            
            3,927
            
            
            
            26,951Revision
      of previous estimates
            
            
            2,658
            
            
            
            12,730Extensions
      and discoveries
            
            
            36
            
            
            
            302Purchase
      of reserves in place
            
            
            296
            
            
            
            2,451Production
            
            
            (744
            )
            
            
            (5,335
            )Sales
      of reserves in place
            
            
            -
            
            
            
            -End
      of year 2009
            
            
            6,173
            
            
            
            37,099Net
      proved developed reserves after royaltiesEnd
      of year 2007
            
            
            797
            
            
            
            37,454End
      of year 2008
            
            
            3,649
            
            
            
            23,105End
      of year 2009
            
            
            4,850
            
            
            
            26,325





Notes:





1.
            Net
      after royalty reserves are the Trust’s overriding royalty and working
      interest share of the gross remaining reserves, after deduction of any
      crown, freehold and overriding royalties.  Such royalties are
      subject to change by legislation or regulation and can also vary depending
      on production rates, selling prices and timing of initial
      production.


2.
            Reserves
      are the estimated quantities of crude oil, natural gas and related
      substances anticipated from geological and engineering data to be
      recoverable from known accumulations, from a given date forward, by known
      technology, under existing operating conditions and the average of the
      commodity prices on the first day of each month for the year ended
      December 31, 2009.  Prior to December 31, 2009 reserves are
      based on the commodity prices in effect on the last day of the
      year.




3.
            Proved
      oil and gas reserves are the estimated quantities of crude oil, natural
      gas and natural gas liquids which geological and engineering data
      demonstrate with reasonable certainty to be recoverable in future years
      from known reservoirs under existing economic and operating
      conditions.


4.
            Proved
      developed oil and gas reserves are reserves that can be expected to be
      recovered through existing wells with existing equipment and operating
      methods.  Proved undeveloped reserves are reserves that are
      expected to be recovered from known accumulations where a significant
      expenditure is required.







STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS
RESERVES




The
following information is based on crude oil and natural gas reserve and
production volumes estimated by the independent engineering consultants of the
Trust.  It may be useful for certain comparison purposes, but should
not be solely relied upon in evaluating the Trust or its
performance.  Further, information contained in the following table
should not be considered as representative of realistic assessments of future
cash flows, nor should the Standardized Measure of Discounted Future Net Cash
Flows be viewed as representative of the current value of Enterra’s
reserves.




The
future cash flows presented below are based on sales prices, cost rates, and
statutory income tax rates in existence as of the date of the projections and
the average commodity prices in effect on the first day of each month for the
year ended December 31, 2009.  Prior to 2009, future net cash flows
were based on commodity prices in effect on the last day of the
year.  It is expected that material revisions to some estimates of
crude oil and natural gas reserves may occur in the future, development and
production of the reserves may occur in periods other than those assumed, and
actual prices realized and costs incurred may vary significantly from those
used.




Management
does not rely upon the following information in making investment and operating
decisions.  Such decisions are based upon a wide range of factors,
including estimates of probable as well as proved reserves, and varying price
and cost assumptions considered more representative of a range of possible
economic conditions that may be anticipated.




The
computation of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves at December 31, 2009 was based on
the following benchmark prices (average prices of the first day of each month in
2009): Edmonton light crude price of $65.21/bbl, Alberta average plant gate
price of $3.77/mcf, WTI oil price of US$61.18/bbl and US Henry Hub gas prices of
US$3.82/mcf.  The computation of the standardized measure of
discounted future net cash flows relating to proved oil and gas reserves at
December 31, 2008 was based on the following benchmark price (December 31,
2008 prices): Edmonton light crude price of $45.12/bbl, Alberta average plant
gate price of $6.15/mcf, WTI oil price of US$44.60/bbl and US Henry Hub gas
prices of US$5.71/mcf.




The
following table sets forth the standardized measure of discounted future net
cash flows from projected production of the Trust’s crude oil and natural gas
reserves at December 31 for the years presented.




(million
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2009
      TotalFuture
      cash inflows
            
            
            207
            
            
            
            439
            
            
            
            646Future
      costs:Future
      production and development costs
            
            
            (137
            )
            
            
            (284
            )
            
            
            (421
            )Future
      income taxes
            
            
            -
            
            
            
            (5
            )
            
            
            (5
            )Future
      net cash flows
            
            
            70
            
            
            
            150
            
            
            
            220Deduct:
      10% annual discount factor
            
            
            (13
            )
            
            
            (67
            )
            
            
            (80
            )Standardized
      measure of discounted future net cash flows
            
            
            57
            
            
            
            83
            
            
            
            140







(millions
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2008
      TotalFuture
      cash inflows
            
            
            210
            
            
            
            461
            
            
            
            671Future
      costs:Future
      production and development costs
            
            
            (160
            )
            
            
            (273
            )
            
            
            (433
            )Future
      income taxes
            
            
            -
            
            
            
            (32
            )
            
            
            (32
            )Future
      net cash flows
            
            
            50
            
            
            
            156
            
            
            
            206Deduct:
      10% annual discount factor
            
            
            (9
            )
            
            
            (45
            )
            
            
            (54
            )Standardized
      measure of discounted future net cash flows
            
            
            41
            
            
            
            111
            
            
            
            152















CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOW RELATING TO PROVED OIL
AND GAS RESERVES




The
following table sets forth the changes in the standardized measure of discounted
future net cash flows at December 31 for the years presented:




(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2009
      TotalFuture
      discounted net cash flows at beginning of year
            
            
            41,000
            
            
            
            111,283
            
            
            
            152,283Revenues,
      net of royalties and production costs
            
            
            (20,235
            )
            
            
            (29,349
            )
            
            
            (49,584
            )Change
      due to prices, net of production costs
            
            
            19,786
            
            
            
            (39,492
            )
            
            
            (19,706
            )Development
      costs during the year
            
            
            1,200
            
            
            
            10,871
            
            
            
            12,071Changes
      in estimated future development costs
            
            
            (1,484
            )
            
            
            (46,883
            )
            
            
            (48,367
            )Changes
      due to extensions, discoveries and improved recovery
            
            
            273
            
            
            
            1,551
            
            
            
            1,824Change
      due to revisions
            
            
            12,673
            
            
            
            46,285
            
            
            
            58,958Acquisitions
      of reserves
            
            
            -
            
            
            
            12,660
            
            
            
            12,660Disposition
      of reserves
            
            
            -
            
            
            
            -
            
            
            
            -Accretion
      of discount
            
            
            4,100
            
            
            
            11,128
            
            
            
            15,228Other
      significant factors
            
            
            -
            
            
            
            (16,790
            )
            
            
            (16,790
            )Changes
      in income taxes
            
            
            -
            
            
            
            22,505
            
            
            
            22,505Future
      discounted net cash flows at end of year
            
            
            57,313
            
            
            
            83,769
            
            
            
            141,082







(thousands
      of dollars)
            
            Canada
            
            
            United
      States
            
            
            2008
      TotalFuture
      discounted net cash flows at beginning of year
            
            
            158,353
            
            
            
            149,495
            
            
            
            307,848Revenues,
      net of royalties and production costs
            
            
            (18,939
            )
            
            
            (32,880
            )
            
            
            (51,819
            )Change
      due to prices, net of production costs
            
            
            (111,783
            )
            
            
            (98,040
            )
            
            
            (209,823
            )Development
      costs during the year
            
            
            11,121
            
            
            
            19,143
            
            
            
            30,264Changes
      in estimated future development costs
            
            
            (1,000
            )
            
            
            (20,022
            )
            
            
            (21,022
            )Changes
      due to extensions, discoveries and improved recovery
            
            
            2,428
            
            
            
            17,609
            
            
            
            20,037Change
      due to revisions
            
            
            (10,893
            )
            
            
            27,346
            
            
            
            16,453Acquisitions
      of reserves
            
            
            54
            
            
            
            -
            
            
            
            54Disposition
      of reserves
            
            
            (22,055
            )
            
            
            (4,117
            )
            
            
            (26,172
            )Accretion
      of discount
            
            
            15,835
            
            
            
            14,950
            
            
            
            30,785Other
      significant factors
            
            
            -
            
            
            
            32,587
            
            
            
            32,587Changes
      in income taxes
            
            
            17,879
            
            
            
            5,212
            
            
            
            23,091Future
      discounted net cash flows at end of year
            
            
            41,000
            
            
            
            111,283
            
            
            
            152,283





Note:




1.
      The schedules above are calculated using year-end costs, statutory tax
      rates and proved oil and gas reserves and the average of the commodity
      prices on the first day of each month for the year ended December 31,
      2009.  Prior to December 31, 2009, the schedules are based on
      the commodity prices in effect on the last day of the year.  The
      value of exploration properties and probable reserves, future exploration
      costs, future changes in oil and gas prices and in production and
      development costs are excluded.