Bonterra Energy Income Trust Announces Fourth Quarter and Annual Results



    CALGARY, March 19 /CNW/ - Bonterra Energy Income Trust
(www.bonterraenergy.com) (TSX:BNE.UN) is pleased to announce its financial and
operational results for the three months and fiscal year ended December 31,
2007.

    HIGHLIGHTS

    Capital Spending and Production
    -------------------------------
    In 2007 Bonterra's capital expenditure was $19,000,000, down from
$38,000,000 in 2006. This reduction was caused mainly by uncertainty regarding
what the impact of the Alberta royalty structure change will be and by the out
of control drilling costs encountered in 2006. In 2007 the Trust drilled
22 gross (15.3 net) Cardium oil wells and 2 gross (0.7 net) Edmonton Sand
natural gas wells with a 100 percent success rate.
    The capital program was successful in replacing the 2007 annual
production and in increasing overall reserves as well as increasing the daily
production rate to 4,218 BOE from 4,042 in 2006. It is expected that average
production will increase in 2008. The exit production rate for December 2007
was approximately 4,400 BOE per day.
    Internal calculations of the estimated inventory of economic undrilled
locations, net to the Trust, using a crude oil price of $80 and capital
expenditures of $900,000 per Cardium well ($375,000 for a natural gas well)
(subject to the terms of the new Alberta royalty structure) is:

    
    -   Cardium oil and solution gas wells:       330
    -   Natural gas wells                          10
                                                 -----
                                                  340
                                                 -----
                                                 -----
    

    At the current rate of drilling, the Trust will have a drilling inventory
of approximately 17 years. It is not anticipated that these drill locations
will have any significant impact on production from existing wells.

    Reserves
    --------
    Gross proved plus probable crude oil and NGL reserves increased by
2 percent and gross proved plus probable natural gas reserves increased by
9 percent. These percentages were somewhat affected by the property swap of
Dodsland area, Saskatchewan, properties for Pembina area, Alberta, properties,
whereby the Dodsland property ratio of oil to solution gas was higher than the
ratio of oil to solution gas for the Pembina property. The reserve life index
for 2007 (using Q4, 2007 production) is 17.4 years compared to 17.6 years in
2006. The slight reduction is due to Q4, 2007 production increasing to 4,295
BOE compared to 4,118 BOE in Q4, 2006. On a per unit basis the reserves in BOE
per weighted average outstanding unit increased to 1.62 in 2007 from 1.57 in
2006.
    The Trust is extremely pleased with its 2007 finding and development
costs of $2.68 per BOE for proved plus probable reserve additions. The recycle
ratio in 2007 was 13.0 (2006 - 1.9). The exceptional costs and ratio in 2007
are attributable to lower capital costs per well and also due to a carry over
from 2006 activities. At December 31, 2006, drilled wells that were not on
production were assigned low reserves or no reserves and when these wells were
put on production in 2007, the independent engineers, giving consideration to
the 2007 production history, assigned or increased previously assigned
reserves to all of these wells.

    Bank Debt
    ---------
    Bank debt at December 31, 2007, was $57,422,000 compared to $45,379,000
in 2006. This represents a debt to funds flow ratio (by annualizing the Q4,
2007, adjusted distribution base) of 10.9 months compared to the 2006 ratio of
11 months. It is anticipated that this ratio will be reduced in 2008.

    Cash Netback and Recycle Ratio
    ------------------------------
    Bonterra's cash netback in 2007 was $34.93 compared to $35.04 in 2006. It
should be noted that due to an increase in production and commodity prices and
the property swap, the Q4, 2007, netback increased to $40.09 compared to
$34.96 for Q4, 2006. The Trust's recycle ratio in 2007 was 13.0 compared to
1.9 in 2006.

    
    FINANCIAL AND OPERATIONAL SUMMARY

                             Three Months Ended            Years Ended
                                 December 31               December 31
                              2007         2006         2007         2006
    -------------------------------------------------------------------------
    Realized Oil, Gas
     & NGL Sales          $26,573,000  $21,719,000  $96,431,000  $88,734,000
    Adjusted Distribution
     Base(1)              $15,842,000  $12,235,000  $53,815,000  $52,797,000
      Per Unit - basic    $      0.94  $      0.72  $      3.18  $      3.15
      Per Unit - diluted  $      0.94  $      0.72  $      3.18  $      3.12
    Net Earnings          $ 7,920,000  $ 6,471,000  $30,350,000  $37,250,000
      Per Unit - basic    $      0.47  $      0.39  $      1.79  $      2.23
      Per Unit - diluted  $      0.47  $      0.38  $      1.79  $      2.21
    Distributions
     per Unit             $      0.66  $      0.72  $      2.64  $      2.82
    Payout Ratio                                            83%          90%
    Units outstanding                                16,928,158   16,874,658
    Daily Oil and NGL
     Production (Bbls)          3,098        3,138        3,113        3,040
    Daily Gas
     Production (MCF)           7,176        5,885        6,627        6,014
    Daily BOE (6:1)             4,295        4,119        4,218        4,042
    Average Liquid Price
     ($/Bbl)              $     77.60  $     60.79  $     70.31  $     64.69
    Average Gas Price
     ($/MCF)              $      6.70  $      7.57  $      6.75  $      7.55
    Average BOE Price
     ($/BOE)              $     67.25  $     57.32  $     62.64  $     60.13
    Net Back per BOE(2)   $     40.09  $     32.21  $     34.96  $     35.04
    Reserves
    Oil and Liquids
     (barrels in 000's)
      Proved Developed
       Producing (Gross)(3)                              14,468       13,688
      Proved (Gross)                                     17,472       16,758
      Proved plus
       Probable (Gross)                                  21,910       21,526
    Natural Gas (MCF
     in 000's)
      Proved Developed
       Producing (Gross)                                 19,863       17,011
      Proved (Gross)                                     24,125       22,562
      Proved plus
       Probable (Gross)                                  32,465       29,700
    Reserve Life Index
     (Oil, liquids and
     natural gas at 6:1)(4)
      Proved Developed
       Producing                                           11.3         11.0
      Proved                                               13.7         13.6
      Proved plus Probable                                 17.4         17.6
    Reserves in BOE's per
     Weighted Average
     Outstanding Unit
      Proved Developed
       Producing                                           1.05         0.98
      Proved                                               1.27         1.22
      Proved plus Probable                                 1.62         1.57
    -------------------------------------------------------------------------
    (1) Adjusted distribution base (formally funds flow from operations) is
        not a recognized measure under GAAP. Management believes that in
        addition to net earnings, adjusted distribution base is a useful
        supplemental measure as it demonstrates the Trust's ability to
        generate the cash necessary to make trust distributions, repay debt
        or fund future growth through capital investment. Investors are
        cautioned, however, that this measure should not be construed as an
        indication of the Trust's performance. The Trust's method of
        calculating this measure may differ from other issuers and
        accordingly, it may not be comparable to that used by other issuers.
        For these purposes, the Trust defines adjusted distribution base as
        funds provided by operations before changes in non-cash operating
        working capital items excluding gain on sale of property and asset
        retirement expenditures.

        The Canadian Institute of Chartered Accountants ("CICA") recently
        published recommendations regarding disclosure of a measure called
        Standardized Distributable Cash. Please refer to pages 23 and 24 of
        this report for the reconciliation between adjusted distribution base
        and standardized distributable cash.

    (2) BOE's are calculated using a conversion ratio of 6 MCF to 1 barrel of
        oil. The conversion is based on an energy equivalency conversion
        method primarily applicable at the burner tip and does not represent
        a value equivalency at the wellhead and as such may be misleading if
        used in isolation.

    (3) Gross reserves relate to the Trust's ownership of reserves before
        royalty interests.

    (4) The reserve life index is calculated by dividing the reserves (in
        BOE's) by the annualized fourth quarter average production rate in
        BOE/d 4,295 (2006 - 4,119)


    RESERVES

    The Trust engaged the services of Sproule Associates Limited to prepare a
reserve evaluation with an effective date of December 31, 2007. The reserves
are located in the Provinces of Alberta and Saskatchewan. The Trust's main oil
producing areas are located in the Pembina area of Alberta and Shaunavon area
of Saskatchewan. The gross reserve figure for the following charts represents
the Trust's ownership interest before royalties and the net figure is after
deductions for royalties.

           SUMMARY OF OIL AND GAS RESERVES AS OF DECEMBER 31, 2007
                         (FORECAST PRICES AND COSTS)

                                              RESERVES

                           Light and           Natural         Natural Gas
                           Medium Oil            Gas             Liquids
                         Gross      Net    Gross      Net    Gross      Net
    RESERVE CATEGORY     (Mbbl)   (Mbbl)   (MMcf)   (MMcf)   (Mbbl)   (Mbbl)
    -------------------------------------------------------------------------
    PROVED
      Developed
       Producing         13,624   12,909   19,863   15,281      844      627
      Developed
       Non-Producing          9        9      907      731        1        1
      Undeveloped         2,808    2,425    3,355    2,215      186      123
    -------------------------------------------------------------------------
    TOTAL PROVED         16,442   15,343   24,125   18,228    1,030      750
    PROBABLE              4,160    3,890    8,340    6,213      278      194
    -------------------------------------------------------------------------
    TOTAL PROVED PLUS
     PROBABLE            20,602   19,233   32,465   24,441    1,308      944
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                   RECONCILIATION OF TRUST GROSS RESERVES
            BY PRINCIPAL PRODUCT TYPE (FORECAST PRICES AND COSTS)

                            Light and Medium
                              Oil and NGL's               Natural Gas

                                           Gross                      Gross
                         Gross    Gross    Proved   Gross    Gross    Proved
                         Proved  Probable   Plus    Proved  Probable   Plus
                         (Mbbl)   (Mbbl)  Probable  (MMcf)   (MMcf)  Probable
                                           (Mbbl)                     (MMcf)
    -------------------------------------------------------------------------
    December 31, 2006    16,758    4,768   21,526   22,562    7,138   29,700
      Extension             719      180      899    1,350     (375)     975
      Improved recovery     147       57      204      295      168      463
      Technical
       revisions          1,473     (411)   1,062    1,066    1,363    2,429
      Discoveries             -        -        -        -        -        -
      Acquisitions          771      260    1,031    1,372      418    1,790
      Dispositions       (1,288)    (357)  (1,645)    (448)    (185)    (633)
      Economic factors      (27)     (59)     (86)     103     (187)     (84)
      Production         (1,081)       -   (1,081)  (2,175)       -   (2,175)
    -------------------------------------------------------------------------
    December 31, 2007    17,472    4,438   21,910   24,125    8,340   32,465
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


             SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
             AS OF DECEMBER 31, 2007 (FORECAST PRICES AND COSTS)

                                   NET PRESENT VALUE OF FUTURE NET REVENUE
                                             Before Income Taxes
                                            Discounted at (%/year)
                                    0        5        10       15       20
    (M$)
    RESERVE CATEGORY
    -------------------------------------------------------------------------
    PROVED
      Developed Producing        834,718  489,936  351,815  279,759  235,358
      Developed Non-Producing      4,009    3,167    2,570    2,131    1,799
      Undeveloped                111,055   88,159   70,872   57,584   47,202
    -------------------------------------------------------------------------
    TOTAL PROVED                 949,782  581,262  425,257  339,474  284,358
    PROBABLE                     323,791  131,693   74,507   49,747   36,262
    -------------------------------------------------------------------------
    TOTAL PROVED PLUS PROBABLE 1,273,573  712,955  499,764  389,222  320,620
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


             SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
             AS OF DECEMBER 31, 2007 (FORECAST PRICES AND COSTS)

                                   NET PRESENT VALUE OF FUTURE NET REVENUE
                                              After Income Taxes
                                            Discounted at (%/year)
                                    0        5        10       15       20
    (M$)
    RESERVE CATEGORY
    -------------------------------------------------------------------------
    PROVED
      Developed Producing        687,026  422,853  313,885  255,463  260,016
      Developed Non-Producing      3,375    2,690    2,204    1,846    1,573
      Undeveloped                 94,416   74,799   60,043   48,718   39,870
    -------------------------------------------------------------------------
    TOTAL PROVED                 784,817  500,341  376,132  306,026  260,016
    PROBABLE                     244,341  100,548   57,632   38,976   28,768
    -------------------------------------------------------------------------
    TOTAL PROVED PLUS PROBABLE 1,029,159  600,889  433,763  345,003  288,784
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Commodity prices used in the above calculations of reserves are as
follows:

    Year        Edmonton    Alberta Gas    Propane       Butane      Pentane
               Par Price     Reference
                               Price
                             Plantgate
                  (Cdn $       (Cdn $       (Cdn $       (Cdn $       (Cdn $
              per barrel)     per MCF)  per barrel)  per barrel)  per barrel)
    -------------------------------------------------------------------------
    2008           88.17         6.19        52.29        65.72        90.30
    2009           84.54         6.94        50.14        63.01        86.58
    2010           83.16         7.46        49.32        61.98        85.17
    2011           81.26         7.50        48.20        60.57        83.23
    2012           80.73         7.41        47.88        60.17        82.68
    2013           81.25         7.58        48.19        60.56        83.21
    2014           82.88         7.76        49.16        61.78        84.88
    2015           84.55         7.94        50.14        63.02        86.59
    2016           86.25         8.12        51.15        64.28        88.33
    2017           87.98         8.31        52.18        65.58        90.10

    Crude oil, natural gas and liquid prices escalate at 2% per year
thereafter.

    The following cautionary statements are specifically required by NI 51-101

    -   It should not be assumed that the estimates of future net revenue
        presented in the above tables represent the fair market value of the
        reserves. There is no assurance that the forecast prices and cost
        assumptions will be attained and variances could be material.
    -   Disclosure provided herein in respect of BOE's may be misleading,
        particularly if used in isolation. In accordance with NI 51-101, a
        BOE conversion ratio of 6mcf:1bbl has been used in all cases in this
        disclosure. This BOE conversion ratio is based on an energy
        equivalency conversion method primarily applicable at the burner tip
        and does not represent a value equivalency at the wellhead.
    -   Estimates of reserves and future net revenues for individual
        properties may not reflect the same confidence level as estimates of
        reserves and future net revenues for all properties due to the
        effects of aggregation.
    

    A DISCUSSION OF FINANCIAL AND OPERATIONAL RESULTS

    Production

    The Trust's 2007 average production of oil and natural gas liquids was
3,113 (2006 - 3,040) barrels per day and natural gas production in 2007
averaged 6,627 (2006 - 6,014) MCF per day. Oil production increased by
approximately 2.5 percent while gas production increased by approximately
10 percent. The increased crude oil production was predominantly due to the
Trust's 2006 and 2007 development programs. Natural gas increase was a
combination of the 2006 development program and the asset swap concluded on
October 30, 2007.
    The Trust's fourth quarter production saw increases in both crude oil and
natural gas production due to commencement of production from new wells
drilled in 2007. Bonterra tied-in 3 gross and net Cardium oil wells and
2 gross and net natural gas wells in December. The Trust also completed an
asset exchange resulting in the disposition of its interest in the Dodsland
area of Saskatchewan for further property interests in the Pembina area of
Alberta. The net result was a slight reduction in volumes on a BOE basis with
Dodsland representing approximately 265 BOE's per day and the acquired
properties producing approximately 250 BOE's. However the newly acquired
properties had an average operating cost per BOE of $12.60 compared to $36.50
for the Dodsland assets offset slightly by larger royalties.
    The Trust's overall annual decline rate for 2007 was approximately nine
percent which the Trust was able to more than offset with its 2007 drill
program. The Trust, along with its partners, drilled 22 gross (15.3 net)
Cardium oil wells. This includes 15 gross and 14.3 net Cardium wells drilled
directly by the Trust. Also the Trust drilled 2 gross (.7 net) shallow gas
wells in 2007. The Trust experienced a 100 percent success rate with its 2007
drilling program.
    As at December 31, 2007 Bonterra had 7 gross (6.3 net) Cardium oil wells,
2 gross (2 net) natural gas wells and 3 gross (2.5 net) coal-bed (CBM) wells
with assigned reserves drilled but not on production. Subsequent to
December 31, 2007 and up to the date of this report, Bonterra has put on
production all of its Cardium oil wells and one shallow gas well. The timing
for the tie-in of the remaining natural gas and CBM wells has not yet been
determined.

    Revenue

    Gross revenue from petroleum and natural gas sales prior to royalties was
$96,431,000 (2006 - $88,734,000). The increase of $7,697,000 was due to
increased production volumes and an increase in the average price received for
crude oil offset partially by a 10.6 percent decline in the average price of
natural gas. The price received for crude oil increased to $70.31 per barrel
in 2007 from $64.69 per barrel in 2006 while natural gas prices decreased to
$6.75 per MCF in 2007 from $7.55 per MCF in 2006.
    The fourth quarter saw a substantial increase in gross revenues of
$2,779,000 over quarter three due to increased production and increased
commodity prices. Production in the fourth quarter averaged 4,295 BOE's per
day compared to 4,088 in the third quarter. Also the average price received in
the fourth quarter for crude oil and natural gas liquids was $77.60 ($73.68
third quarter) per barrel and $6.70 ($5.47 third quarter) per MCF for natural
gas.
    Although the Trust received higher net commodity prices in 2007 than in
2006, increases in the price of U.S. WTI oil prices and U.S. Nymex natural gas
prices were partially offset by the rising Canadian dollar. The negative
impact of the rising Canadian dollar on 2007's cash flow from operations was
approximately 26 cents per unit and approximately 24 cents per unit on net
earnings.
    Included in gross revenue is a realized gain on risk management contracts
of $621,000 (2006 - ($62,000)) due to higher prices received as a result of
price hedging. The Trust also reported an unrealized loss on risk management
contracts of $3,085,000 due to the elimination of hedge accounting effective
October 1, 2007. With the property swap of the Dodsland property the Trust has
reduced its hedging percentage to approximately 25 percent of its anticipated
forward production.
    Commodity price hedges outstanding as of the date of this report are as
follows:

    
                                          Volume
    Period of Agreement    Commodity      per day   Index    Price (Cdn.)
    -------------------    ---------      -------   -----    ------------
    January 1, 2008        Crude Oil  1,000 barrels   WTI   Floor of $73.00
     to June 30, 2008                                        and ceiling of
                                                             $83.00 per
                                                             barrel
    July 1, 2008 to
     December 31, 2008     Crude Oil    500 barrels   WTI   Floor of $73.00
                                                             and ceiling of
                                                             $80.68 per
                                                             barrel
    November 1, 2007
     to March 31, 2008   Natural Gas     2,000 GJ's  AECO   Floor of $6.50
                                                             and ceiling of
                                                             $10.37 per GJ


    Subsequent to December 31, 2007 and up to the date of this report the
Trust has entered into the following commodity hedging transactions:

                                          Volume
    Period of Agreement    Commodity      per day   Index    Price (Cdn.)
    -------------------    ---------      -------   -----    ------------
    July 1, 2008 to
     December 31, 2008     Crude Oil    500 barrels   WTI   Floor of $85.00
                                                             and ceiling of
                                                             $104.80 per
                                                             barrel
    April 1, 2008 to
     October 31, 2008    Natural Gas     1,500 GJ's  AECO   Floor of $6.00
                                                             and ceiling of
                                                             $7.60 per GJ
    

    As at December 31, 2007 the fair value of the outstanding commodity
hedging contracts was a net liability of $3,085,000 (December 31, 2006 - net
asset $1,189,000).

    Royalties

    Royalties paid by the Trust consist primarily of Crown royalties paid to
the Provinces of Alberta and Saskatchewan. During 2007 the Trust paid
$9,209,000 (2006 - $8,156,000) in Crown royalties and $3,235,000 (2006 -
$1,996,000) in freehold royalties, gross overriding royalties and net carried
interests. The majority of the Trust's wells are low productivity wells and
therefore have low Crown royalty rates. The Trust's average Crown royalty rate
is approximately ten percent (2006 - ten percent) and approximately three
percent (2006 - two percent) for other royalties before hedging adjustments.
    During 2007, the Trust was advised by the owner of a gross overriding
royalty that the production limit, resulting in an additional gross overriding
royalty in respect of certain of its Cardium oil wells, had been reached. The
production limit was triggered by a calculation on a multitude of Cardium
wells including many that were not owned by the Trust. In addition the exact
wells that the production limit was applicable to was not readily known by the
Trust nor easily determined. In discussions with the payee it was determined
that the production limit was reached in late 2005. The royalty has been
calculated based on this agreed date and the affected wells for Bonterra and
other operators in the area were identified. The approximate amount of the
adjustment, net to the Trust is $570,000 for periods prior to January 1, 2007,
and this amount has been included in the 2007 royalties figure. The monthly
amount of the royalty on a go forward basis is approximately $55,000 per month
based on current pricing and production levels.
    Also in 2007 the Trust was informed by the operator of its Dodsland
property that it had not been charged a net profit royalty for the years 2004,
2005 and 2006. In review of the agreements it was confirmed no payment was
made and an amount of approximately $150,000 was paid by the Trust for the net
profit royalty. This amount has been included in the 2007 royalty figure.
    Royalty rates in the fourth quarter averaged approximately 13 percent;
slightly higher than preceding quarters. The asset swap of the Dodsland
properties for the Pembina properties resulted in an increase of approximately
one percent in the average royalty rate for the Trust.
    The Trust was eligible for Alberta Crown Royalty rebates for Alberta
production from all wells that it drilled on Crown lands and from a small
number of purchased wells; however this program was discontinued by the
Alberta Government effective January 1, 2007 which resulted in a reduction of
revenue of $500,000 in 2007.

    Production Costs

    Production costs totalled $24,073,000 in 2007 compared to $22,238,000 in
2006. On a barrel of oil equivalent (BOE) basis 2007 operating costs were
$15.64 compared to $15.07 for 2006. BOE's are calculated using a conversion
ratio of 6 MCF to 1 barrel of oil. The conversion is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead and as such may be
misleading if used in isolation. Operating costs on the Trust's newly acquired
Pembina properties from the swap as well as on the newly drilled wells are
significantly lower on a BOE basis than on its Dodsland property and this may
result in lower operating costs per BOE in the future.
    Operating costs were $5,535,000 in the fourth quarter of 2007 compared to
$6,401,000 in the third quarter. The decrease was due primarily to the above
mentioned asset swap which resulted in approximately $375,000 less operating
costs as well as an approximate $300,000 operating cost adjustment related to
previously expensed surface lease payments that pertained to periods
subsequent to the closing date of the asset swap.
    As discussed above, the Trust's production comes primarily from low
productivity wells. These wells generally result in higher operating costs on
a per unit-of-production basis as costs such as municipal taxes, surface
leases, power and personnel costs are not variable with production volumes.
The Trust is continually examining means of reducing operating costs.
    With the asset exchange, the Trust anticipates operating costs in the
$13.50 to $14.50 per BOE range for 2008. The higher operating costs for the
Trust are substantially offset by low royalty rates of approximately
13 percent, which is much lower than industry average for conventional
production and on a combined basis results in high cash net backs despite
higher than average operating costs.

    General and Administrative Expense

    General and administrative expenses were $2,603,000 in 2007 compared to
$2,295,000 in 2006. On a BOE basis, general and administrative expenses in
2007 averaged $1.69 compared to $1.56 per BOE in 2006. The Trust is managed
internally. In addition, the Trust provides administrative services to
Comaplex Minerals Corp. (Comaplex) and Pine Cliff Energy Ltd. (Pine Cliff),
companies that share common directors and management. Please refer to
discussion under Related Party Transactions for details.
    The Trust's only significant general and administrative costs are
employee compensation and professional services such as legal, engineering and
audit. Employee compensation expense increased by approximately 8.5 percent
($252,000). This increase has been partially offset by increased overhead
recoveries charged to operations and capital programs. Costs associated with
professional services increased by approximately $450,000. Of this increase
approximately $340,000 related to the evaluation of several organizational
options. This review was part of the Trust's continuing examination of means
to address the changes resulting from the federal government's taxation of
Trust's announcement on October 31, 2006 and enacted into law in 2007. The
balance of the increase pertained to increased costs associated with producing
the Trust's engineering report as well as fees related to the audit and
continuous disclosure requirements.
    The fourth quarter general and administrative expenses were $34,000 lower
than the third quarter. The decrease was primarily due to the Trust incurring
costs of $275,000 for professional fees in the third quarter for services
discussed above offset partially by an increase in the fourth quarter bonus
amount and increased cost adjustments related to engineering and audit
services.

    Interest Expense

    Interest expense for the 2007 fiscal year of the Trust was $3,028,000
(2006 - $1,610,000). The increase was due to increased loan balances resulting
from the Trust's 2006 and 2007 capital programs. Interest rates during the
year on the outstanding debt averaged approximately 5.9 (2006 - 5.3) percent.
The Trust maintained an average outstanding debt balance of approximately
$51,600,000 (2006 - $31,000,000). Total debt (including negative working
capital) as of December 31, 2007 represents approximately 13.1 months of 2007
annual adjusted distribution base or 11.1 months based on annualized 2007
fourth quarter adjusted distribution base. The ratio of bank debt only as of
December 31, 2007 based on the annualized 2007 Q4 base was 10.9 months.
    The Trust believes that maintaining debt at or less than one year's
adjusted distribution base (calculated quarterly based on annualized quarterly
results) is an appropriate level to allow it to take advantage in the future
of either acquisition opportunities or to provide flexibility to develop its
infill oil, shallow gas and CBM potential without requiring the issuance of
trust units. The Trust's December 31, 2007 debt level including working
capital is slightly below this level.
    The Trust's current bank agreements for the Trust's wholly owned
operating subsidiaries (each of Bonterra Energy Corp (Bonterra Corp.), and
Novitas Energy Ltd. (Novitas) have their own) provide for a combined
$69,900,000 (December 31, 2006 - $49,900,000) of available credit facility.
Bank debt at December 31, 2007 was $57,422,000 (December 31, 2006 -
$45,379,000). The interest rate charged on all non Banker Acceptances (BA's)
facility borrowings is bank prime. The Trust's banking arrangements allow it
to use BA's as part of its loan facility. Interest charges on BA's are
generally one half percent lower than that charged on the general loan
account.

    Unit Option Based Compensation

    Unit option based compensation is a statistically calculated value
representing the estimated expense of issuing employee unit options. The Trust
records a compensation expense over the vesting period based on the fair value
of options granted to employees, directors and consultants.
    In 2007, the Trust issued 553,000 unit options of which 517,000 were
issued at the end of June 2007 at an average price of $28.31 and a fair value
of $2.75 per unit. The fair value of the options granted has been estimated
using the Black-Scholes option pricing model, assuming a weighted risk free
interest rate of 4.7 (2006 - 4.1) percent, expected weighted average
volatility of 27 percent (2006 - 27), expected weighted average life of
2.3 years (2006 - 2.5) and an annual dividend rate based on the distributions
paid to the Unitholders during the year. The future unit based compensation
impact of these options is approximately $250,000 per quarter over the next
four quarters.

    Depletion, Depreciation, Accretion and Dry Hole Costs

    The Trust follows the successful efforts method of accounting for
petroleum and natural gas exploration and development costs. Under this
method, the costs associated with dry holes are charged to operations. For
intangible capital costs that result in the addition of reserves, the Trust
depletes its oil and natural gas intangible assets using the
unit-of-production basis by field.
    For tangible assets such as well equipment, a life span of ten years is
estimated and the related tangible costs are depreciated at one tenth of
original cost per year. The use of a ten year life span instead of calculating
depreciation over the life of reserves was determined to be more
representative of actual costs of tangible property. Given the Trust's long
production life, wells generally require replacement of tangible assets more
than once during their life time. Most of the Trust's wells have been
producing since the 1960's and are expected to continue to produce for at
least another twenty years.
    Provisions are made for asset retirement obligations through the
recognition of the fair value of obligations associated with the retirement of
tangible long-life assets being recorded in the period the asset is put into
use, with a corresponding increase to the carrying amount of the related
asset. The obligations recognized are statutory, contractual or legal
obligations. The liability is adjusted over time for changes in the value of
the liability through accretion charges which are included in depletion,
depreciation and accretion expense. The costs capitalized to the related
assets are amortized to earnings in a manner consistent with the depletion and
depreciation of the underlying asset.
    At December 31, 2007, the estimated total undiscounted amount required to
settle the asset retirement obligations was $54,622,000 (2006 - $46,434,000).
Of the $8,188,000 increase, approximately $2.7 million is due to the asset
swap (the Dodsland property had no asset retirement obligation associated with
it as the Trust had the option of transferring back the title to the wells to
a third party who would then inherit this obligation).
    These obligations will be settled based on the useful lives of the
underlying assets, which extend up to 50 years into the future. This amount
has been discounted using a credit-adjusted risk-free interest rate of five
percent. The discount rate is reviewed annually and adjusted if considered
necessary. A change in the rate would have a significant impact on the amount
recorded for asset retirement obligations. Based on the current provision, a
one percent increase in the risk adjusted rate would decrease the asset
retirement obligation by $2,504,000, while a one percent decrease in the risk
adjusted rate would increase the asset retirement obligation by $3,430,000.
    The above calculation requires an estimation of the amount of the Trust's
petroleum reserves by field. This figure is calculated annually by an
independent engineering firm and is used to calculate depletion. This
calculation is to a large extent subjective. Reserve adjustments are affected
by economic assumptions as well as estimates of petroleum products in place
and methods of recovering those reserves. To the extent reserves are increased
or decreased, depletion costs will vary.
    For the fiscal year ending December 31, 2007, the Trust expensed
$16,675,000 (2006 - $15,393,000) for the above-described items including
$3,078,000 (2006 - $2,919,000) for dry hole costs. During 2007 the Trust wrote
off all costs related to 8 wells drilled during the period 2004-2006 since the
independent third party engineers did not attribute any reserves to them as
well as some 2007 carryover costs related to wells written off in 2006. As of
December 31, 2007 all capitalized costs have been assigned reserves and in the
future any facilities that do not have reserves attributed to them will be
written off.
    The Trust has experienced a significant reduction in finding and
development costs during the current year (see discussion under Finding and
Development Costs) resulting in a marginal decrease in costs per barrel of
reserves. Based on year end reserves, the Trust's average cost of proved
reserves is $5.84 (2006 - $5.95) per BOE.
    The Trust currently has an estimated reserve life for its proved
developed producing reserves of 11.3 (2006 - 11) years calculated using the
Trust's gross reserves (prior to allowance for royalties) based on the third
party engineering report dated December 31, 2007 and using fourth quarter 2007
average production rates of 4,295 BOE's (2006 - 4,119 BOE's). Based on total
proved reserves the Trust has a 13.7 (2006 - 13.6) year reserve life and if
proved and probable are used the reserve life increases to 17.4 (2006 - 17.6)
years. These figures are some of the longest (excluding oil sands) reserve
life indexes in the Trust sector.

    Taxes

    On October 31, 2006, the Canadian Federal Government announced a proposed
Trust taxation pertaining to taxation of distributions paid by publicly traded
income trusts and this was enacted by legislation in June 2007. Previously,
distributions paid to unitholders, other than returns of capital, are claimed
as a deduction by the Trust in arriving at taxable income whereby tax is
eliminated at the Trust level and the tax is paid on the distributions by the
unitholders. The June 2007 legislation results in a two-tiered tax structure
whereby distributions commencing in 2011 would first be subject to a
28 (previously 31.5) percent tax at the Trust level and then investors would
be subject to tax on the distribution as if it were a taxable dividend paid by
a taxable Canadian corporation.
    Future income tax expense for 2007 increased by a one time adjustment of
$4,076,000, with a corresponding increase to the future tax liability as a
result of the June 2007 enactment. Until June 2007, the Trust had been tax
effecting the reversal of taxable temporary differences at a nil tax rate on
the assumption that the Trust would make sufficient tax deductible cash
distributions to unitholders such that the Trust's taxable income would be nil
for the foreseeable future and the tax burden would have continued to be with
whomever received the monthly distribution. The new legislation limits the tax
deductibility of cash distributions such that income taxes may become payable
in the future.
    The Trust has estimated its future income taxes based on its best
estimates of results from operations and tax pool claims and cash
distributions in the future assuming no material change to the Trust's current
organizational structure. As currently interpreted, Canadian Generally
Accepted Accounting Principles ("GAAP") does not permit the Trust's estimate
of future income taxes to incorporate any assumptions related to a change in
organizational structure until such structures are given legal effect even
though it is anticipated that many trusts will change their organizational
structure to attempt to reduce this impact.
    The Trust's estimate of its future income taxes will vary as to the
Trust's assumptions pertaining to the factors described above, and such
variations may be material.
    Until 2011, the new legislation does not directly affect the Trust's cash
flow from operations, and accordingly, the Trust's financial condition.
    Currently taxable income earned within the Trust is required to be
allocated to its Unitholders and as such the Trust will not incur any current
taxes. However, the Trust operates its oil and gas interests through its
100 percent owned subsidiaries Bonterra Energy Corp. ("Bonterra Corp.") and
Novitas Energy Ltd. ("Novitas") and these corporations may periodically be
taxable. These corporations pay the majority of their income to the Trust
through interest and royalty payments which are deductible for income tax
purposes. The current tax provision relates to resource surcharge payable by
the Trust's subsidiaries to the Province of Saskatchewan. The surcharge is
calculated as a flat percent of revenues generated from the sale of petroleum
products produced in Saskatchewan. The provincial government of Saskatchewan
has reduced the current resource surcharge rate of 3.3 percent to 3.1 percent
on July 1, 2007 and to 3.0 percent on July 1, 2008.
    The Trust's subsidiaries have the following tax pools, which may be used
to reduce taxable income in future years, limited to the applicable rates of
utilization:

    
                                                       Rate of
                                                     Utilization
                                                          %         Amount
    -------------------------------------------------------------------------
    Undepreciated capital costs                          20-100  $16,921,000
    Canadian oil and gas property expenditures (COGPE)       10    1,771,000
    Canadian development expenditures (CDE)                  30   30,431,000
    Canadian exploration expenditures (CEE)                 100       93,000
    Income tax losses carried forward(1)                    100   15,056,000
    -------------------------------------------------------------------------
                                                                 $64,272,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Income tax losses carried forward expire in 2014 ($635,000), 2015
        ($3,574,000), 2026 ($4,826,000) and 2027 ($6,021,000).


    The Trust itself has the following tax pools, which may be used in
reducing future taxable income allocated to its Unitholders:

                                                       Rate of
                                                     Utilization
                                                          %         Amount
    -------------------------------------------------------------------------
    COGPE                                                    10  $14,409,000
    Finance costs                                            20      339,000
    Eligible capital expenditures                             7      348,000
    -------------------------------------------------------------------------
                                                                 $15,096,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Canadian tax breakdown of distributions for the 2007 taxation year is
as follows:

                                         Percentage
                                         -----------
    Taxable Income (Other Income)             91.45
    Return of Capital                          8.55
                                         -----------
                                             100.00
                                         -----------
    

    With respect to cash distributions paid during the year to U.S.
individual unitholders, 7.9 percent should be reported as a return of capital
(to the extent of the Unitholder's U.S. tax basis in their respective units)
and 92.1 percent should be reported as qualified dividends.
    During the fourth quarter the Trust reported a future tax recovery of
$133,000 compared to a future tax recovery of $1,110,000 in the third quarter.
The difference of $977,000 relates to the significant increase in the adjusted
distribution base to $15,842,000 (Q3 - $13,149,000) as well as increased
capital spending of $7,213,000 (Q3 - $2,763,000) while only increasing the
Trust's debt level by $828,000. The impact of the above was that the corporate
subsidiaries had to claim maximum CDE and tangible tax pools deductions as
well as reducing their loss carryforwards during the fourth quarter to cover
the additional income left in the subsidiaries.

    Net Earnings

    The Trust's net earnings of $30,350,000 for the year ended December 31,
2007 represents a decrease of $6,990,000 over the Trust's 2006 net earnings of
$37,250,000. The Trust recorded net earnings per unit on a fully diluted basis
in 2007 of $1.79 versus $2.21 in the 2006 year. This represents a return on
Unitholders' equity of approximately 68.6 (2006 - 69.8) percent based on year
end Unitholders' equity.
    The enacting of the trust taxation legislation resulted in a one time
adjustment of $4,076,000 for future income tax expense which is the
predominant reason for the decline in net earnings. Strong crude oil prices
along with a 4.4 percent increase in production volumes were offset with a
10.6 percent decrease in the price of natural gas, increased operating costs
and depletion claims due to higher production volumes and increased interest
costs. The Trust returned in excess of 33 percent of its gross realized
revenues in net earnings. The Trust's low capital costs combined with a low
debt to adjusted distribution base ratio all contribute to the high return.
Bonterra's higher than industry average per unit operating costs are more than
offset with its low royalty rates resulting in one of the highest cash net
backs in the industry (see cash netback).

    Comprehensive Income

    On January 1, 2007 the Trust became obliged to adopt the new accounting
standards regarding the accounting for financial instruments. On adoption the
Trust increased its investment in related party by $1,836,000 for the fair
value of this investment. On January 1, 2007 the Trust further recognized a
current asset of $1,189,000 for the fair value of its commodity derivative
contracts. These adjustments resulted in a further increase in the future
income tax liability and accumulated other comprehensive income of $645,000
and $2,380,000 respectively.
    Other comprehensive income for 2007 included an increase in the
unrealized gain on investment in a related party of $1,465,000 ($295,000 in
the fourth quarter), a reduction of $814,000 relating to the recognition and
transfer of previously reported hedging gains in accumulated other
comprehensive income. Effective October 1, 2007, the Trust discontinued the
use of hedge accounting due to the difficulty in determining the effective
portion of the commodity hedges. All of the above adjustments are net of
applicable income tax effects.

    Standardized Distributable Cash

    Compliance with Guidance

    The following discussion and analysis is in all material respects in
accordance with the recommendations provided in CICA's publication
Standardized Distributable Cash in Income Trusts and Other Flow-Through
Entities: Guidance on Preparation and Disclosure.

    
    Definition and Disclosure of Standardized Distributable Cash

    -------------------------------------------------------------------------
                                                                 Cumulative
                                                                Amounts From
                                                                  Inception
                                                                   of Trust
                                                                   (July 1,
                                   Year Ended     Year Ended       2001 to
                                   December 31,   December 31,   December 31,
                                       2007           2006           2007)
    -------------------------------------------------------------------------
    Cash Flow from Operating
     Activities                   $ 51,433,000   $ 51,944,000   $218,275,000
    -------------------------------------------------------------------------
    Less adjustment for:
    -------------------------------------------------------------------------
      Capital expenditures         (19,300,000)   (37,598,000)   (94,498,000)
    -------------------------------------------------------------------------
      Financing restrictions
       caused by debt                        -              -              -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Standardized
     Distributable Cash           $ 32,133,000   $ 14,346,000   $123,777,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Definition and Disclosure of Adjusted Distribution Base (Formerly Funds
    Flow from Operations)

    -------------------------------------------------------------------------
                                                                 Cumulative
                                                                Amounts From
                                                                  Inception
                                                                   of Trust
                                                                   (July 1,
                                   Year Ended     Year Ended       2001 to
                                   December 31,   December 31,   December 31,
                                       2007           2006           2007)
    -------------------------------------------------------------------------
    Standardized Distributable
     Cash - per above             $ 32,133,000   $ 14,346,000   $123,777,000
    -------------------------------------------------------------------------
    Adjusted for:
    -------------------------------------------------------------------------
      Capital expenditures          19,300,000     37,598,000     94,498,000
    -------------------------------------------------------------------------
      Gain on sale of property               -        532,000      1,089,000
    -------------------------------------------------------------------------
      Changes in accounts
       receivable                    1,082,000        147,000      5,576,000
    -------------------------------------------------------------------------
      Changes in crude oil
       inventory                       (51,000)         7,000        253,000
    -------------------------------------------------------------------------
      Changes in parts inventory        18,000       (107,000)      (190,000)
    -------------------------------------------------------------------------
      Changes in prepaid expenses      244,000        305,000        498,000
    -------------------------------------------------------------------------
      Changes in accounts payable
       and accrued Liabilities         269,000       (793,000)     1,863,000
    -------------------------------------------------------------------------
      Asset retirement
       obligations settled             820,000        762,000      2,529,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Adjusted Distribution Base
     (formerly Funds Flow from
     Operations)(1)               $ 53,815,000   $ 52,797,000   $229,893,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Adjusted distribution base (formerly funds flow from operations) is
        not a recognized measure under GAAP. The Trust believes that in
        addition to net earnings, adjusted distribution base is a useful
        supplemental measure as it demonstrates the Trust's ability to
        generate the cash necessary to make trust distributions, repay debt
        or fund future growth through capital investment. Investors are
        cautioned, however, that this measure should not be construed as an
        indication of the Trust's performance. The Trust's method of
        calculating this measure may differ from other issuers and
        accordingly, it may not be comparable to that used by other issuers.
        For these purposes, the Trust defines adjusted distribution base as
        funds provided by operations before changes in non-cash operating
        working capital items excluding gain on sale of property and asset
        retirement obligations.


    Working Capital Policies

    The Trust, excluding the current portion of debt, maintains a consistent
level of working capital. All items of working capital are generally turned
over every 30 to 60 days. Excluding minor variations due to payment of bonuses
and property taxes there are no reoccurring items that would cause a material
seasonality impact in working capital.

    Analysis of Relationship between Standardized Distributable Cash,
    Distributions, and Investing and Financing Activities

    -------------------------------------------------------------------------
                                   Year ended     Year ended     Year ended
                                   December 31,   December 31,   December 31,
                                       2007           2006           2005
    -------------------------------------------------------------------------
    Standardized
     Distributable Cash           $ 32,133,000   $ 14,346,000   $ 23,413,000
    -------------------------------------------------------------------------
    Distributions                 ($44,648,000)  ($47,281,000)  ($38,949,000)
    -------------------------------------------------------------------------
    Increase in bank debt         $ 12,043,000   $ 25,202,000   $ 11,717,000
    -------------------------------------------------------------------------
    Proceeds on exercise of
     employee unit options        $    993,000   $  5,161,000   $  2,823,000
    -------------------------------------------------------------------------
    Issuance of units
     (net of costs of issue)                 -              -      ($259,000)
    -------------------------------------------------------------------------
    Non cash financing and
     investing working capital
     adjustments                     ($521,000)  $  2,572,000   $  1,255,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The only unfunded operating transaction of the Trust is its asset
retirement obligations. The Trust has the following estimated timing of
expenditures for asset retirement obligations:

                                                    Expected
    Year                                          Expenditure
    ----------------------------------------------------------
    2008                                         $    296,000
    2009                                              517,000
    2010                                              529,000
    2011                                              563,000
    2012                                              856,000
    ----------------------------------------------------------
    ----------------------------------------------------------
                                                 $  2,761,000
    ----------------------------------------------------------
    ----------------------------------------------------------

    Definition and History of Productive Capacity and Strategy

    Bonterra's primary objective is to grow its reserves from which it expects
to generate cash flow so it will be able to continue with distributions for
its unitholders. The Trust defines Productive Capacity Maintenance as the
maintaining of the Trust's proven plus probable reserves. The Trust follows a
policy of internal development as its primary method of planned growth.
Bonterra has a significant inventory of undrilled Cardium oil infill drilling
locations as well as several shallow gas opportunities on its lands or through
farm-in agreements. It is management's view that the calculation of the amount
required for Productive Capacity Maintenance is the amount of reserves
produced in the relevant time period multiplied by the Trust's finding and
development costs for proven plus probable reserves. For this purpose the
Trust believes that the use of a three year average rate is reasonable given
fluctuations in annual costs due to market conditions.

    -------------------------------------------------------------------------
                                   Year Ended     Year ended     Year ended
                                   December 31,   December 31,   December 31,
                                       2007           2006           2005
    -------------------------------------------------------------------------
    Proven and probable
     reserves at beginning of
     period (BOE's)                 26,476,000     23,870,000     19,711,000
    -------------------------------------------------------------------------
    Reserves added due to
     acquisitions (net of
     disposals) (BOE's)               (421,000)        16,000      2,393,000
    -------------------------------------------------------------------------
    Reserves added due to capital
     expenditures (BOE's)            2,806,000      4,082,000      3,100,000
    -------------------------------------------------------------------------
    Production during period
     (BOE's)                         1,540,000      1,476,000      1,334,000
    -------------------------------------------------------------------------
    Increase in productive
     capacity (BOE's)                  845,000      2,622,000      4,159,000
    -------------------------------------------------------------------------
    Reserves per unit (fully
     diluted)                             1.62           1.57           1.46
    -------------------------------------------------------------------------
    Productive capacity
     maintenance requirements     $ 17,043,000   $ 17,472,000   $  9,205,000
    -------------------------------------------------------------------------
    Capital expenditures for
     the period                   $ 19,300,000   $ 38,348,000   $ 56,703,000
    -------------------------------------------------------------------------
    Capital expenditures in
     excess of maintenance
     requirements                 $  2,257,000   $ 20,876,000   $ 47,498,000
    -------------------------------------------------------------------------
    Cost of increased productive
     capacity (per BOE)           $       2.67   $       8.01   $      11.42
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Financing Strategy

    The Trust maintains a strategy of limiting its debt levels to
approximately one year adjusted distribution base. Bonterra has a long term
goal to retain between 20 to 25 percent of its adjusted distribution base to
finance its capital maintenance expenditures. Over the past years, this level
of retention of adjusted distribution base has proven to be sufficient to
maintain the productive capacity of the Trust. To the extent additional
capital expenditures are incurred to increase reserves, the Trust anticipates
financing them through proceeds received on exercise of employee unit options,
equity placements or from its line of credit.
    Periods may exist where the cost of replacing reserves exceed the level
of funds withheld. However, the Trust with its long life reserves and
relatively low debt levels compared to other income trusts has the flexibility
to increase or decrease its capital commitments depending on commodity prices
and costs of development.
    It is management's strategy to finance the costs of reclamation as well
as potential income taxes (commencing in 2011) resulting from the recently
enacted income trust tax law from the adjusted distribution base. Management
is reviewing various organizational alternatives and operational strategies to
mitigate the impact of the new tax.

    Compliance with Financial Covenants

    Due to the relatively low debt levels maintained by the Trust, the
Trust's loan agreements do not contain any debt covenants other than that the
debt is payable upon demand.

    
    Per Unit and Ratio Disclosures

    -------------------------------------------------------------------------
                                                                 Cumulative
                                                                Amounts From
                                                                  Inception
                                                                   of Trust
                                                                   (July 1,
                                   Year Ended     Year Ended       2001 to
                                   December 31,   December 31,   December 31,
                                       2007           2006           2007)
    -------------------------------------------------------------------------
    Standardized
     Distributable Cash           $ 32,133,000   $ 14,346,000   $123,777,000
    -------------------------------------------------------------------------
    Per weighted average unit     $       1.90   $       0.86   $       8.01
    -------------------------------------------------------------------------
    Per fully diluted unit        $       1.90   $       0.85   $       7.96
    -------------------------------------------------------------------------
    Cash distributions            $ 44,648,000   $ 47,281,000   $204,299,000
    -------------------------------------------------------------------------
    Payout ratio                          1.39           3.30           1.65
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Adjusted Distribution Base    $ 53,815,000   $ 52,797,000   $229,893,000
    -------------------------------------------------------------------------
    Per weighted average unit     $       3.18   $       3.15   $      14.93
    -------------------------------------------------------------------------
    Per fully diluted unit        $       3.18   $       3.12   $      14.82
    -------------------------------------------------------------------------
    Cash distributions            $ 44,648,000   $ 47,281,000   $204,299,000
    -------------------------------------------------------------------------
    Payout ratio                          0.83           0.90           0.89
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    On a go forward basis the Trust plans to reduce the payout ratio in
respect of Standardized Distributable Cash to a level between 110 to
120 percent to facilitate a debt to adjusted distribution base level of
approximately one year and to incur no current income tax (excluding
Saskatchewan Resource Surcharge). This will be attained through continued
control of capital replacement costs, by examining lower cost methods of
reserve replacement as well as increased cash flow from wells currently
producing.

    Tax Attributes of Distributions and the Trust's Assets

    See discussion under Income Taxes.

    Cash Netback

    The following table illustrates the Trust's cash netback:

    $ per Barrel of Oil Equivalent (BOE)                  2007          2006
    -------------------------------------------------------------------------
    Production volumes (BOE)                         1,539,461     1,475,639
    -------------------------------------------------------------------------
    Gross production revenue                       $     62.64   $     60.13
    Royalties                                            (8.08)        (7.12)
    Field operating                                     (15.64)       (15.07)
    -------------------------------------------------------------------------
    Field netback                                        38.92         37.94
    General and administrative                           (1.69)        (1.56)
    Interest and taxes                                   (2.30)        (1.34)
    -------------------------------------------------------------------------
    Cash netback                                   $     34.93   $     35.04
    -------------------------------------------------------------------------

    The following table illustrates the Trust's cash netback for the three
months ended:

                                                   December 31   September 30
    $ per Barrel of Oil Equivalent (BOE)               2007          2007
    -------------------------------------------------------------------------
    Production volumes (BOE)                           395,154       375,962
    -------------------------------------------------------------------------
    Gross production revenue                       $     67.25   $     63.29
    Royalties                                            (8.39)        (7.13)
    Field operating                                     (14.01)       (17.02)
    -------------------------------------------------------------------------
    Field netback                                        44.85         39.14
    General and administrative                           (1.87)        (2.06)
    Interest and taxes                                   (2.89)        (2.12)
    -------------------------------------------------------------------------
    Cash netback                                   $     40.09   $     34.96
    -------------------------------------------------------------------------

    Finding and Development Costs (F&D Costs)

    Bonterra has been active in its capital development program over the past
three years. Over this time period the Trust has incurred the following
finding and development costs:

    -------------------------------------------------------------------------
                      2007 F&D   2006 F&D   2005 F&D  2007 Three  2006 Three
                     Costs per  Costs per  Costs per     Year        Year
                      BOE(1)(2)  BOE(1)(2)  BOE(1)(2)   Average     Average
    -------------------------------------------------------------------------
    Proved Reserve
     Additions           $2.74     $25.51     $14.86      $14.37      $15.90
    -------------------------------------------------------------------------
    Proved plus
     Probable Reserve
     Additions           $2.68     $18.21     $12.33      $11.07      $11.84
    -------------------------------------------------------------------------

    The above figures have been calculated in accordance with National
Instrument 51-101 (NI 51-101) where the finding and development costs equate
to the total exploration and development costs incurred by the Trust during
the year plus the yearly change in estimated future development costs as
calculated by Sproule Associates Limited. The following precautionary notes
have been provided as required by NI 51-101.

    (1) BOE's may be misleading, particularly if used in isolation. A BOE
        conversion ratio of 6MCF:1bbl is based on an energy equivalency
        conversion method primarily applicable at the burner tip and does not
        represent a value equivalency at the wellhead.
    (2) 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 reserve additions for that
        year.


    During 2007, Bonterra experienced an approximate 30 percent reduction in
drilling and completion costs. In addition, results from the Trust's Cardium
oil drilling program have been better than anticipated resulting in an
increase in the third party engineering reports estimated recoverable reserves
from existing wells but also from future development. Both these factors
contributed to an overall F&D cost in 2007 of $2.68 per proven and probable
reserve.

    Commitments

    The Trust has no contractual obligations that last more than a year other
than its office lease agreement which is as follows:

    Contract Obligations                 Less than      1 - 3         4 - 5
                              Total        1 year       years         years
    -------------------------------------------------------------------------
    Office lease           $1,658,000     $289,000     $932,000     $437,000
    -------------------------------------------------------------------------
    

    Liquidity and Capital Resources

    During 2007 the Trust participated in drilling 24 gross (16 net) wells at
a total cost of $18,595,000. Included in the above figure is approximately
$7,000,000 of costs associated with the completion and tie-in of wells the
Trust drilled in 2006 and prior years. An additional $1,200,000 was spent in
2008 to complete and tie-in the remaining 2007 drilled wells for an average
cost of $760,000 per well. This compares to over $1.1 million per Cardium well
in 2006.
    As at December 31, 2007 Bonterra had 7 gross (6.3 net) Cardium oil wells,
2 gross (2 net) natural gas wells and 3 gross (2.5 net) CBM wells drilled but
not on production. Subsequent to December 31, 2007 and up to the date of this
report, Bonterra has put on production all the Cardium oil wells and 1 gross
(1 net) shallow gas well. The timing for the eventual tie-in of the remaining
natural gas and CBM wells has not yet been determined.
    The Trust currently has plans to drill 25 gross (20 net) infill Cardium
wells at an estimated budget figure of $800,000 per well. The Trust also plans
on refracing 10 to 15 Cardium wells in 2008 to enhance current production. In
addition, the Trust is currently examining an infill Edmonton Sand natural gas
program. Total capital costs are anticipated to be approximately $20,000,000
for the planned development programs and tying in of the remaining 2007
drilled wells. The Trust anticipates funding the 2008 capital program out of
current cash flow and exercising of employee unit options. This combination
should allow for the Trust to maintain its debt to adjusted distribution base
ratio at less than one.

    Taxation of Trusts

    In June, 2007 the October 31, 2006 proposals by the Minster of Finance
for Canada for the taxation of existing income trusts were proclaimed into
law. In summary the law provides that:

    
    -   An income trust will be subject to a special rate of tax on its
        distributions of income that is attributable to income from business
        carried on in Canada, income from non-portfolio investments in
        Canadian resource properties, and capital gains from the above.
    -   Distributions from income trusts will be taxed in the same manner as
        a dividend from a taxable Canadian corporation.
    -   For existing trusts the new rules apply to taxation years that end
        after 2010.
    -   The tax rate that would apply to taxation years after 2010 would be
        31.5 percent. In October of 2007 the Minister of Finance announced a
        reduction in this rate to 29.5 percent for 2011 and 28 percent
        thereafter.
    

    In addition the Minister announced in October 2006 the government's
attempt to limit the growth of existing income trusts. According to the
announcement, the government will not recommend any change to the 2011 date in
respect of any income trust whose equity capital grows as a result of
issuances of new equity, in any of the years from October 31, 2006 to
December 31, 2010 by an amount that does not exceed the greater of $50 million
and an objective "safe harbour" amount. The safe harbour amount is measured by
reference to the trust's market capitalization as of the end of trading on
October 31, 2006. Market capitalization is to be measured in terms of the
value of an income trust's issued and outstanding publicly-traded units and
its bank debt. For the period November 1, 2006 to December 31, 2007 an income
trust's safe harbour will be 40 percent of that October benchmark and
20 percent for each calendar year 2008, 2009 and 2010. The Minister also
announced in October 2006 the government's intent to allow for conversions of
income trusts back to corporate form as well as to allow the mergers of income
trusts without effecting the above safe harbour amounts. None of the rules
surrounding the safe harbour and conversion to a corporate form have been
legislated.
    The impact to individual unitholders of the above legislative changes
differs by the category of the investor. For Canadian individual or Canadian
taxable corporation investors the distributions will be subject to the
dividend tax credit which should offset to a large degree the tax paid by the
Trust. For those investors that hold their trust units in a tax deferred fund
(RRSP's, RRIF's or in a pension fund) there will be double taxation of
distributions. This will result in an effective rate of tax in most cases in
excess of 50 percent, twenty nine and a half percent (Twenty eight percent in
2012 and thereafter) at the trust level and a further tax on withdrawal from
the fund based on the individual's tax rate. Also for non-resident investors
there will be a significant double taxation as well. The trust again pays its
taxes, then generally a further 15 percent withholding is required and the
non-residents must also pay their own taxes in their country of residence.
This could result in excess of 55 percent being paid in taxes.
    The Trust's management along with its professional advisors have been
examining various options available to it to in respect of its long term
strategic planning. The process continues to be complicated by the fact that
significant proposals of the Minister's October 2006 announcement have not yet
been legislative. In addition, the Trust has a diverse ownership base with
approximately 24.8 percent of outstanding units held by non-residents as of
January 2, 2008 (based on ADP Canada and ADP USA beneficial reports) and an
estimated 15 percent held by deferred income plans with the rest held by
taxable Canadian investors.
    In the mean time the proposed safe harbour rules will allow Bonterra to
raise in excess of $650,000,000 over the next three years without losing its
tax free status before 2011. This will allow the trust to continue with its
Cardium infill drilling program, its shallow natural gas and CBM development
as well as potentially developing a CO(2) flood program or to make corporate
or property acquisitions. The current emphasis will be placed on increasing
the Trust's available tax pools to assist in dealing with the future tax
consequences resulting from the taxation of trust legislation.

    
    Sensitivity Analysis

    Sensitivity analysis, as estimated for 2008:

                                                                  Cash Flow
                                                    Cash Flow      Per Unit
                                                    ---------      --------

    U.S. $1.00 per barrel                            $958,000       $0.056
    Canadian $0.10 per MCF                           $213,000       $0.013
    Change of Canadian $0.01/U.S. $ exchange rate    $692,000       $0.041
    

    Forward-Looking Information

    Certain information set forth in this document, including management's
assessment of Bonterra Energy Income Trust's ("the Trust" or "Bonterra")
future plans and operations, contains forward-looking statements. By their
nature, forward-looking statements are subject to numerous risks and
uncertainties, some of which are beyond Bonterra's control, including the
impact of general economic conditions, industry conditions, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other industry participants, the lack of
availability of qualified personnel or management, stock market volatility and
ability to access sufficient capital from internal and external sources.
Readers are cautioned that the assumptions used in the preparation of such
information, although considered reasonable at the time of preparation, may
prove to be imprecise and, as such, undue reliance should not be placed on
forward-looking statements. Bonterra's actual results, performance or
achievement could differ materially from those expressed in, or implied by
these forward-looking statements, and, accordingly, no assurance can be given
that any of the events anticipated by the forward-looking statements will
transpire or occur, or if any of them do so, what benefits that Bonterra will
derive therefrom. Bonterra disclaims any intention or obligation to update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise. Readers are cautioned that net present value of
reserves does not represent fair market value of reserves.


    
    Bonterra Energy Income Trust

    Consolidated Balance Sheets

    As at December 31                                    2007           2006

    Assets
    Current
      Accounts receivable (Note 9)               $ 10,575,000   $ 10,486,000
      Crude oil inventory                             792,000        843,000
      Parts inventory                                 132,000        114,000
      Prepaid expenses                              1,330,000      1,086,000
      Future income tax asset (Note 5)                913,000              -
      Investment in related party (Note 2)          4,014,000        461,000
    -------------------------------------------------------------------------
                                                   17,756,000     12,990,000
    -------------------------------------------------------------------------
    Property and Equipment (Note 3)
      Petroleum and natural gas properties
       and related equipment                      187,288,000    176,602,000
      Accumulated depletion and depreciation      (61,805,000)   (54,650,000)
    -------------------------------------------------------------------------
                                                  125,483,000    121,952,000
    -------------------------------------------------------------------------
                                                 $143,239,000   $134,942,000
    -------------------------------------------------------------------------
    Liabilities
    Current
      Distribution payable                       $  3,724,000   $  4,050,000
      Accounts payable and accrued liabilities     12,291,000     13,748,000
      Derivative liability (Note 11)                3,085,000              -
      Debt (Note 4)                                57,422,000     45,379,000
    -------------------------------------------------------------------------
                                                   76,522,000     63,177,000
    Future income tax liability (Note 5)            7,595,000      3,587,000
    Asset retirement obligations (Note 6)          14,904,000     14,819,000
    -------------------------------------------------------------------------
                                                   99,021,000     81,583,000
    -------------------------------------------------------------------------
    Commitments, Contingencies and Guarantees
     (Note 11)
    Unitholders' Equity (Note 7)
      Unit capital                                 90,590,000     89,488,000
      Contributed surplus                           2,140,000      1,116,000
    -------------------------------------------------------------------------
                                                   92,730,000     90,604,000
    -------------------------------------------------------------------------
      Deficit                                     (51,543,000)   (37,245,000)
      Accumulated other comprehensive
       income (Note 8)                              3,031,000              -
    -------------------------------------------------------------------------
                                                  (48,512,000)   (37,245,000)
    -------------------------------------------------------------------------
    Total Unitholders' Equity                      44,218,000     53,359,000
    -------------------------------------------------------------------------
                                                 $143,239,000   $134,942,000
    -------------------------------------------------------------------------



    Bonterra Energy Income Trust

    Consolidated Statements of Unitholders' Equity

    For the Years Ended December 31                      2007           2006

    Unitholders' equity, beginning of year       $ 53,359,000   $ 57,322,000
    Comprehensive income for the year              31,001,000     37,250,000
    Adjustment of opening accumulated other
     comprehensive income (Note 1)                  2,380,000              -
    Net capital contributions (Note 7)                993,000      5,161,000
    Unit option based compensation adjustment       1,133,000        907,000
    Distributions declared                        (44,648,000)   (47,281,000)
    -------------------------------------------------------------------------
    Unitholders' Equity, End of Year             $ 44,218,000   $ 53,359,000
    -------------------------------------------------------------------------



    Bonterra Energy Income Trust

    Consolidated Statements of Operations
     and Deficit

    For the Years Ended December 31                      2007           2006

    Revenue
      Oil and gas sales                          $ 95,810,000   $ 88,796,000
      Realized gain (loss) on risk
       management contracts                           621,000        (62,000)
      Unrealized loss on risk management
       contracts (Notes 8 and 11)                  (3,085,000)             -
      Royalties                                   (12,444,000)   (10,512,000)
      Alberta royalty tax credit                            -        487,000
      Gain on sale of property (Note 3)                     -        532,000
      Interest and other                               44,000         66,000
    -------------------------------------------------------------------------
                                                   80,946,000     79,307,000
    -------------------------------------------------------------------------
    Expenses
      Production costs                             24,073,000     22,238,000
      General and administrative                    2,603,000      2,295,000
      Interest on debt                              3,028,000      1,610,000
      Unit option based compensation                1,133,000        907,000
      Dry hole costs                                3,078,000      2,919,000
      Depletion, depreciation and accretion        13,597,000     12,474,000
    -------------------------------------------------------------------------
                                                   47,512,000     42,443,000
    -------------------------------------------------------------------------
    Earnings Before Income Taxes                   33,434,000     36,864,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Income taxes (recovery) (Note 5)
      Current                                         512,000        367,000
      Future                                        2,572,000       (753,000)
    -------------------------------------------------------------------------
                                                    3,084,000       (386,000)
    -------------------------------------------------------------------------
    Net Earnings for the Year                      30,350,000     37,250,000
    Deficit, beginning of year                    (37,245,000)   (27,214,000)
    Distributions declared                        (44,648,000)   (47,281,000)
    -------------------------------------------------------------------------
    Deficit, end of year                         ($51,543,000)  ($37,245,000)
    -------------------------------------------------------------------------
    Net Earnings Per Trust Unit
     - Basic (Note 7)                            $       1.79   $       2.23
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Earnings Per Trust Unit
     - Diluted (Note 7)                          $       1.79   $       2.21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Bonterra Energy Income Trust

    Consolidated Statement of Comprehensive Income (Note 1)

    For the Year Ended December 31                                      2007

    Net Earnings for the Period                                 $ 30,350,000
    -------------------------------------------------------------------------
    Other comprehensive income, net of income tax
      Unrealized gains on investments
       (net of income taxes of $252,000)                           1,465,000
      Gains and losses on derivatives designated as
       cash flow hedges transferred to net earnings
       (net of income taxes of ($334,000))                          (814,000)
    -------------------------------------------------------------------------
    Other Comprehensive Income                                       651,000
    -------------------------------------------------------------------------
    Comprehensive Income                                        $ 31,001,000
    -------------------------------------------------------------------------
    Comprehensive Income Per Trust Unit - Basic (Note 7)        $       1.83
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Comprehensive Income Per Trust Unit - Diluted (Note 7)      $       1.83
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Bonterra Energy Income Trust

    Consolidated Statements of Cash Flow

    For the Years Ended December 31                      2007           2006

    Operating Activities
      Net earnings for the year                  $ 30,350,000   $ 37,250,000
      Items not affecting cash
        Gain on sale of property                            -       (532,000)
        Unrealized loss on risk management
         contracts                                  3,085,000              -
        Unit option based compensation              1,133,000        907,000
        Dry hole costs                              3,078,000      2,919,000
        Depletion, depreciation and accretion      13,597,000     12,474,000
        Future income taxes (recovery)              2,572,000       (753,000)
    -------------------------------------------------------------------------
                                                   53,815,000     52,265,000
    -------------------------------------------------------------------------
      Change in non-cash working capital
        Accounts receivable                        (1,082,000)      (147,000)
        Crude oil inventory                            51,000         (7,000)
        Parts inventory                               (18,000)       107,000
        Prepaid expenses                             (244,000)      (305,000)
        Accounts payable and accrued liabilities     (269,000)       793,000
      Asset retirement obligations settled           (820,000)      (762,000)
    -------------------------------------------------------------------------
                                                   (2,382,000)      (321,000)
    -------------------------------------------------------------------------
                                                   51,433,000     51,944,000
    -------------------------------------------------------------------------
    Financing Activities
      Increase in debt                             12,043,000     25,202,000
      Unit option proceeds                            993,000      5,161,000
      Unit distributions                          (44,974,000)   (46,869,000)
    -------------------------------------------------------------------------
                                                  (31,938,000)   (16,506,000)
    -------------------------------------------------------------------------
    Investing Activities
      Property and equipment expenditures         (19,300,000)   (38,348,000)
      Proceeds on sale of property                          -        750,000
      Change in non-cash working capital
        Accounts receivable                           993,000        681,000
        Accounts payable and accrued liabilities   (1,188,000)     1,479,000
    -------------------------------------------------------------------------
                                                  (19,495,000)   (35,438,000)
    -------------------------------------------------------------------------
    Net cash inflow                                         -              -
    Cash, beginning of year                                 -              -
    -------------------------------------------------------------------------
    Cash, End of Year                            $          -   $          -
    -------------------------------------------------------------------------
    Cash Interest Paid                           $  3,028,000   $  1,610,000
    Cash Taxes Paid                              $    292,000   $    393,000



    Bonterra Energy Income Trust

    Notes to the Consolidated Financial Statements

    For the Years Ended December 31, 2007 and 2006

    1.  SIGNIFICANT ACCOUNTING POLICIES

    Basis of Presentation

    The consolidated financial statements have been prepared by management in
    accordance with Canadian generally accepted accounting principles
    ("GAAP") as described below.

    Consolidation

    These consolidated financial statements include the accounts of Bonterra
    Energy Income Trust (the "Trust") and its wholly owned subsidiaries
    Bonterra Energy Corp. (Bonterra) and Novitas Energy Ltd. (Novitas).

    Measurement Uncertainty

    The preparation of financial statements requires management to make
    estimates and assumptions that affect the reported amounts of assets and
    liabilities and disclosure of contingent assets and liabilities at the
    date of the financial statements and revenues and expenses during the
    reporting period. Actual results can differ from those estimates.

    In particular, amounts recorded for depreciation and depletion and
    amounts used in ceiling test calculations are based on estimates of
    petroleum and natural gas reserves and future costs required to develop
    those reserves. The Trust's reserve estimates are evaluated annually by
    an independent engineering firm. By their nature, these estimates of
    reserves and the related future cash flows are subject to measurement
    uncertainty, and the impact on the consolidated financial statements of
    future periods could be material.

    The amounts recorded for asset retirement obligations were estimated
    based on the Trust's net ownership interest in all wells and facilities,
    estimated costs to abandon and reclaim the wells and facilities and the
    estimated period during which these costs will be incurred in the future.
    Any changes to these estimates could change the amount recorded for asset
    retirement obligations and may materially impact the financial statements
    of future periods.

    Financial instruments - recognition and measurement

    On January 1, 2007, the Trust adopted Section 3855 of the Canadian
    Institute of Chartered Accountants ("CICA") Handbook, "Financial
    Instruments - Recognition and Measurement" and Section 3861 "Financial
    Instruments - Disclosure and Presentation". These set out the standards
    for recognizing and measuring financial instruments in the balance sheet
    and the standards for reporting gains and losses in the financial
    statements. Financial assets available for sale, assets and liabilities
    held for trading and derivative financial instruments, whether part of a
    hedging relationship or not, have to be measured at fair value.

    The Trust has made the following classifications:

    -   Investment in related party is classified as available for sale and
        recorded at fair value which is marked-to-market through
        comprehensive income.

    -   Accounts receivable are classified as loans and receivables and are
        recorded at amortized cost using the effective interest method. Gains
        and losses are recognized in net earnings when the asset is no longer
        recognized.

    -   Accounts payable and accrued liabilities and bank debt are classified
        as other liabilities and are recorded at amortized cost using the
        effective interest method. Gains and losses are recognized in net
        earnings when the liability is no longer recognized.

    The adoption of the Sections is done retrospectively without restatement
    of the consolidated financial statements of prior periods. As at
    January 1, 2007, the impact on the consolidated balance sheet of
    measuring the investment in related party at fair value was an increase
    of $1,836,000 to investment in a related party, an increase in future
    income tax liability of $270,000 and an increase in accumulated other
    comprehensive income of $1,566,000.

    The impact on the consolidated balance sheet of measuring hedging
    derivatives at fair value at January 1, 2007 was an increase in other
    assets of $1,189,000, an increase in future tax liability of $375,000 and
    an increase in accumulated other comprehensive income of $814,000. As of
    October 1, 2007, the Trust discontinued the used of hedge accounting (see
    Note 8).

    The Trust selected January 1, 2003 as its transition date for embedded
    derivatives. An embedded derivative is a component of a financial
    instrument or another contract the characteristics of which are similar
    to a derivative. This had no impact on the consolidated financial
    statements.

    Comprehensive income

    On January 1, 2007, the Trust adopted Section 1530 of the CICA Handbook,
    "Comprehensive Income". This section describes reporting and disclosure
    recommendations with respect to comprehensive income and its components.
    Comprehensive income is the change in unitholders' equity, which results
    from transactions and events from sources other than the Trust's
    unitholders and consists of net income and other comprehensive income
    ("OCI"). OCI comprises revenues, expenses, gains and losses that are
    recognized in comprehensive income but excluded from net income. Such
    items include unrealized gains and losses from changes in fair value of
    certain financial instruments.

    The adoption of this section results in the Trust presenting a
    consolidated statement of comprehensive income as a part of the
    consolidated financial statements.

    Equity

    On January 1, 2007, the Trust adopted Section 3251 of the CICA Handbook
    "Equity" replacing Section 3250 "Surplus". This section describes
    standards for the presentation of equity and changes in equity for
    reporting periods as a result of the application of Section 1530
    "Comprehensive Income".

    Hedges

    On January 1, 2007, the Trust adopted Section 3865 of the CICA Handbook
    "Hedges". The recommendations of this Section expand the guidelines
    required by Accounting Guideline 13 (AcG-13), Hedging Relationships. This
    section describes when and how hedge accounting can be applied as well as
    the disclosure requirements. Hedge accounting enables the recording of
    gains, losses, revenues and expenses from the derivative financial
    instrument in the same period as those related to the hedged item.

    Derivative financial instruments are utilized to reduce commodity price
    risk on the Trust's product sales. The Trust does not enter into
    financial instruments for trading or speculative purposes.

    The Trust's policy is to formally designate each derivative financial
    instrument as a hedge of a specifically identified product sale. The
    Trust assesses the derivative financial instruments for effectiveness as
    hedges, both at inception and over the term of the instrument. The
    production volume in the derivative financial instruments all match the
    production being hedged.

    Commodity price swap agreements are used as part of the Trust's program
    to manage its product pricing. The commodity price swap agreements
    involve the periodic exchange of payments and are recorded as adjustments
    of net revenue.

    Accounting changes

    The Trust also adopted Section 1506, "Accounting Changes," whereby the
    only impact is to provide disclosure of when an entity has not applied a
    new source of GAAP that has been issued but is not yet effective. This is
    the case with Section 1535, "Capital Disclosures", Section 3862,
    "Financial Instruments Disclosures" and Section 3863, "Financial
    Instruments - Presentation" which are required to be adopted for fiscal
    years beginning on or after October 1, 2007. The Trust will adopt these
    standards on January 1, 2008 and it is expected that the only effect on
    the Trust will be incremental disclosures regarding the Trust's
    objectives, policies and processes for managing capital and the
    significance of financial instruments for the entity's financial position
    and performance; and the nature, extent and management of risks arising
    from financial instruments to which the entity is exposed.

    In February 2008, the CICA issued Section 3064, "Goodwill and Intangible
    Assets", replacing Section 3062, "Goodwill and Other Intangible Assets"
    and Section 3450, "Research and Development Costs". Various changes have
    been made to other sections of the CICA Handbook for consistency
    purposes. The new section will be applicable to financial statements
    relating to fiscal years beginning on or after October 1, 2008.
    Accordingly, the Trust will adopt the new standards for its fiscal year
    beginning January 1, 2009. This standard establishes standards for the
    recognition, measurement, presentation and disclosure of goodwill
    subsequent to its initial recognition and of intangible assets by profit-
    oriented enterprises. Standards concerning goodwill are unchanged from
    the standards included in the previous Section 3062. The Trust is
    currently evaluating the impact of the adoption of this new Section on
    its consolidated financial statements. The Trust does not expect that the
    adoption of this new Section will have a material impact on its
    consolidated financial statements.

    Inventories

    Inventories consist of crude oil as well as materials and supplies which
    include tubing, rods, motors, pump jacks, bases and miscellaneous parts
    used in the maintenance of the Trust's tangible equipment. Both crude oil
    and materials and supplies are valued at the lower of cost or net
    realizable value. Inventory cost for crude oil is determined based on
    combined average per barrel operating costs, royalties and depletion and
    depreciation for the year and net realizable value is determined based on
    sales price in the month preceding year end.

    Investments

    Investments are carried at fair value. In 2006 the investments were
    recorded at lower of cost and market value.

    Property and Equipment

    Petroleum and Natural Gas Properties and Related Equipment

    The Trust follows the successful efforts method of accounting for
    petroleum and natural gas properties and related equipment. Costs of
    exploratory wells are initially capitalized pending determination of
    proved reserves. Costs of wells which are assigned proved reserves remain
    capitalized, while costs of unsuccessful wells are charged to earnings.
    All other exploration costs including geological and geophysical costs
    are charged to earnings as incurred. Development costs, including the
    cost of all wells, are capitalized.

    Producing properties and significant unproved properties are assessed
    annually or more frequently as economic events dictate, for potential
    impairment. Impairment is assessed by comparing the estimated net
    undiscounted future cash flows to the carrying value of the asset. If
    required, the impairment recorded is the amount by which the carrying
    value of the asset exceeds its fair value.

    Depreciation and depletion of capitalized costs of oil and gas producing
    properties are calculated using the unit of production method.
    Development and exploration drilling and equipment costs are depleted
    over the remaining proved developed reserves. Depreciation of other plant
    and equipment is provided on the straight line method. Straight line
    depreciation is based on the estimated service lives of the related
    assets which is estimated to be ten years.

    Furniture, Fixtures and Office Equipment

    These assets are recorded at cost and depreciated over a three to
    ten year period representing their estimated useful lives.

    Income Taxes

    Income taxes are calculated using the liability method of accounting for
    income taxes. Under this method, income tax liabilities and assets are
    recognized for the estimated tax consequences attributable to differences
    between the amounts reported for assets and liabilities by the Trust and
    its subsidiary companies in the consolidated financial statements of the
    Trust and their respective tax bases, using enacted or substantively
    enacted income tax rates. The effect of a change in income tax rates on
    future income tax liabilities and assets is recognized in income in the
    period in which the change occurs.

    In the Trust structure, payments are made between the Trust's operating
    subsidiaries and the Trust which result in the transferring of taxable
    income from the operating subsidiaries to individual Unitholders. These
    payments may reduce future income tax liabilities previously recorded by
    the operating companies which would be recognized as a recovery of income
    tax in the period incurred.

    Asset Retirement Obligations

    The fair value of obligations associated with the retirement of long-life
    assets are recorded in the period the asset is put into use, with a
    corresponding increase to the carrying amount of the related asset. The
    obligations recognized are statutory, contractual or legal obligations.
    The liability is adjusted over time for changes in the value of the
    liability through accretion charges which are included in depletion,
    depreciation and accretion expense. The costs capitalized to the related
    assets are amortized to earnings in a manner consistent with the
    depletion and depreciation of the underlying asset.

    Trust Unit Option Based Compensation

    The Trust has a unit option based compensation plan, which is described
    in Note 7. The Trust records a compensation expense over the vesting
    period based on the fair value of options granted to employees, directors
    and consultants. These amounts are recorded as contributed surplus. Any
    consideration paid by employees, directors or consultants on the exercise
    of these options is recorded as unit capital together with the related
    contributed surplus associated with the exercised options.

    Revenue Recognition

    Revenues associated with sales of petroleum and natural gas are recorded
    when title passes to the customer.

    Joint Interest Operations

    Significant portions of the Trust's oil and gas operations are conducted
    with other parties and accordingly the financial statements reflect only
    the Trust's proportionate interest in such activities.

    Net Earnings Per Unit

    Basic earnings per unit are computed by dividing earnings by the weighted
    average number of units outstanding during the year. Diluted per unit
    amounts reflect the potential dilution that could occur if options to
    purchase trust units were exercised. The treasury stock method is used to
    determine the dilutive effect of trust unit options, whereby proceeds
    from the exercise of trust unit options or other dilutive instruments are
    assumed to be used to purchase trust units at the average market price
    during the period.

    2.  INVESTMENT IN RELATED PARTY

    The investment consists of 689,682 (December 31, 2006 - 689,682) common
    shares in Comaplex Minerals Corp (Comaplex), a company with common
    directors and management with the Trust and its subsidiaries. The
    investment is recorded at fair market value (December 31, 2006 -
    $2,297,000). The common shares trade on the Toronto Stock Exchange under
    the symbol CMF. The investment represents less than a one and a half
    percent ownership in the outstanding shares of Comaplex.

    3.  PROPERTY AND EQUIPMENT

                                 2007                        2006
    -------------------------------------------------------------------------
                                     Accumulated                 Accumulated
                                   Depletion and               Depletion and
                              Cost  Depreciation          Cost  Depreciation
    -------------------------------------------------------------------------
    Undeveloped land  $    316,000  $          -  $    334,000  $          -
    Petroleum and
     natural gas
     properties and
     related
     equipment         185,947,000    61,105,000   175,353,000    54,008,000
    Furniture,
     equipment and
     other               1,025,000       700,000       915,000       642,000
    -------------------------------------------------------------------------
                      $187,288,000  $ 61,805,000  $176,602,000  $ 54,650,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    In January 2006 the Trust completed the sale of a non-operated oil and
    gas property for gross proceeds of $750,000 to an unrelated third party.
    The disposition resulted in the Trust reporting a gain on sale of
    $532,000.

    4.  DEBT

    The Trust has a bank revolving credit facility of $69,900,000 at
    December 31, 2007 (2006 - $49,900,000). The terms of the credit facility
    provide that the loan is due on demand and is subject to annual review.
    The credit facility has no fixed payment requirements. The amount
    available for borrowing under the credit facility is reduced by
    outstanding letters of credit. Letters of credit totalling $340,000
    (December 31, 2006 - $340,000) were issued at December 31, 2007. Security
    for the credit facility consists of various fixed and floating demand
    debentures totalling $79,000,000 over all of the Trust's assets, and a
    general security agreement with first ranking over all personal and real
    property.

    The credit facility carries an interest rate of Canadian chartered bank
    prime. The Trust has classified this debt as a current liability as
    required by GAAP. It has been management's experience that these types of
    demand loans which are required to be classified as a current liability
    are seldom called by principal bankers as long as all the terms and
    conditions of the loan are complied with. Cash interest paid during the
    year ended December 31, 2007 for this loan was $3,021,000 (2006 -
    $1,610,000).

    5.  TAXES

    The Trust has recorded a future income tax liability and a current future
    income tax asset related to assets and liabilities and related tax
    amounts. The following 2007 figures reflect the consequences of the
    Canadian Federal Government's October 31, 2006 announcement on the future
    taxation of Income Trusts and the enactment of those proposals in 2007:

                                                      2007           2006
    -------------------------------------------------------------------------
    Future income tax liability related to
     assets and liabilities:                     $ 11,517,000   $  6,233,000
    Future tax asset related to finance costs:        (79,000)             -
    Future tax asset related to corporate tax
     losses carried forward in the
     subsidiary companies                          (3,843,000)    (2,646,000)
    -------------------------------------------------------------------------
    Future income tax liability                  $  7,595,000   $  3,587,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Future income tax asset related to current
     portion of derivative liability             $    913,000   $          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Income tax expense varies from the amounts that would be computed by
    applying Canadian federal and provincial income tax rates as follows and
    the federal government's rate reduction enacted in December 2007:

                                                      2007           2006
    -------------------------------------------------------------------------
    Earnings before taxes                        $ 33,434,000   $ 36,864,000
    Combined federal and provincial
     income tax rates                                  32.27%         34.97%
    -------------------------------------------------------------------------
    Income tax provision calculated using
     statutory tax rates                           10,789,000     12,891,000
    Increase (decrease) in taxes resulting from:
      Saskatchewan resource surcharge                 512,000        367,000
      Unit-based compensation                         366,000        317,000
      Non-deductible crown royalties                        -      1,072,000
      Resource allowance                                    -     (1,901,000)
      Change in effective tax rate of the Trust     4,076,000              -
      Trust income allocated to Unitholders       (13,176,000)   (13,031,000)
      Others                                          517,000       (123,000)
    -------------------------------------------------------------------------
    Income tax expense (recovery)                $  3,084,000   $   (386,000)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Trust's subsidiaries have the following tax pools, which may be used
    to reduce taxable income in future years, limited to the applicable rates
    of utilization:

                                                       Rate of
                                                     Utilization
                                                          %         Amount
    -------------------------------------------------------------------------
    Undepreciated capital costs                          20-100  $16,921,000
    Canadian oil and gas property expenditures               10    1,771,000
    Canadian development expenditures                        30   30,431,000
    Canadian exploration expenditures                       100       93,000
    Income tax losses carried forward(1)                    100   15,056,000
    -------------------------------------------------------------------------
                                                                 $64,272,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Income tax losses carried forward expire in 2014 ($635,000), 2015
        ($3,574,000), 2026 ($4,826,000) and 2027 ($6,021,000).

    The Trust has the following tax pools, which may be used in reducing
    future taxable income allocated to its Unitholders:

                                                       Rate of
                                                     Utilization
                                                          %         Amount
    -------------------------------------------------------------------------
    Canadian oil and gas property expenditures               10  $14,409,000
    Finance costs                                            20      339,000
    Eligible capital expenditures                             7      348,000
    -------------------------------------------------------------------------
                                                                 $15,096,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    On October 31, 2006, the Canadian Federal Government announced a proposed
    Trust taxation pertaining to taxation of distributions paid by publicly
    traded income trusts and this was enacted by legislation in June, 2007.
    Previously, distributions paid to unitholders, other than returns of
    capital, were claimed as a deduction by the Trust in arriving at taxable
    income whereby tax is eliminated at the Trust level and tax is paid on
    the distributions by the unitholders. The June, 2007 legislation results
    in a two-tiered tax structure whereby distributions commencing in 2011
    would first be subject to a 31.5 percent tax at the Trust level and then
    investors would be subject to tax on the distribution as if it were a
    taxable dividend paid by a taxable Canadian corporation. The tax rate was
    subsequently lowered to 29.5 percent in 2011 and 28 percent in 2012 and
    thereafter.

    Prior to June 2007, the Trust estimated the future income tax on certain
    temporary differences between amounts recorded on its balance sheet for
    book and tax purposes at a nil effective tax rate. The entire balance of
    the future income tax liability reported related to assets and
    liabilities and related tax amounts held through the Trust's 100 percent
    held subsidiaries. Under the legislation, the Trust now estimates the
    effective tax rate on post-2010 reversal of these temporary differences
    at the above mentioned tax rates. Temporary differences at the Trust
    level reversing before 2011 will still give rise to nil future income
    taxes.

    Based on its assets and liabilities as at December 31, 2007, the Trust
    has estimated the amount of its temporary differences which were
    previously not subject to tax and estimated the periods in which these
    differences will reverse. The Trust estimates that $14,496,000 net
    taxable temporary differences will reverse after January 1, 2011,
    resulting in an additional $4,076,000 future income tax liability. The
    taxable temporary differences relate principally to the excess of net
    book value of oil and gas properties over the remaining tax pools
    attributable thereto.

    As the legislation gives rise to a change in the Trust's estimated future
    income tax liability in the period, the recognition of the additional
    liability is accounted for prospectively in the period and an additional
    $4,076,000 of future income tax expense has been recorded for the period.

    While the Trust believes it will be subject to additional tax under the
    new legislation, the estimated effective tax rate on temporary difference
    reversals after 2011 may change in future periods. As the legislation is
    new, future technical interpretations of the legislation could occur and
    could materially affect management's estimate of the future income tax
    liability.

    The amount and timing of reversals of temporary differences will also
    depend on the Trust's future operating results, acquisitions and
    dispositions of assets and liabilities, and distribution policy. A
    significant change in any of the preceding assumptions could materially
    affect the Trust's estimate of the future income tax liability.

    6.  ASSET RETIREMENT OBLIGATIONS

    At December 31, 2007, the estimated total undiscounted amount required to
    settle the asset retirement obligations was $54,622,000 (2006 -
    $46,434,000). Costs for asset retirement have been calculated assuming a
    2 percent inflation rate. These obligations will be settled based on the
    useful lives of the underlying assets, which extend up to 50 years into
    the future. This amount has been discounted using a credit-adjusted
    risk-free interest rate of 5 (2006 - 5) percent.

    Changes to asset retirement obligations were as follows:

                                                      2007           2006
    -------------------------------------------------------------------------
    Asset retirement obligations, January 1      $ 14,819,000   $ 13,195,000
    Adjustment to asset retirement obligations       (399,000)     1,726,000
    Adjustment related to asset additions
     (net of disposals)                               563,000              -
    Liabilities settled during the year              (820,000)      (762,000)
    Accretion                                         741,000        660,000
    -------------------------------------------------------------------------
    Asset retirement obligations, December 31    $ 14,904,000   $ 14,819,000
    -------------------------------------------------------------------------

    7.  UNIT CAPITAL

    Authorized

    The Trust is authorized to issue an unlimited number of trust units
    without nominal or par value.

                                    2007                      2006
    -------------------------------------------------------------------------
    Issued                   Number       Amount       Number       Amount
    -------------------------------------------------------------------------
    Trust Units
    Balance, beginning
     of year               16,874,658  $89,488,000   16,535,158  $83,900,000
    Transfer of
     contributed surplus
     to unit capital                -      109,000            -      427,000
    Issued pursuant
     to Trust unit
     option plan               53,500      993,000      339,500    5,161,000
    -------------------------------------------------------------------------
    Balance, end of year   16,928,158  $90,590,000   16,874,658  $89,488,000
    -------------------------------------------------------------------------

    The number of trust units used to calculate diluted net earnings per unit
    for the year ended December 31, 2007 of 16,942,036 (2006 - 16,880,422)
    included the basic weighted average number of units outstanding of
    16,908,266 (2006 - 16,737,651) plus 33,770 (2006 - 142,771) units related
    to the dilutive effect of unit options.

    The deficit balance is composed of the following items:

                                                     2007           2006
    -------------------------------------------------------------------------
    Accumulated earnings                         $152,756,000   $122,406,000
    Accumulated cash distributions               (204,299,000)  (159,651,000)
    -------------------------------------------------------------------------
    Deficit                                      $(51,543,000)  $(37,245,000)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Trust provides an option plan for its directors, officers, employees
    and consultants. Under the plan, the Trust may grant options for up to
    1,692,800 (2006 - 1,687,500) trust units. The exercise price of each
    option granted equals the market price of the trust unit on the date of
    grant and the option's maximum term is five years.

    A summary of the status of the Trust's unit option plan as of
    December 31, 2007 and 2006, and changes during the years is presented
    below:

                                     2007                      2006
    -------------------------------------------------------------------------
                                          Weighted-                 Weighted-
                                           Average                   Average
                                          Exercise                  Exercise
                              Options       Price       Options       Price
    -------------------------------------------------------------------------
    Outstanding at
     beginning of year        721,500       $26.55      646,000       $18.67
    Options granted           553,000        28.11      447,000        29.18
    Options exercised         (53,500)       18.56     (339,500)       15.20
    Options cancelled         (44,000)       27.92      (32,000)       24.70
    -------------------------------------------------------------------------
    Outstanding at end
     of year                1,177,000       $27.59      721,500       $26.55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Options exercisable
     at end of year           530,000       $26.63      212,500       $22.62
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following table summarizes information about unit options outstanding
    at December 31, 2007:

                        Options Outstanding            Options Exercisable
    -------------------------------------------------------------------------
                 Number     Weighted-
                  Out-       Average      Weighted-     Number      Weighted-
    Range of    standing    Remaining     Average    Exercisable    Average
    Exercise       At      Contractual    Exercise        At        Exercise
    Prices      12/31/07      Life         Price       12/31/07      Price
    -------------------------------------------------------------------------
    $22.45-
     $23.35      225,000    1.4 years       $23.34      225,000       $23.34
    $24.20-
     $27.50       32,000    2.3 years        25.30            -            -
    $28.30-
     $28.75      880,000    1.6 years        28.49      285,000        28.75
    $32.00-
     $33.75       40,000    2.0 years        33.55       20,000        33.55
    -------------------------------------------------------------------------
    $22.45-
     $33.75    1,177,000    1.6 years       $27.59      530,000       $26.63
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Trust records compensation expense over the vesting period based on
    the fair value of options granted to employees, directors and
    consultants. The Trust granted 553,000 (2006 - 447,000) unit options with
    an estimated fair value of $1,494,000 (2006 - $1,193,000) ($2.70 per
    option, 2006 - $2.67 per option) using the Black-Scholes option pricing
    model with the following key assumptions:

                                                      2007           2006
    -------------------------------------------------------------------------
    Weighted-average risk free interest rate (%)       4.7            4.1
    Expected life (years)                              2.3            2.5
    Weighted-average volatility (%)                   27.2           27.0
    Dividend yield 2007 and 2006                     based on the percentage
                                                     of distributions paid to
                                                     the Unitholders during
                                                     the year

    8.  ACCUMULATED OTHER COMPREHENSIVE INCOME

                                    January 1,      Other
                                       2007     Comprehensive    December 31,
                                     (Note 1)       Income           2007
                                 --------------------------------------------
    Unrealized gains on available
     for sale financial assets    $  1,566,000   $  1,465,000   $  3,031,000
    Unrealized gains and losses
     on derivatives designated
     as cash flow hedges               814,000       (814,000)             -
                                 -------------- -------------- --------------
                                  $  2,380,000   $    651,000   $  3,031,000
                                 -------------- -------------- --------------
                                 -------------- -------------- --------------

    As of October 1, 2007, the Trust determined that its cash flow hedges on
    commodities described in Note 11 is no longer an effective hedge.
    Therefore the full loss in cash flow hedges has been transferred from
    accumulated other comprehensive income to net earnings.

    9.  RELATED PARTY TRANSACTIONS

    The Trust received a management fee from Comaplex of $300,000 (2006 -
    $300,000) for management services and office administration. This fee has
    been included as a recovery in general and administrative expenses and
    represents the fair value of the services rendered.

    As at December 31, 2007, the Trust had an account receivable from
    Comaplex of $63,000 (December 31, 2006 - $38,000).

    The Trust received a management fee from Pine Cliff of $216,000 (2006 -
    $216,000) for management services and office administration. This fee has
    been included as a recovery in general and administrative expenses and
    represents the fair value of the services rendered.

    As at December 31, 2007 the Trust had an account receivable from Pine
    Cliff of $4,000 (December 31, 2006 - $Nil).

    10. FINANCIAL INSTRUMENTS

    Fair Values

    The Trust's financial instruments include accounts receivable,
    distribution payable, accounts payable and accrued liabilities, and the
    revolving demand loan. The fair value of these financial instruments
    approximate their carrying value due to the short-term maturity of those
    instruments. Borrowings under bank credit facilities are for short
    periods with variable interest rates, thus, carrying values that
    approximate fair value. Derivative financial instruments are recorded at
    fair value (see Note 1)

    Credit Risk

    Substantially all of the Trust's accounts receivable are due from
    customers in the oil and gas industry and are subject to normal industry
    credit risks. The carrying value of accounts receivable reflects
    management's assessment of associated credit risks.

    Interest Rate Risk

    The Trust's bank debt is comprised of revolving loans at variable rates
    of interest, and as such, the Trust is exposed to interest rate risk.

    Commodity Price Risk

    The nature of the Trust's operations results in exposure to fluctuations
    in commodity prices and exchange rates. The Trust monitors and when
    appropriate uses derivative financial instruments to manage its exposure
    to these risks.

    11. COMMITMENTS, CONTINGENCIES AND GUARANTEES

    The Trust entered into the following commodity hedging transactions for a
    portion of its 2008 production:

                                          Volume
    Period of Agreement    Commodity      per day   Index    Price (Cdn.)
    -------------------    ---------      -------   -----    ------------
    January 1, 2008        Crude Oil  1,000 barrels   WTI   Floor of $73.00
     to June 30, 2008                                        and ceiling of
                                                             $83.00 per
                                                             barrel

    July 1, 2008 to        Crude Oil    500 barrels   WTI   Floor of $73.00
     December 31, 2008                                       and ceiling of
                                                             $80.68 per
                                                             barrel

    November 1, 2007     Natural Gas     2,000 GJ's  AECO   Floor of $6.50
     to March 31, 2008                                       and ceiling of
                                                             $10.37 per GJ

    Subsequent to December 31, 2007 and up to the date of the auditors'
    report the Trust has entered into the following commodity hedging
    transactions:

                                          Volume
    Period of Agreement    Commodity      per day   Index    Price (Cdn.)
    -------------------    ---------      -------   -----    ------------
    July 1, 2008 to        Crude Oil    500 barrels   WTI   Floor of $85.00
     December 31, 2008                                       and ceiling of
                                                             $104.80 per
                                                             barrel

    April 1, 2008 to     Natural Gas     1,500 GJ's  AECO   Floor of $6.00
     October 31, 2008                                        and ceiling of
                                                             $7.60 per GJ


    As at December 31, 2007 the fair value of the outstanding commodity
    hedging contracts was a net liability of $3,085,000 (December 31, 2006 -
    net asset of $1,189,000).

    The Trust has no contractual obligations that last more than a year other
    than its office lease agreement which is as follows:

    Contract Obligations                 Less than      1 - 3         4 - 5
                              Total        1 year       years         years
    -------------------------------------------------------------------------
    Office lease           $1,658,000     $289,000     $932,000     $437,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    12. SUBSEQUENT EVENTS - DISTRIBUTIONS

    Subsequent to December 31, 2007, the Trust declared distributions of
    $0.22 per unit payable on February 29 and $0.23 per unit payable on
    March 31, 2008 to Unitholders of record on February 15 and March 14, 2008
    respectively. The distributions represent amounts related to January and
    February 2008 operations.
    

    %SEDAR: 00017467E




For further information:

For further information: Additional information relating to the Trust
may be found on SEDAR.COM as well as on the Trust's web site at
www.bonterraenergy.com or by contacting George F. Fink, President, and CEO or
Garth E. Schultz, Vice President - Finance, and CFO at (403) 262-5307 or by
fax at (403) 265-7488

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Bonterra Energy Corp.

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