Bonterra Energy Income Trust Announces Fourth Quarter and Annual Results



    CALGARY, March 27 /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,
2006.

    
    HIGHLIGHTS

    -   Gross proved reserves total 20,518,000 BOE's(1) resulting in a
        reserve life(2) of approximately 13.6 years. Gross proven plus
        probable reserves total 26,476,000 BOE's for a 17.6 year reserve
        life.
    -   Funds flow(3) per fully diluted unit increased to $3.12 per unit from
        $2.69 with distributions totaling $2.82 per unit in 2006 compared to
        $2.37 per unit in 2005.
    -   Net Earnings per fully diluted unit increased to $2.21 per unit in
        2005 from $2.01 per unit in 2005.

    (1) 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.

    (2) The reserve life index is calculated by dividing the reserves (in
    BOE's) by the annualized fourth quarter average production rate in BOE/d
    (2005 - 3,780).

    (3) Funds flow from operations is not a recognized measure under GAAP.
    Management believes that in addition to net earnings, funds flow from
    operations 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 funds flow from operations as funds
    provided by operations before changes in non-cash operating working
    capital items excluding gain on sale of property and asset retirement
    expenditures.


    FINANCIAL AND OPERATIONAL SUMMARY

                            Three Months Ended            Years Ended
                                December 31               December 31
                             2006         2005         2006         2005
    -------------------------------------------------------------------------
    Oil, Gas & NGL Sales  $21,719,000  $21,753,000  $88,734,000  $75,837,000
    Funds Flow            $12,235,000  $12,489,000  $52,797,000  $44,579,000
    Funds Flow per Unit
     - basic              $      0.72  $      0.76  $      3.15  $      2.72
    Funds Flow per Unit
     - diluted            $      0.72  $      0.76  $      3.12  $      2.69
    Net Earnings          $ 6,471,000  $ 9,918,000  $37,250,000  $33,468,000
    Net Earnings per Unit
     - basic              $      0.39  $      0.59  $      2.23  $      2.04
    Net Earnings per Unit
     - diluted            $      0.38  $      0.58  $      2.21  $      2.01
    Distributions
     per Unit             $      0.72  $      0.68  $      2.82  $      2.37
    Units outstanding                                16,874,658   16,535,158
    Daily Oil and NGL
      Production (Bbls)         3,138        2,814        3,040        2,713
    Daily Gas
     Production (MCF)           5,885        5,795        6,014        5,650
    Daily BOE (6:1)             4,119        3,780        4,042        3,655
    Average Liquid Price
     ($/Bbl)              $     60.79  $     61.13  $     64.69  $     58.30
    Average Gas Price
     ($/MCF)              $      7.57  $     11.16  $      7.55  $      8.64
    Average BOE Price
     ($/BOE)              $     57.32  $     62.55  $     60.13  $     56.85
    Net Back per BOE      $     32.21  $     35.36  $     35.04  $     32.86
    


    ENGINEERING SUMMARY

    The Trust engaged the services of Sproule Associates Limited to prepare a
reserve evaluation with an effective date of December 31, 2006. 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 Dodsland and
Shaunavon areas 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, 2006
                         (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  12,934   12,269   17,011   12,675      754      536
    Developed
     Non-Producing          391      389    2,962    2,283       27       19
    Undeveloped           2,553    2,319    2,589    1,813       99       70
    -------------------------------------------------------------------------
    TOTAL PROVED         15,878   14,977   22,562   16,771      880      625
    PROBABLE              4,522    4,256    7,138    5,339      246      175
    -------------------------------------------------------------------------
    TOTAL PROVED PLUS
     PROBABLE            20,400   19,233   29,700   22,110    1,126      800
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


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

                              Light, Medium
                              Oil and NGL's               Natural Gas
                                           Gross                      Gross
                         Gross    Gross    Proved   Gross    Gross    Proved
                         Proved  Probable   Plus    Proved  Probable   Plus
                         (Mbbl)   (Mbbl)  Probable  (Mbbl)   (Mbbl)  Probable
                                           (Mbbl)                     (Mbbl)
    -------------------------------------------------------------------------
    December 31, 2005    15,662    3,944   19,606   20,473    5,110   25,583
      Extension              10        -       10      920        -      920
      Improved recovery   1,655      643    2,298    2,687      639    3,326
      Technical revisions   564      197      761      583    1,223    1,806
      Discoveries             1        2        3      116      172      288
      Acquisitions           16        -       16        -        -        -
      Dispositions          (40)     (18)     (58)     (11)      (5)     (16)
      Production         (1,110)       -   (1,110)  (2,206)       -   (2,206)
    -------------------------------------------------------------------------
    December 31, 2006    16,758    4,768   21,526   22,562    7,139   29,701
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


             SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
             AS OF DECEMBER 31, 2006 (FORECAST PRICES AND COSTS)

                                   NET PRESENT VALUE OF FUTURE NET REVENUE
                                        Before and After Income Taxes
                                            Discounted at (%/year)
                                    0        5        10       15       20
    (M$)
    RESERVE CATEGORY
    -------------------------------------------------------------------------
    PROVED
      Developed Producing        569,022  363,050  271,893  221,685  189,765
      Developed Non-Producing     27,731   19,068   15,479   13,444   12,069
      Undeveloped                 46,070   34,813   26,120   19,332   13,971
    -------------------------------------------------------------------------
    TOTAL PROVED                 642,823  416,931  313,492  254,461  215,805
    PROBABLE                     242,903  103,837   62,670   44,553   34,337
    -------------------------------------------------------------------------
    TOTAL PROVED PLUS PROBABLE   885,726  520,768  376,162  299,014  250,142
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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)
    -------------------------------------------------------------------------
    2007           74.10         7.51        43.94        55.23        75.88
    2008           77.62         8.38        46.03        57.85        79.49
    2009           70.25         7.55        41.66        52.36        71.94
    2010           65.56         7.37        38.88        48.87        67.14
    2011           61.90         7.54        36.71        46.14        63.40
    2012           63.15         7.68        37.45        47.07        64.67
    2013           64.42         7.79        38.21        48.02        65.98
    2014           65.72         7.93        38.97        48.98        67.30
    2015           67.04         8.07        39.76        49.97        68.66
    2016           68.39         8.21        40.56        50.97        70.04
    2017           69.76         8.54        41.38        52.00        71.45

    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 costs
        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 2006 average production of oil and natural gas liquids was
3,040 (2005 - 2,713) barrels per day and natural gas production in 2006
averaged 6,014 (2005 - 5,650) MCF per day. Oil production increased by
approximately 12 percent while gas production increased by approximately
6 percent. The increases were predominantly due to the Trusts 2005 and 2006
development programs. 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 2006.
    The Trust's overall annual decline rate for 2006 is approximately
nine percent which the Trust was able to more than offset with its 2006 drill
program. The Trust, along with its partners, drilled 43 gross (30.3 net)
Cardium oil wells. This includes 34 gross and 29 net Cardium wells drilled
directly by the Trust. Also the Trust drilled 18 gross (15.3 net) shallow gas
wells in 2006. The Trust experienced a 100 percent success rate with its and
its partners Cardium drilling program. The drilling of the shallow gas wells
resulted in 11 successful (8.3 net) and 7 gross and net wells that have been
determined to be uneconomic. The expenditures to drill these uneconomic wells
totalled $2,919,000 which has been written off as dry hole costs.
    As at December 31, 2006 Bonterra had 21 gross (11.4 net) Cardium oil
wells (including 9 gross, 1.3 net on non operated lands), 12 gross (9.3 net)
natural gas wells and 7 gross (5.5 net) coal-bed wells drilled but not on
production. During the fourth quarter the Trust tied-in 11 gross (10.4 net)
Cardium wells and 1 gross (1 net) natural gas well on its operated lands.
    Subsequent to December 31, 2006 and up to the date of this report,
Bonterra has put on production 6 gross (5.8 net) of its operated Cardium oil
wells and 2 gross (1 net) shallow gas wells. Most of the 9 gross (1.3 net)
wells on non-operated lands also have been completed in Q1, 2007. The Trust is
currently completing several of its Edmonton sand gas wells drilled in 2006
and anticipates that the majority of the gas wells will be on production by
the end of the second quarter of 2007. Bonterra is waiting on final regulatory
decisions and recovery in natural gas pricing prior to commencing further
completion work on the coal-bed methane wells.

    Revenue

    Gross revenue from petroleum and natural gas sales prior to royalties was
$88,734,000 (2005 - $75,837,000). The increase of $12,897,000 was due to
increased production volumes and an increase in the average price received for
crude oil offset partially by a 12.6 percent decline in the average price of
natural gas. The price received for crude oil increased to $64.69 per barrel
in 2006 from $58.30 per barrel in 2005 while natural gas prices decreased to
$7.55 per MCF in 2006 from $8.64 per MCF in 2005. Part of the increase in
average price of crude oil was the increased production related to the Trust's
light sweet crude production in the Pembina area of Alberta which receives a
higher price per barrel. The mix of light crude to mid grade crude has
increased to 87 percent of the Trust's crude oil production in 2006 from
85 percent in 2005
    The fourth quarter saw a decrease in gross revenues of $1,946,000 over
quarter three due primarily to decreased crude oil prices. The average price
received in the fourth quarter for crude oil and natural gas liquids was
$60.79 ($71.11 third quarter) per barrel and $7.57 ($6.95 third quarter) per
MCF for natural gas.
    Gross revenue has been reduced by $62,000 (2005 - $4,054,000) due to
lower prices received as a result of price hedging. The Trust will continue to
hedge future production (see Business Prospects, Risks, and Outlooks) to
assist in managing its cash flow. The Trust continues to follow the policy of
protecting high cost production with hedges that provide a significant level
of profitability and also to provide for a reasonable amount of cash flow
protection for development projects. The Trust will however maintain a policy
of not hedging more than 50 percent of production to allow it to benefit from
any price movements in either crude oil or natural gas.
    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, 2007        Crude Oil    500 barrels   WTI   Floor of $74.55
     to June 30, 2007                                        and ceiling of
                                                             $85.00 per
                                                             barrel
    January 1, 2007        Crude Oil    500 barrels   WTI   Floor of $75.00
     to June 30, 2007                                        and ceiling of
                                                             $95.47 per
                                                             barrel
    July 1, 2007 to        Crude Oil    500 barrels   WTI   Floor of $75.00
     December 31, 2007                                       and ceiling of
                                                             $93.00 per
                                                             barrel
    July 1, 2007 to        Crude Oil    500 barrels   WTI   Floor of $70.00
     December 31, 2007                                       and ceiling of
                                                             $80.06 per
                                                             barrel
    November 1, 2006     Natural Gas     2,000 GJ's  AECO   Floor of $6.65
     to March 31, 2007                                       and ceiling of
                                                             $12.50 per GJ
    December 1, 2006     Natural Gas     1,500 GJ's  AECO   Floor of $6.00
     to March 31, 2007                                       and ceiling of
                                                             $9.65 per GJ
    April 1, 2007        Natural Gas     2,000 GJ's  AECO   $6.52 per GJ
     to July 31, 2007
    April 1, 2007 to     Natural Gas     1,000 GJ's  AECO   Floor of $6.50
     October 31, 2007                                        and ceiling of
                                                             $9.20 per GJ
    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
    

    As of December 31, 2006 the fair value of the outstanding commodity
hedging contracts was a net asset of $1,189,000 compared to a net liability of
$1,349,000 as of December 31, 2005.

    Royalties

    Royalties paid by the Trust consist primarily of Crown royalties paid to
the Provinces of Alberta and Saskatchewan. During 2006 the Trust paid
$8,516,000 (2005 - $6,986,000) in Crown royalties and $1,996,000 (2005 -
$2,009,000) 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 (2005 - nine percent) and approximately
two percent (2005 - three percent) for other royalties before hedging
adjustments. Crown royalty rates vary with production volumes and as such the
crown rates are higher on the Trust's newly drilled wells. 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. Effective January 1, 2007, the Alberta Government discontinued the
rebate.

    Gain on Sale of Property

    The Trust disposed of its interests in a non-core, non-operated property
on January 1, 2006 for proceeds of $750,000 resulting in a gain on sale of
$532,000. Production from this property averaged ten barrels per day in 2005.
On April 8, 2005, a former subsidiary of Novitas Energy Ltd. ("Novitas") (a
subsidiary of the Trust), Pine Cliff Energy Ltd.'s (Pine Cliff) (with common
directors and management with Bonterra) rights offering closed with over
97 percent of former Novitas shareholders exercising their rights to acquire
common shares in Pine Cliff for $0.15 per common share. As part of the rights
offering, the Trust agreed to sell to Pine Cliff effective January 1, 2005
(closing April 9, 2005) approximately 18 BOE per day of production and some
exploration lands formally held by Novitas for proceeds of approximately
$1,000,000. As a result of this sale the Trust reported a gain on sale of
property of $225,000. The balance of the 2005 gain of $38,000 relates to a
disposition of an interest in another non-core area property.

    Production Costs

    Production costs totalled $22,238,000 in 2006 compared to $20,203,000 in
2005. On a barrel of oil equivalent (BOE) basis 2006 operating costs were
$15.07 compared to $15.14 for 2005. 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 drilled
wells are significantly lower on a BOE basis than on its older low
productivity wells and has resulted in the Trust being able to maintain its
operating costs to BOE rate even though the oil and gas industry saw double
digit rates of inflation on its well service costs.
    Operating costs were $5,997,000 in the fourth quarter of 2006 compared to
$5,689,000 in the third quarter. The increase was due primarily to a $241,000
charge related to an unsuccessful insurance claim relating to a 2005 oil
spill.
    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.
Operating costs in the $14 to $15 per BOE range are expected for 2007. The
high operating costs for the Trust are substantially offset by low royalty
rates of approximately 12 percent, which is much lower than industry average
for conventional production and results in high cash net backs on a combined
basis despite higher than average operating costs.

    General and Administrative Expense

    General and administrative expenses were $2,295,000 in 2006 compared to
$2,420,000 in 2005. On a BOE basis, general and administrative expenses in
2006 averaged $1.56 compared to $1.81 per BOE in 2005. The Trust is managed
internally. In addition, the Trust provides administrative services to
Comaplex Minerals Corp. (Comaplex) and 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 cost increase was
in employee compensation. The Trust has an employee incentive plan equal to
three percent of net earnings before taxes. In 2006 net earnings before taxes
increased to $36,864,000 from $33,548,000 in 2005 resulting in an additional
$100,000 of employee compensation expense. In addition, the Trust added
additional staff to assist with its enhanced capital programs. The additional
employee compensation has been offset by higher intercompany charges and
increased overhead recoveries charged to operations and capital programs.
    The fourth quarter general and administrative expenses were $89,000 lower
than the third quarter. The decrease was primarily due to the reduction in the
Trust's employee bonus amount resulting from the provision of $2,919,000 in
dry hole costs.

    Interest Expense

    Interest expense for the 2006 fiscal year of the Trust was $1,610,000
(2005 - $575,000). The increase was due to increased loan balances resulting
from the Trust's 2006 capital program. The Trust incurred $38,348,000 in
capital development expenditures in 2006 resulting in an increase of
$25,202,000 in outstanding debt.
    Interest rate charges during the year on the outstanding debt averaged
approximately 5.3 (2005 - 4.7) percent. The Trust maintained an average
outstanding debt balance of approximately $31,000,000 (2005 - $12,250,000).
Total debt (including negative working capital) as of December 31, 2006
represents approximately 11.5 months of 2006 annual funds flow or 12.3 months
based on annualized 2006 fourth quarter funds flow.
    The Trust believes that maintaining debt at or less than one year's funds
flow (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 natural gas from coals potential without requiring the
issuance of trust units. The Trust's December 31, 2006 debt level is slightly
higher than this level. A significant decrease in the fourth quarter price of
crude oil coupled with the Trust increasing its 2006 capital program, resulted
in higher debt levels and lower funds flow for the quarter. A large number of
wells drilled in 2006 were not tied in for production until the fourth quarter
of 2006 or in 2007 and therefore contributed little or no cash flow to reduce
debt.
    The Trust's current bank agreements (each of Bonterra Energy Corp,
Comstate Resources Ltd. and Novitas have their own) provide for a combined
$49,900,000 (January 1, 2007 - $59,900,000) of available credit facility. Bank
debt at December 31, 2006 was $45,379,000 (December 31, 2005 - $20,177,000).
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 Based Compensation

    The Trust is required to record a compensation expense over the vesting
period of its unit options based on the fair value of the unit options granted
to employees, directors and consultants. During the year 447,000 (2005 -
407,000) unit options were granted with a fair value of $2.67 per unit (2005 -
$2.49). The fair value of options granted has been estimated using the
Black-Scholes option pricing model, assuming a weighted risk free interest
rate of 4.1 (2005 - 3.5) percent, expected weighted average volatility of 27
(2005 - 31) percent, expected weighted average life of 2.5 (2005 - 2.5) years
and an annual dividend rate based on the distributions paid to the Unitholders
during the year. The result of applying the above, a total unit based
compensation of $734,000, based on currently issued and outstanding options,
is required to be recorded over the years 2007 and 2008.

    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. The Trust believes that the successful
efforts method of accounting provides a more accurate cost of the producing
properties than the alternative measure of full cost accounting.
    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, 2006, the estimated total undiscounted amount required to
settle the asset retirement obligations was $46,434,000 (2005 - $39,921,000).
Of the $6,513,000 increase, approximately $2 million is due to the increased
number of wells resulting from the Trust's 2006 capital program, with the
balance resulting from increased inflation assumptions.
    These obligations will be settled based on the useful lives of the
underlying assets, which extend up to 40 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 $2,263,000. While a one percent decrease in the
risk adjusted rate would increase the asset retirement obligation by
$2,989,000.
    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, 2006, the Trust expensed
$15,393,000 (2005 - $10,358,000) for the above-described items including
$2,919,000 (2005 - $628,000) for dry hole costs. The increase of $2,744,000
(excluding dry hole costs) over the 2005 balance is due primarily to increased
2006 production levels. The Trust has experienced increased finding and
development costs over the past two years (see Finding and Development Costs
below). This has resulted in a higher depletion per barrel as production from
the 2005/2006 wells make up a larger component of overall production. Based on
year end reserves, the Trusts average cost of proved reserves is $5.95 (2005 -
$5.08) per BOE.
    The dry hole cost of $2,919,000 relates to seven shallow gas wells that
were drilled in the winter and summer of 2006. Five of these wells were
drilled pursuant to a farm-in agreement where Bonterra was committed to
drilling and completing a certain number of wells in order to earn in on the
entire land area. In total 12 wells (nine by the end of August) were drilled
and completed on the farm in lands in 2006. A further two were drilled in
January 2007 to complete the required wells per the farm-in agreements. The
wells were designed to test the productivity of the Edmonton Sands shallow gas
potential in two separate townships.
    The Trust currently has an estimated reserve life for its proved
developed producing reserves of 11.0 (2005 - 12.1) years calculated using the
Trust's gross reserves (prior to allowance for royalties) based on the third
party engineering report dated December 31, 2006 and using fourth quarter 2006
average production rates of 4,119 BOE's (2005 - 3,780 BOE's). Based on total
proved reserves the Trust has a 13.6 (2005 - 13.8) year reserve life and if
proved and probable are used the reserve life increases to 17.6 (2005 - 17.3)
years. These figures are some of the longest (excluding oil sands) reserve
life indexes in the Trust sector.

    Income Taxes

    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. Please see
discussion under Taxation of Trusts for discussion relating to the newly
announced taxation of trusts. However, the Trust operates its oil and gas
interests through its 100 percent owned subsidiaries Bonterra Energy Corp.
(Bonterra Corp.), Comstate Resources Ltd. (Comstate Ltd.) and Novitas.
Effective January 1, 2007 the Trust amalgamated Comstate Ltd. and Bonterra
Corp. All operating companies pay the majority of their income to the Trust
through interest and royalty payments which are deductible for income tax
purposes. For the taxation periods ending prior to 2004 Bonterra Corp. and
Comstate Ltd. both paid to the Trust sufficient royalty and interest payments
to eliminate all their taxable income. During 2004, due to timing of capital
expenditures and other funds flow factors, Comstate Ltd. was unable to pay
sufficient payments to the Trust to eliminate all of its taxable income and
paid taxes of approximately $560,000. Comstate Ltd. was able to obtain a full
refund of the 2004 taxes in 2005.
    The Province of Saskatchewan levies a resource surcharge on all oil and
gas produced in the province. This surcharge applies if an individual company
exceeds a minimum capital threshold or where there are related companies a
combined asset threshold also applies. Both Bonterra Corp. and Comstate Ltd.
both exceeded the individual company threshold in 2006 and are now subject to
the surcharge. The Trust recorded a tax expense of $367,000 in relation to the
surcharge. Novitas may be subject to the surcharge by 2007 due to the
continued combined growth of the Trust's subsidiaries. Based on the Trust's
2006 revenues, from oil and gas production in the Province of Saskatchewan,
and if all operating companies had exceeded the combined asset threshold a
total tax expense of $617,000 would have been recorded.
    Future tax provision relates to the future taxes that exist within
Bonterra Corp., Comstate Ltd. and Novitas. The liability on the balance sheet
and the corresponding income recovery relates to temporary differences
existing between Bonterra Corp's., Comstate Ltd.'s and Novitas' book value of
its assets and its remaining tax pools. Provision for future tax fluctuates
quarter over quarter depending on the timing of capital expenditures and funds
flow levels in each respective operating company.
    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  $15,037,000
    Canadian oil and gas property expenditures               10    1,244,000
    Canadian development expenditures                        30   30,581,000
    Canadian exploration expenditures                       100       93,000
    Income tax losses carried forward(1)                    100    9,035,000
    -------------------------------------------------------------------------
                                                                 $55,990,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1)  Income tax losses carried forward expire in 2014 ($635,000), 2015
         ($3,574,000) and 2016 ($4,826,000).

    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  $15,685,000
    Finance costs                                            20      626,000
    Eligible capital expenditures                             7      168,000
    -------------------------------------------------------------------------
                                                                 $16,479,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Canadian tax breakdown of distributions for the 2006 taxation year is
as follows:

                                         Percentage
                                         ----------
    Taxable Income (Other Income)             78.80
    Return of Capital                         21.20
                                         ----------
                                             100.00
                                         ----------
    

    With respect to cash distributions paid during the year to U.S.
individual unitholders, 18.1 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 81.9 percent should be reported as qualified dividends.

    Net Earnings

    The Trust's net earnings of $37,250,000 for the year ended December 31,
2006 represents an increase of $3,782,000 over the Trusts 2005 net earnings of
$33,468,000. The Trust recorded net earnings per unit on a fully diluted bases
in 2006 of $2.21 verses $2.01 in the 2005 year. This represents a return on
Unitholders' equity of approximately 69.8 (2005 - 58.4) percent based on year
end Unitholders' equity.
    Strong commodity prices along with a 10.5 percent increase in production
volumes were the main drivers of the increased earnings. The Trust continues
to return in excess of 40 percent of its gross revenues in net earnings. The
Trust's low capital costs combined with a low debt to funds flow ratio all
contribute to the high return. Bonterra's high 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).

    Funds Flow from Operations

    Funds flow from operations for the year ending December 31, 2006 was
$52,797,000 compared to $44,579,000 for the year ended December 31, 2005.
Funds flow from operations is not a recognized measure under GAAP. The Trust
believes that in addition to net earnings, funds flow from operations 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 funds flow from operations 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 increase was primarily due to higher commodity prices and higher
production volumes. As with all oil and gas producers the Trust's funds flow
is highly dependent on commodity prices.
    The following reconciliation compares funds flow to the Trust's cash flow
from operations as calculated according to Canadian generally accepted
accounting principles:

    
    For the periods            Three Months              Twelve Months
     ended December 31       2006         2005         2006         2005
    -------------------------------------------------------------------------
    Cash flow from
     operations for the
     period               $11,925,000  $12,342,000  $51,944,000  $38,985,000
    Items not affecting
     funds flow:
      Gain on sale of
       property                     -            -      532,000      263,000
      Changes in accounts
       receivable           1,102,000       50,000      147,000    2,814,000
      Changes in crude
       oil inventory         (179,000)      66,000        7,000      134,000
      Changes in parts
       inventory                5,000       (3,000)    (107,000)    (170,000)
      Changes in prepaid
       expenses              (299,000)    (380,000)     305,000     (306,000)
      Changes in accounts
       payable and accrued
       liabilities           (688,000)     369,000     (793,000)   2,584,000
      Asset retirement
       obligations settled    369,000       45,000      762,000      275,000
    -------------------------------------------------------------------------
    Funds flow from
     operations for
     the period           $12,235,000  $12,489,000  $52,797,000  $44,579,000
    -------------------------------------------------------------------------

    Cash Netback

    The following table illustrates the Trust's cash netback:

    $ per Barrel of Oil Equivalent (BOE)               2006         2005
    -------------------------------------------------------------------------
    Production volumes (BOE)                          1,475,639    1,334,075
    Gross production revenue                        $     60.13  $     56.85
    Royalties                                             (7.12)       (6.74)
    Field operating                                      (15.07)      (15.14)
    -------------------------------------------------------------------------
    Field netback                                         37.94        34.97
    General and administrative                            (1.56)       (1.81)
    Interest and taxes                                    (1.34)       (0.30)
    -------------------------------------------------------------------------
    Cash netback                                    $     35.04  $     32.86
    -------------------------------------------------------------------------

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

                                                    December 31  September 30
    $ per Barrel of Oil Equivalent (BOE)                2006         2006
    -------------------------------------------------------------------------
    Production volumes (BOE)                            378,916      369,104
    Gross production revenue                        $     57.32  $     64.12
    Royalties                                             (6.37)       (6.77)
    Field operating                                      (15.83)      (15.41)
    -------------------------------------------------------------------------
    Field netback                                         35.12        41.94
    General and administrative                            (1.27)       (1.55)
    Interest and taxes                                    (1.64)       (1.38)
    -------------------------------------------------------------------------
    Cash netback                                    $     32.21  $     39.01
    -------------------------------------------------------------------------

    Finding and Development Costs (F&D Costs)

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

    -------------------------------------------------------------------------
                      2006 F&D   2005 F&D   2004 F&D  2006 Three  2005 Three
                     Costs per  Costs per  Costs per     Year        Year
                      BOE(1,2)   BOE(1,2)   BOE(1,2)    Average     Average
    -------------------------------------------------------------------------
    Proved Reserve
     Additions          $25.51     $14.86      $7.33      $15.90      $10.47
    -------------------------------------------------------------------------
    Proved plus
     Probable Reserve
     Additions          $18.21     $12.33      $4.97      $11.84       $6.90
    -------------------------------------------------------------------------

    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.
    

    Escalating development costs combined with moderate results in the Trusts
shallow gas drilling program in 2006 has resulted in a substantial increase in
2006 F&D costs. With the recent reduction in commodity prices, the Trust is
being able to negotiate lower drilling rig costs in respect of its 2007 winter
drill program.

    Related Party Transactions

    The Trust holds 689,682 (2005 - 689,682) common shares in Comaplex which
have a fair market value as of December 31, 2006 of $2,297,000 (2005 -
$2,448,000). Comaplex is a publically traded mineral company on the Toronto
Stock Exchange. The Trust's ownership in Comaplex represents approximately
1.7 percent of the issued and outstanding common shares of Comaplex. Bonterra
has common directors and management with Comaplex.
    Comaplex paid a management fee to Comstate Ltd. of $300,000 (2005 -
$240,000). Comaplex also cost shares office rental costs and reimburses
Comstate Ltd. for costs related to employee benefits and office materials. In
addition Comaplex owns 204,633 (December 31, 2005 - 204,633) units in the
Trust. Services provided by Comstate Ltd. include executive services
(president and vice president, finance duties), accounting services, oil and
gas administration and office administration. All services performed are
charged at estimated fair value. At December 31, 2006, Comaplex owed the Trust
$38,000 (December 31, 2005 - $29,000).
    The Trust also has a management agreement with Pine Cliff. Pine Cliff has
common directors and management with the Trust. Pine Cliff trades on the TSX
Venture Exchange. Pine Cliff paid a management fee to Comstate Ltd. of
$216,000 (2005 - $132,000). Services provided by Comstate Ltd. include
executive services (president and vice president, finance duties), accounting
services, oil and gas administration and office administration. All services
performed are charged at estimated fair value. The Trust has no share
ownership in Pine Cliff. There were no intercompany balances owing as of
December 31, 2006.

    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     After
                             Total     1 year     years     years    5 years
    -------------------------------------------------------------------------
    Office lease          $1,963,000  $283,000  $910,000  $656,000  $114,000
    -------------------------------------------------------------------------
    

    Liquidity and Capital Resources

    During 2006 the Trust participated in drilling 61 gross (45.6 net) wells
at a total cost of $38,348,000. Of these wells, 43 gross (30.3 net) were oil
wells and 18 gross (15.3 net) were natural gas wells. The Trust's operated
2006 drill program consisted of 34 gross (29 net) Cardium oil wells and 17
gross (14.7 net) natural gas wells.
    As at December 31, 2006 Bonterra had 21 gross (11.4 net) Cardium oil
wells (including 9 gross, 1.3 net on non operated lands), 12 gross (9.3 net)
natural gas wells and 7 gross (5.5 net) coal-bed wells drilled but not on
production. Subsequent to December 31, 2006 and up to the date of this report,
Bonterra has put on production 6 gross (5.8 net) Cardium oil wells and 2 gross
(1 net) shallow gas wells. The Trust is currently completing several of its
Edmonton sand gas wells drilled in 2006 and anticipates that the majority of
the gas wells will be on production by the end of the second quarter of 2007.
Bonterra is waiting on final regulatory decisions and recovery in natural gas
pricing prior to commencing further completion work on the coal-bed methane
wells.
    The Trust currently has plans to drill 20 gross (15 net) infill Cardium
wells and 2 gross (1.8 net) natural gas wells in 2007. Total capital costs are
anticipated to be approximately $20,000,000 for the planned development
programs and tying in of the remaining 2006 drilled wells. The Trust
anticipates funding the 2007 capital program out of current funds flow
($10-$15 million), exercising of employee unit options ($2-$3 million) and
existing lines of credit. This combination should allow for the Trust to
maintain an approximate one year debt to funds flow ratio.
    The Trust is continuing with its efforts to acquire producing and non
producing properties through either property or entity acquisitions. Funding
for any acquisition would depend on items such as the type of acquisition
(entity vs. property), quality of the assets, size of the purchase and the
Trust unit trading price at the time of the acquisition.
    At December 31, 2006 the Trust had bank debt of $45,379,000 (2005 -
$20,177,000). The Trust through its operating subsidiaries has bank revolving
credit facilities totalling $49,900,000 at December 31, 2006 (December 31,
2005 - $36,900,000). Effective January 1, 2007 this amount has been increased
to $59,900,000. The facilities carry an interest rate of Canadian chartered
bank prime.

    Taxation of Trusts

    On October 31, 2006 the Minster of Finance for Canada announced new
proposals for the taxation of existing income trusts. In summary under the new
proposals:

    
    -   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 addition the Minister announced the governments attempt to limit the
growth of existing income trusts. Under the proposals, 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 now to 2011 by an amount that does not exceed the greater of $50
million and an objective "safe harbour" amount. The safe harbour amount will
be measured by reference to the trusts 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 trusts issued and outstanding publicly-traded units.
For the period November 1, 2006 to December 31, 2007 an income trusts 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 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.
    The above proposals have not been made law as of the date of this report.
In addition, the rules surrounding the safe harbour rules and conversion to a
corporate form have not yet been drafted into legislation.
    The impact to individual unitholders of the above proposals 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 55
percent made up of 31.5 percent 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 31.5 percent, then a further 15 percent withholding
is required and the non-residents must also pay their own federal and state
taxes. This could result in excess of 60 percent being paid in taxes.
    Bonterra's market value has been significantly impacted by the above
announcement. The Trust traded at $37.50 on October 31, 2006, and ended the
year at $25.57. The actual impact on operations to date has been minimal.
However, the uncertainty of how the legislation will be drafted and eventually
put into law has caused the Trust to be more conservative when examining its
current operations.
    As of January 2, 2007, the Trust is believed to be owned approximately 25
percent by non-residents (based on ADP Canada and ADP USA beneficial reports).
As for the ownership by tax deferred funds, it is managements estimate that no
more than 15 percent is held by such entities. Therefore the majority of the
beneficial owners of Bonterra are estimated to be taxable Canadian investors.

    
    Management has been examining its options. These include:

    (1)  Continuing as a trust.
    (2)  Continuing as a trust to 2011 and converting to a corporation at
         that time.
    (3)  Immediate conversion to a corporation.
    

    All of these options have differing impacts to the Trust's various
unitholders. With the fact the current government is in a minority position in
the house of commons, there is a large degree of uncertainty as to whether the
draft legislation will be passed, what amendments if any would be made, what
further legislation will be enacted to cover the safe harbour rules and
conversion features as well as a possible delay in the implementation of the
tax. All of these considerations may very will impact management's decision
regarding the best course of action for Bonterra.
    Until more concrete information can be obtained it is management's
position that the Trust should continue with its current operations. The
proposed safe harbour rules will allow the Trust to raise in excess of
$650,000,000 over the next four years without losing its tax free status to
2011. This will allow the Trust to continue with its Cardium infill drilling
program, its shallow natural gas and natural gas from coals development as
well as potentially developing a CO(2) flood program and making some
acquisitions. Emphasis will be placed on increasing the Trusts available tax
pools to assist in mitigating any future tax consequences should the
legislation be passed.
    Management will ensure that as information about the taxation of trusts
is provided all such relevant information will be made available to
Unitholders through press releases or as part of the Trust's continuous
disclosure requirements.

    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                                2006           2005

    Assets
    Current
      Accounts receivable (Note 8)               $ 10,486,000   $ 11,020,000
      Crude oil inventory                             843,000        836,000
      Parts inventory                                 114,000        221,000
      Prepaid expenses                              1,086,000        781,000
      Investment in related party (Note 2)            461,000        461,000
    -------------------------------------------------------------------------
                                                   12,990,000     13,319,000
    -------------------------------------------------------------------------
    Property and Equipment (Note 3)
      Petroleum and natural gas properties and
       related equipment                          176,602,000    139,798,000
      Accumulated depletion and depreciation      (54,650,000)   (42,968,000)
    -------------------------------------------------------------------------
                                                  121,952,000     96,830,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                                 $134,942,000   $110,149,000
    -------------------------------------------------------------------------
    Liabilities
    Current
      Distribution payable                       $  4,050,000   $  3,638,000
      Accounts payable and accrued liabilities     13,748,000     11,476,000
      Debt (Note 4)                                45,379,000     20,177,000
    -------------------------------------------------------------------------
                                                   63,177,000     35,291,000
    Future income tax liability (Note 5)            3,587,000      4,341,000
    Asset retirement obligations (Note 6)          14,819,000     13,195,000
    -------------------------------------------------------------------------
                                                   81,583,000     52,827,000
    -------------------------------------------------------------------------

    Commitments, Contingencies and Guarantees
     (Note 10)

    Unitholders' Equity (Note 7)
      Unit capital                                 89,488,000     83,900,000
      Contributed surplus                           1,116,000        636,000
      Deficit                                     (37,245,000)   (27,214,000)
    -------------------------------------------------------------------------
                                                   53,359,000     57,322,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                                 $134,942,000   $110,149,000
    -------------------------------------------------------------------------


                        Bonterra Energy Income Trust
                        ----------------------------
               Consolidated Statements of Unitholders' Equity
               ----------------------------------------------

    For the Years Ended December 31                  2006           2005

    Unitholders' equity, beginning of year       $ 57,322,000   $ 54,060,000
    Net earnings for the year                      37,250,000     33,468,000
    Net capital contributions (Note 7)              5,161,000      2,823,000
    Units issued on acquisition of Novitas
     Energy Ltd. (Note 7)                                   -      5,681,000
    Unit issue costs on acquisition of Novitas
     Energy Ltd. (Note 7)                                   -       (259,000)
    Unit based compensation adjustment                907,000        498,000
    Dstributions declared                         (47,281,000)   (38,949,000)
    -------------------------------------------------------------------------
    Unitholders' Equity, End of Year             $ 53,359,000   $ 57,322,000
    -------------------------------------------------------------------------


                        Bonterra Energy Income Trust
                        ----------------------------
              Consolidated Statements of Operations and Deficit
              -------------------------------------------------

    For the Years Ended December 31                  2006           2005

    Revenue
      Oil and gas sales                          $ 88,734,000   $ 75,837,000
      Royalties                                   (10,512,000)    (8,995,000)
      Alberta royalty tax credit                      487,000        464,000
      Gain on sale of property (Note 3)               532,000        263,000
      Interest and other                               66,000         33,000
    -------------------------------------------------------------------------
                                                   79,307,000     67,602,000
    -------------------------------------------------------------------------
    Expenses
      Production costs                             22,238,000     20,203,000
      General and administrative                    2,295,000      2,420,000
      Interest on debt                              1,610,000        575,000
      Unit based compensation                         907,000        498,000
      Dry hole costs                                2,919,000        628,000
      Depletion, depreciation and accretion        12,474,000      9,730,000
    -------------------------------------------------------------------------
                                                   42,443,000     34,054,000
    -------------------------------------------------------------------------
    Earnings Before Income Taxes                   36,864,000     33,548,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Income taxes (recovery) (Note 5)
      Current                                         367,000       (175,000)
      Future                                         (753,000)       255,000
    -------------------------------------------------------------------------
                                                     (386,000)        80,000
    -------------------------------------------------------------------------
    Net Earnings for the Year                      37,250,000     33,468,000
    Deficit, beginning of year                    (27,214,000)   (21,733,000)
    Distributions declared                        (47,281,000)   (38,949,000)
    -------------------------------------------------------------------------
    Deficit, end of year                        ($ 37,245,000) ($ 27,214,000)
    -------------------------------------------------------------------------
    Net Earnings Per Unit - Basic (Note 7)       $       2.23   $       2.04
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Earnings Per Unit - Diluted (Note 7)     $       2.21   $       2.01
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



                        Bonterra Energy Income Trust
                        ----------------------------
                    Consolidated Statements of Cash Flow
                    ------------------------------------

    For the Years Ended December 31                  2006           2005

    Operating Activities
      Net earnings for the year                  $ 37,250,000   $ 33,468,000
      Items not affecting cash
        Gain on sale of property                     (532,000)      (263,000)
        Unit based compensation                       907,000        498,000
        Dry hole costs                              2,919,000        628,000
        Depletion, depreciation and accretion      12,474,000      9,730,000
        Future income taxes (recovery)               (753,000)       255,000
    -------------------------------------------------------------------------
                                                   52,265,000     44,316,000
    -------------------------------------------------------------------------
      Change in non-cash working capital
        Accounts receivable                          (147,000)    (2,814,000)
        Crude oil inventory                            (7,000)      (134,000)
        Parts inventory                               107,000        170,000
        Prepaid expenses                             (305,000)       306,000
        Accounts payable and accrued liabilities      793,000     (2,584,000)
      Asset retirement obligations settled           (762,000)      (275,000)
    -------------------------------------------------------------------------
                                                     (321,000)    (5,331,000)
    -------------------------------------------------------------------------
                                                   51,944,000     38,985,000
    -------------------------------------------------------------------------
    Financing Activities
      Increase in debt                             25,202,000     11,717,000
      Unit option proceeds                          5,161,000      2,823,000
      Unit issue costs on acquisition of
       Novitas Energy Ltd.                                  -       (259,000)
      Unit distributions                          (46,869,000)   (38,001,000)
    -------------------------------------------------------------------------
                                                  (16,506,000)   (23,720,000)
    -------------------------------------------------------------------------
    Investing Activities
      Property and equipment expenditures         (38,348,000)   (16,669,000)
      Proceeds on sale of property                    750,000      1,097,000
      Abandonment deposit                                   -      1,522,000
      Cash portion of Novitas Energy Ltd.
       acquisition                                          -       (769,000)
    -------------------------------------------------------------------------
                                                  (37,598,000)   (14,819,000)
    -------------------------------------------------------------------------
      Change in non-cash working capital
        Accounts receivable                           681,000       (534,000)
        Accounts payable and accrued liabilities    1,479,000         88,000
    -------------------------------------------------------------------------
                                                    2,160,000       (446,000)
    -------------------------------------------------------------------------
                                                  (35,438,000)   (15,265,000)
    -------------------------------------------------------------------------
    Net cash inflow                                         -              -
    Cash, beginning of year                                 -              -
    -------------------------------------------------------------------------
    Cash, End of Year                            $          -   $          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash Interest Paid                           $  1,610,000   $    575,000
    Cash Taxes Paid                              $    393,000   $    894,000



                        Bonterra Energy Income Trust
                        ----------------------------
               Notes to the Consolidated Financial Statements
               ----------------------------------------------

    For the Years Ended December 31, 2006 and 2005

    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), Comstate Resources Ltd. (Comstate) and
    effective January 7, 2005, Novitas Energy Ltd. (Novitas). Effective
    January 1, 2007, Bonterra and Comstate amalgamated. Inter-company
    transactions and balances are eliminated upon consolidation.

    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.

    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 the 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's
    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 tax liabilities and assets is recognized in income in the period
    in which the change occurs.

    The Trust is a taxable entity under the Income Tax Act (Canada) and is
    taxable only on income that is not distributed or distributable to the
    Unitholders. As the Trust allocates all of its taxable income to the
    Unitholders in accordance with the Trust Indenture, and meets the
    requirements of the Income Tax Act (Canada) applicable to the Trust, no
    provision for income tax expense has been made in the Trust. However, the
    Trust's subsidiaries are subject to taxation on income which is not
    transferred to the Trust.

    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-Based Compensation

    The Trust has a unit-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.

    Hedging

    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.  For the twelve months ended December 31, 2006 the Trust
    recorded a reduction to net revenue of $62,000 (2005 - $4,054,000) with
    respect to these agreements.

    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 AND ACQUISITION OF NOVITAS ENERGY LTD.

    The investment consists of 689,682 (December 31, 2005 - 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 cost. The fair market value as determined by
    using the trading price of the stock at December 31, 2006 was $2,297,000
    (December 31, 2005 - $2,448,000). The common shares trade on the Toronto
    Stock Exchange under the symbol CMF. The investment represents less than
    a two percent ownership in the outstanding shares of Comaplex.

    On January 7, 2005 the Trust acquired Novitas. The acquisition was
    accounted for at Novitas' carrying value due to the related status of
    Novitas to the Trust. The carried values were as follows:

    Accounts receivable                                         $    568,000
    Crude oil inventory                                              122,000
    Prepaid expenses                                                  47,000
    Property and equipment                                        23,130,000
    Accumulated depletion and depreciation                        (6,522,000)
    Accounts payable and accrued liabilities                      (2,010,000)
    Debt                                                          (4,598,000)
    Future income tax liability                                   (3,089,000)
    Asset retirement obligations                                  (1,198,000)
                                                               --------------
                                                                $  6,450,000
                                                               --------------
                                                               --------------

    The acquisition cost was $769,000 cash and the issuance of 1,335,753
    trust units.

    3.  PROPERTY AND EQUIPMENT

                                 2006                        2005
                                    Accumulated                 Accumulated
                                     Depletion                   Depletion
                                        and                         and
                             Cost   Depreciation     Cost       Depreciation
    -------------------------------------------------------------------------
    Undeveloped land  $    334,000  $          -  $    334,000  $          -

    Petroleum and
     natural gas
     properties and
     related
     equipment         175,353,000    54,008,000   138,713,000    42,622,000

    Furniture,
     equipment and
     other                 915,000       642,000       751,000       346,000
    -------------------------------------------------------------------------
                      $176,602,000  $ 54,650,000  $139,798,000  $ 42,968,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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.

    On April 8, 2005, a former subsidiary of Novitas, Pine Cliff Energy Ltd.
    (Pine Cliff) (with common directors and management with the Trust and its
    subsidiaries) closed a rights offering with over 97 percent of former
    Novitas shareholders exercising their rights to acquire common shares in
    Pine Cliff for $0.15 per common share. As part of the rights offering,
    the Trust agreed to sell to Pine Cliff effective January 1, 2005 (closing
    April 8, 2005) approximately 18 barrels per day of oil equivalent of
    production and some exploration lands formerly held by Novitas for
    proceeds of approximately $1,000,000. As a result of this sale the Trust
    reported a gain on sale of property of $225,000. The Trust also disposed
    of minor non-core area properties for proceeds of approximately $97,000
    for a gain of $38,000.

    4.  DEBT

    The Trust has a bank revolving credit facility of $49,900,000 at
    December 31, 2006 (2005 - $36,900,000). Effective January 2, 2007 the
    revolving credit facility was increased to $59,900,000. 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, 2005 - $340,000) were issued at December 31, 2006. 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, 2006 for this loan was $1,610,000 (2005 -
    $575,000).

    5.  INCOME TAXES

    The Trust has recorded a future income tax liability related to assets
    and liabilities and related tax amounts held through its 100 percent
    owned operating subsidiaries. The following figures do not reflect the
    potential consequences of the Canadian Federal Governments October 31,
    2006 announcement on the future taxation of Income Trusts. The liability
    relates to the following temporary differences in those subsidiaries:

                                                     2006           2005
    -------------------------------------------------------------------------
    Future income tax liability to assets and
     liabilities of the subsidiary companies     $  6,233,000   $  5,919,000
    Future tax asset related to finance costs
     in corporate subsidiaries                              -        (12,000)
    Future tax asset related to corporate tax
     losses carried forward in the subsidiary
     companies                                     (2,646,000)    (1,566,000)
    -------------------------------------------------------------------------
                                                 $  3,587,000   $  4,341,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Income tax expense varies from the amounts that would be computed by
    applying Canadian federal and provincial income tax rates as follows:

                                                     2006           2005
    -------------------------------------------------------------------------
    Earnings before income taxes                 $ 36,864,000   $ 33,548,000
    Combined federal and provincial income
     tax rates                                         34.97%         38.08%
    -------------------------------------------------------------------------
    Income tax provision calculated using
     statutory tax rates                           12,891,000     12,775,000
    Increase (decrease) in taxes resulting
     from:
      Saskatchewan resource surcharge                 389,000        347,000
      Unit-based compensation                         317,000        190,000
      Non-deductible crown royalties                1,072,000      1,793,000
      Resource allowance                           (1,901,000)    (3,283,000)
      Trust income allocated to Unitholders       (13,031,000)   (12,763,000)
      Adjustment on acquisition of Novitas                  -      1,055,000
      Others                                         (123,000)       (34,000)
    -------------------------------------------------------------------------
    Income tax expense (recovery)                $   (386,000)  $     80,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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   $ 15,037,000
    Canadian oil and gas property expenditures             10      1,244,000
    Canadian development expenditures                      30     30,581,000
    Canadian exploration expenditures                     100         93,000
    Income tax losses carried forward(1)                  100      9,035,000
    -------------------------------------------------------------------------
                                                                $ 55,990,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Income tax losses carried forward expire in 2014 ($635,000), 2015
        ($3,574,000) and 2016 ($4,826,000).

    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   $ 15,685,000
    Finance costs                                          20        626,000
    Eligible capital expenditures                           7        168,000
    -------------------------------------------------------------------------
                                                                $ 16,479,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    On October 31, 2006, the Canadian Federal Government announced a proposed
    Trust taxation pertaining to taxation of distributions paid by publicly
    traded income trusts. Currently, 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 is paid by the unitholders. The proposals would result in a two-
    tiered tax structure whereby distributions would first be subject to a
    31.5 percent at the Trust level commencing in 2011 and then investors
    would be subject to tax on the distribution as if it were a taxable
    dividend paid by a taxable Canadian corporation. If enacted, the
    proposals would apply to the Trust effective January 1, 2011. The Trust
    is currently assessing various alternatives with respect to the potential
    implications of the tax proposals; however, until the legislation is
    enacted in final form, the Trust will not arrive at a final conclusion
    with respect to future Trust structure and implications to the Trust. As
    the tax proposals had not been substantively enacted as of December 31,
    2006, the consolidated financial statements do not reflect the impact of
    the proposed taxation.

    6.  ASSET RETIREMENT OBLIGATIONS

    At December 31, 2006, the estimated total undiscounted amount required to
    settle the asset retirement obligations was $46,434,000 (2005 -
    $39,921,000). Costs for asset retirement have been calculated assuming a
    5 percent inflation rate for 2007, 4 percent for 2008, 3 percent for 2009
    and 2 percent thereafter. These obligations will be settled based on the
    useful lives of the underlying assets, which extend up to 40 years into
    the future. This amount has been discounted using a credit-adjusted risk-
    free interest rate of 5 (2005 - 5) percent.

    Changes to asset retirement obligations were as follows:

                                                     2006           2005
    -------------------------------------------------------------------------
    Asset retirement obligations, January 1      $ 13,195,000   $ 11,419,000
    Adjustment to asset retirement obligations      1,726,000        233,000
    Acquisition of Novitas                                  -      1,198,000
    Liabilities settled during the year              (762,000)      (275,000)
    Accretion                                         660,000        620,000
    -------------------------------------------------------------------------
    Asset retirement obligations, December 31    $ 14,819,000   $ 13,195,000
    -------------------------------------------------------------------------

    7.  UNIT CAPITAL

    Authorized

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

                                 2006                        2005

    Issued                Number        Amount        Number        Amount
    -------------------------------------------------------------------------
    Trust Units

    Balance,
     beginning
     of year            16,535,158  $ 83,900,000    14,943,405  $ 75,486,000
    Transfer of
     contributed
     surplus to Unit
     capital                     -       427,000             -       169,000
    Units issued on
     acquisition of
     Novitas                     -             -     1,335,753     5,681,000
    Unit issue costs
     on acquisition
     of Novitas                  -             -             -      (259,000)
    Issued pursuant
     to Trust unit
     option plan           339,500     5,161,000       256,000     2,823,000
    -------------------------------------------------------------------------
    Balance, end
     of year            16,874,658  $ 89,488,000    16,535,158  $ 83,900,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The number of trust units used to calculate diluted net earnings per unit
    for the year ended December 31, 2006 of 16,880,422 (2005 - 16,594,260)
    included the basic weighted average number of units outstanding of
    16,737,651 (2005 - 16,388,621) plus 142,771 (2005 - 205,639) units
    related to the dilutive effect of unit options.

    The deficit balance is composed of the following items:

                                                     2006           2005
    -------------------------------------------------------------------------
    Accumulated earnings                         $122,406,000   $ 85,156,000
    Accumulated cash distributions               (159,651,000)  (112,370,000)
    -------------------------------------------------------------------------
    Deficit                                      $(37,245,000)  $(27,214,000)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Trust provides an option plan for its directors, officers, employees
    and consultants. Under the plan, the Trust may grant options for up to
    1,670,000 (2005 - 1,635,000) 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, 2006 and 2005, and changes during the years is presented
    below:

                                     2006                      2005
    -------------------------------------------------------------------------
                                          Weighted-                 Weighted-
                                           Average                   Average
                                          Exercise                  Exercise
                              Options       Price       Options       Price
    -------------------------------------------------------------------------
    Outstanding at beginning
     of year                  646,000       $18.67      565,000       $11.56
    Options granted           447,000        29.18      407,000        23.32
    Options exercised        (339,500)       15.20     (256,000)       11.03
    Options cancelled         (32,000)       24.70      (70,000)       16.35
    -------------------------------------------------------------------------
    Outstanding at
     end of year              721,500       $26.55      646,000       $18.67
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Options exercisable
     at end of year           212,500       $22.62      214,000       $10.89
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following table summarizes information about unit options outstanding
    at December 31, 2006:

                        Options Outstanding            Options Exercisable
                ----------------------------------  -------------------------
                  Number    Weighted-
                   Out-      Average      Weighted-     Number      Weighted-
                standing    Remaining     Average    Exercisable    Average
                    At     Contractual    Exercise        At        Exercise
                12/31/06      Life         Price       12/31/06      Price
    -------------------------------------------------------------------------
    $15.20        31,000    0.5 years       $15.20       19,000       $15.20
    $22.45-
     $23.35      251,500    2.3 years        23.32      193,500        23.35
    $28.70-
     $28.75      399,000    2.2 years        28.75            -            -
    $32.00-
     $33.75       40,000    3.0 years        33.55            -            -
    -------------------------------------------------------------------------
    $15.20-
     $33.75      721,500    2.1 years       $26.55      212,500       $22.62
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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 447,000 unit options with an estimated
    fair value of $1,193,000 ($2.67 per option) using the Black-Scholes
    option pricing model with the following key assumptions:

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

    8.  RELATED PARTY TRANSACTIONS

    The Trust received a management fee from Comaplex of $300,000 (2005 -
    $240,000) 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, 2006, the Trust had an account receivable from
    Comaplex of $38,000 (December 31, 2005 - $29,000).

    The Trust received a management fee from Pine Cliff of $216,000 (2005 -
    $132,000) 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, 2006 the Trust had an account receivable from Pine
    Cliff of Nil (December 31, 2005 - $165). As at December 31, 2006, the
    Trust had an account payable of Nil (December 31, 2005 - $16,000) to Pine
    Cliff. The 2005 amount owing was related to outstanding post closing
    adjustment items for the sale of properties to Pine Cliff (see note 3).

    9.  FINANCIAL INSTRUMENTS

    Fair Values

    The Trust's financial instruments included in the balance sheet are
    comprised of 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.

    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.

    10. COMMITMENTS, CONTINGENCIES AND GUARANTEES

    The Trust entered into the following commodity hedging transactions in
    2006 for a portion of its 2007 and 2008 production:


                                          Volume
    Period of Agreement    Commodity      per day   Index    Price (Cdn.)
    -------------------    ---------      -------   -----    ------------
    January 1, 2007        Crude Oil    500 barrels   WTI   Floor of $74.55
     to June 30, 2007                                        and ceiling of
                                                             $85.00 per
                                                             barrel
    January 1, 2007        Crude Oil    500 barrels   WTI   Floor of $75.00
     to June 30, 2007                                        and ceiling of
                                                             $95.47 per
                                                             barrel
    July 1, 2007 to        Crude Oil    500 barrels   WTI   Floor of $75.00
     December 31, 2007                                       and ceiling of
                                                             $93.00 per
                                                             barrel
    July 1, 2007 to        Crude Oil    500 barrels   WTI   Floor of $70.00
     December 31, 2007                                       and ceiling of
                                                             $80.06 per
                                                             barrel
    November 1, 2006     Natural Gas     2,000 GJ's  AECO   Floor of $6.65
     to March 31, 2007                                       and ceiling of
                                                             $12.50 per GJ
    December 1, 2006     Natural Gas     1,500 GJ's  AECO   Floor of $6.00
     to March 31, 2007                                       and ceiling of
                                                             $9.65 per GJ
    April 1, 2007        Natural Gas     2,000 GJ's  AECO   $6.52 per GJ
     to July 31, 2007
    April 1, 2007 to     Natural Gas     1,000 GJ's  AECO   Floor of $6.50
     October 31, 2007                                        and ceiling of
                                                             $9.20 per GJ
    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

    As at December 31, 2006 the fair value of the outstanding commodity
    hedging contracts was a net asset of $1,189,000 (December 31, 2005 -
    ($1,349,000)).

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

    Contract                     Less than     1 - 3     4 - 5        After
    Obligations     Total        1 year        years     years       5 years
    -------------------------------------------------------------------------
    Office lease    $1,963,000   $283,000    $910,000   $656,000    $114,000
    
    %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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