Bonterra Energy Income Trust Announces Third Quarter Results



    CALGARY, Nov. 14 /CNW/ - Bonterra Energy Income Trust
(www.bonterraenergy.com) (TSX:BNE.UN) is pleased to announce its financial and
operational results for the nine months ended September 30, 2007.

    
    HIGHLIGHTS
    ----------
                                       Three Months Ended  Nine Months Ended
                                          September 30        September 30
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    FINANCIAL ($000, except $ per unit)
    Revenue - oil and gas               23,794    23,665    69,858    67,015
    Adjusted Distribution Base(1)       13,149    14,401    37,973    40,562
      Per Unit - Basic                    0.78      0.86      2.25      2.43
      Per Unit - Diluted                  0.77      0.85      2.24      2.40
    Net Earnings                         9,086    10,441    22,430    30,779
      Per Unit - Basic                    0.54      0.62      1.33      1.84
      Per Unit - Diluted                  0.53      0.62      1.32      1.82
    Cash Distributions per Unit           0.66      0.72      1.98      2.10
    Capital Expenditures and
     Acquisitions                        2,763    12,597    12,087    28,891
    Total Assets                                           138,140   130,655
    Working Capital Deficiency(2)                           50,041    38,853
    Unitholders Equity                                      50,820    60,387
    -------------------------------------------------------------------------
    OPERATIONS
    Oil and NGL's
      Barrels Per Day                    3,054     3,024     3,118     3,007
      Average Price ($ per barrel)       73.68     71.11     67.87     66.06
    Natural Gas
      MCF Per Day                        6,196     5,925     6,442     6,059
      Average Price ($ per MCF)           5.47      6.95      6.77      7.54
    Total Barrels per Day                4,088     4,012     4,192     4,017

    (1) Adjusted distribution base (formally funds flow from operations) is
        not a recognized measure under GAAP. Management believes that in
        addition to net earnings, adjusted distribution base is a useful
        supplemental measure as it demonstrates the Trust's ability to
        generate the cash necessary to make trust distributions, repay debt
        or fund future growth through capital investment. Investors are
        cautioned, however, that this measure should not be construed as an
        indication of the Trust's performance. The Trust's method of
        calculating this measure may differ from other issuers and
        accordingly, it may not be comparable to that used by other issuers.
        For these purposes, the Trust defines adjusted distribution base as
        funds provided by operations before changes in non-cash operating
        working capital items excluding gain on sale of property and asset
        retirement expenditures. The Canadian Institute of Chartered
        Accountants ("CICA") recently published recommendations regarding
        disclosure of a measure called Standardized Distributable Cash. For
        details kindly refer to Analysis of Relationship between Standardized
        Distributable Cash, Distributions, and Investing and Financing
        Activities in this report.

    (2) Includes 100 percent of debt.

    (3) 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.
    

    Forward-looking Information
    ---------------------------
    Certain statements contained in this press release include statements
which contain words such as "anticipate", "could", "should", "expect", "seek",
"may", "intend", "likely", "will", "believe" and similar expressions, relating
to matters that are not historical facts, and such statements of our beliefs,
intentions and expectations about development, results and events which will
or may occur in the future, constitute "forward-looking information" within
the meaning of applicable Canadian securities legislation and are based on
certain assumptions and analysis made by us derived from our experience and
perceptions. Forward-looking information in this press release includes, but
is not limited to: expected cash provided by continuing operations; cash
distributions; future capital expenditures, including the amount and nature
thereof; oil and natural gas prices and demand; expansion and other
development trends of the oil and gas industry; business strategy and outlook;
expansion and growth of our business and operations; and maintenance of
existing customer, supplier and partner relationships; supply channels;
accounting policies; credit risks; and other such matters.
    All such forward-looking information is based on certain assumptions and
analyses made by us in light of our experience and perception of historical
trends, current conditions and expected future developments, as well as other
factors we believe are appropriate in the circumstances. The risks,
uncertainties, and assumptions are difficult to predict and may affect
operations, and may include, without limitation: foreign exchange
fluctuations; equipment and labour shortages and inflationary costs; general
economic conditions; industry conditions; changes in applicable environmental,
taxation and other laws and regulations as well as how such laws and
regulations are interpreted and enforced; the ability of oil and natural gas
trusts to raise capital; the effect of weather conditions on operations and
facilities; the existence of operating risks; volatility of oil and natural
gas prices; oil and gas product supply and demand; risks inherent in the
ability to generate sufficient cash flow from operations to meet current and
future obligations; increased competition; stock market volatility;
opportunities available to or pursued by us; and other factors, many of which
are beyond our control.
    Actual results, performance or achievements could differ materially from
those expressed in, or implied by, this forward-looking information and,
accordingly, no assurance can be given that any of the events anticipated by
the forward-looking information will transpire or occur, or if any of them do,
what benefits will be derived therefrom. Except as required by law, Bonterra
disclaims any intention or obligation to update or revise any forward-looking
information, whether as a result of new information, future events or
otherwise.
    The forward-looking information contained herein is expressly qualified
by this cautionary statement.

    General
    -------
    Bonterra is pleased to report its results for the first nine months
of 2007. Oil and natural gas revenue increased by four percent from
$67,015,000 in the 2006 nine month period to $69,858,000 for the 2007 nine
month period. The increase is mainly attributable to an increase in crude oil
pricing (offset partially by lower natural gas prices as well as an increase
in production volumes of 4.4 percent to 4,192 barrels of oil equivalent
(BOE's) from 4,017 BOE's for the comparable nine month period.
    Adjusted distribution base (formally funds flow from operations) and net
earnings decreased by 6 and 27 percent respectively in 2007 compared to the
results from the first nine months of 2006. Both reductions were impacted by
second quarter one time issues that related to prior periods. The second
quarter one time issues that affected net earnings and adjusted distribution
base consisted of an approximate $750,000 royalty adjustment for 2005 and,
2006 and extra operating costs and reworking costs to existing producing and
non-producing wells that will assist in increased production volumes in future
quarters.
    Other cash items that had a negative impact on adjusted distribution base
and net earnings were an approximate $2,297,000 increase in operating costs,
an interest expense increase of $1,082,000 and the elimination of Alberta
royalty tax credits resulting in a reduction of revenue of $484,000 and no
gain on sale of property in 2007 compared to a 2006 gain of $532,000.
    Production volumes in Q3 were a little lower than budgeted, mainly due to
overall weather related low production in July, and production problems for
most of the quarter in the Peck Lake area of Saskatchewan (which has been
corrected in Q4). Also production from new wells that are higher volume
producers at higher pressures are overloading existing gathering systems and
in some areas it is reducing production from older low pressure wells.
Bonterra is presently dealing with this issue by reducing production volumes
from some of its new wells. On a long term basis Bonterra will attempt to
improve upon the issue by renting space on other companies gathering systems
or by increasing compression in its own system.
    These negatives more than offset the increase in oil and gas revenues
(including hedging adjustments) of $2,843,000. Net earnings were also affected
by an increase in non-cash items of $1,552,000 of depletion, depreciation and
accretion, dry hole costs of $1,720,000 and additional future income taxes of
$2,345,000 resulting from the Federal Governments legislated change in how
income trusts will be taxed.
    The above items also had an impact on the payout ratio for the first nine
months of 2007 resulting in a payout ratio of 88 percent compared to an
objective of 80 percent. The elimination of one time charges as well as
increasing commodity prices should assist in improving upon this ratio for the
balance of 2007. Bonterra's production consists of approximately 75 percent
crude oil (most of which is light sweet gravity crude) and therefore is
benefiting from the current strong crude oil pricing.
    At September 30, 2007, Bonterra had 4 gross (3.2 net) Cardium oil wells,
6 gross (4.5 net) natural gas wells, and 4 gross (3.5 net) coal-bed methane
wells (CBM) drilled but not on production. The Trust anticipates completing
and tying-in 3 gross (2.4 net) Cardium wells as well as 3 gross (1.7 net)
shallow gas wells by the end of Q4 2007. The Trust is currently examining the
recompletion of one (.8 net) Cardium well and intends to have it on production
by spring 2008. The remaining natural gas wells and CBM wells will not be tied
in until later in 2008.
    While service costs continue to be high, Bonterra will continue to focus
more on directing capital expenditures towards completions, tie-ins, reworking
of existing wells, recompletions of gas zones to take advantage of new
commingling regulations for gas wells, and refracing of existing Cardium oil
wells rather than just drilling new wells. Exceedingly wet weather during the
second and third quarters delayed the implementation of the above however, the
Trust still anticipates capital expenditure for 2007 to be $20 million. The
Trust commenced in late October with its fall drill program and anticipates
the drilling of 8 gross (7.9 net) Cardium oil wells by the end of the year.
    The Trust continues to have upside potential by continuing to drill and
develop its large inventory of undrilled locations and potentially from
additional recovery of oil in place by water flooding, CO(2) sequestration,
and by reworking and refracing existing producing and suspended wells.
    With regard to dealing with the federal taxation changes that were
announced on October 31, 2006 and now have been legislated, Bonterra is
evaluating the implications and various alternatives that are available to
mitigate the impact of the additional taxes commencing in 2011. One of the
difficult issues that has to be dealt with is that Bonterra has three types of
unitholders that are affected differently; being Canadian resident unitholders
that hold the units outside of tax shelters (approximately 60 percent),
Canadian resident unitholders that hold units within tax shelters
(approximately 18 percent) and foreign unitholders (approximately 22 percent).
Generally what is beneficial for one type of unitholder may be detrimental to
other types of unitholders.
    The recent announcement by the Alberta provincial government regarding
changes to the royalty tax structure is expected to have little or no effect
to the Trust. The Trust current production mix is predominantly low producing
oil and natural gas wells that will be least affected by the royalty
adjustment. Additional oil royalties that will be payable as a result of the
currently high oil prices should be offset by reductions in natural gas
royalties due to the low production status of most of the Trust's natural gas
production.

    Financial and Operational Discussion
    ------------------------------------

    Production
    ----------
    The Trust drilled 7 gross (6.4 net) Cardium oil wells and 2 gross
(0.7 net) shallow gas wells in the first nine months of 2007 on its operated
lands. As at September 30, 2007 Bonterra had 4 gross (3.2 net) Cardium oil
wells, 6 gross (4.5 net) natural gas wells and 4 gross (3.5 net) coal-bed
methane ("CBM") wells drilled but not on production on its operated lands.
During the first nine months of 2007, the Trust tied-in 15 gross (13 net)
Cardium wells and 5 gross (2.8 net) natural gas wells on its operated lands.
    As of the date of this report a further 100 percent owned Cardium well
has been placed on production and management anticipates that 2 (1.4 net) of
the remaining drilled but not producing Cardium wells will be completed and
tied-in by the end of the fourth quarter of 2007. Three gross (1.7 net) of the
natural gas wells are anticipated to be completed and tied-in by the end of
the fourth quarter of 2007. The remaining shallow gas wells and CBM wells will
not be completed and tied-in in 2007 for various reasons, including landowner
issues, regulatory factors, gathering system capacity and line pressure
issues.
    The reduction in natural gas volumes is primarily due to operational
problems at the Trusts Peck Lake property. Production from this area was down
225 MCF per day during the quarter. The production problem at Peck Lake has
been rectified with production returning to approximately 80 percent of the
field's first quarter levels in late October. Overall production rates in the
third quarter of 2007 were affected by unseasonably wet summer weather
resulting in the inability to perform maintenance on wells as well as higher
initial declines in production on the newly completed Cardium oil wells which
is a normal happening for new Cardium wells.
    On October 30, 2007, the Trust completed an asset exchange agreement
whereby it disposed of its entire interest in the Dodsland area of
Saskatchewan properties in exchange for 100 percent interests in approximately
30 producing wells and an additional interest in an operated property all
located in the Pembina area of Alberta. The exchange will have no impact on
total production as the Dodsland properties were producing approximately
265 BOE per day and the acquired properties are expected to produce
approximately 270 BOE per day. However, the newly acquired properties are
expected to produce approximately 185 barrels per day of crude oil and natural
gas liquids and approximately 500 MCF per day of natural gas whereas the
Dodsland properties produced 245 barrels per day of crude oil and natural gas
liquids and only 110 MCF per day of natural gas.
    The exchange allows the Trust to increase its presence in the Pembina
area of Alberta allowing for further consolidation of its operations including
the tieing in of two (1.4 net) Cardium wells (see above). It should also
result in a significant reduction in the Trust's operating costs as the
acquired properties are anticipated to have operating costs in the $18 per BOE
range verses $37 plus per BOE for the Dodsland assets. The exchange also
reduces the number of wells owned by the Trust as the Dodsland property
contained in excess of 400 wells whereas the Pembina properties acquired have
approximately 40 total wells. The exchange will also result in a slightly
higher average royalty rate as the newly acquired properties have a royalty
rate of approximately 12 percent compared to 2.5 percent for the Dodsland
properties. Overall it is expected that this property exchange will be neutral
from a cash flow perspective.

    Revenue
    -------
    Revenue from petroleum and natural gas sales was $69,858,000
(2006 - $67,015,000). The increase in revenue over the 2006 first nine months
was primarily due to additional production from the wells drilled during 2006
and spring of 2007. The average price received for crude oil and natural gas
liquids during the first nine months of 2007 was $67.87 ($73.68 in the third
quarter) per barrel and $6.77 ($5.47 in the third quarter) per MCF for natural
gas compared to $66.06 per barrel and $7.54 per MCF in the corresponding 2006
period. On a quarter over quarter basis, revenue increased by $332,000 due
primarily to increased crude oil prices from second quarter pricing of $67.60
offset partially by reduced production volumes.

    Royalties
    ---------
    During the second quarter of 2007, two significant royalty adjustments
were recorded. Firstly, the Trust discovered that the production limit,
resulting in additional gross overriding royalty in respect of certain of its
Cardium oil wells, had been reached. The production limit was calculated on a
multitude of Cardium wells including several that were not owned by the Trust.
In addition the exact wells that the production limit was applicable to was
not readily known by the Trust nor easily determined. In discussions with the
payee it was determined that the production limit was reached in late 2005.
The royalty has been calculated based on this agreed date and the affected
wells for Bonterra and other operators in the area were identified. The
approximate amount of the adjustment, net to the Trust is $700,000 for periods
prior to April 1, 2007. The monthly amount of the royalty on a go forward
basis is approximately $40,000 per month based on current pricing and
production levels.
    Secondly, the Trust was informed by the operator of one of its
non-operated properties that it had not charged a net profit royalty for the
years 2004, 2005 and 2006. In review of the agreements it was confirmed no
payment was made and an amount of approximately $150,000 was accrued by the
Trust for payment of such net profit royalty.
    Royalties paid by the Trust consist of Crown royalties paid to the
Provinces of Alberta and Saskatchewan as well as numerous gross override and
freehold royalties. During the first nine months of 2007 the Trust paid
$6,575,000 (2006 - $6,546,000) in Crown royalties and $2,553,000, which
includes the above described adjustments of $700,000 and $150,000, (2006 -
$1,552,000) 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 9.5 percent (2006 - ten percent) and approximately
2.5 percent (after adjusting for the one time items discussed above) (2006 -
2 percent) for other royalties before hedging adjustments. The previously
discussed property swap will result in a one to two percent increase in the
average royalty rate on a go forward basis. 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 amount of purchased wells; however this program
was discontinued by the Alberta Government effective January 1, 2007 which
resulted in a reduction of revenue of $484,000 in 2007.

    Gain on Sale of Property
    ------------------------
    During the first quarter of 2006, the Trust disposed of a non-operated;
non-core property for gross proceeds of $750,000 (approximately $75,000 per
producing BOE). The Trust follows successful efforts accounting for its oil
and gas properties and therefore reported a gain of $532,000 on the difference
between the depleted value of the property and the above proceeds.

    Production Costs
    ----------------
    Production costs for the nine months ended September 30, 2007 were
$18,538,000 compared to $16,241,000 for the nine months ended
September 30, 2006. On a BOE basis production costs averaged $16.20 in 2007
($17.02 in Q3) verses $14.81 in the corresponding 2006 period. Production
costs in Q3 decreased $155,000 from Q2 due to the Trust performing numerous
maintenance programs on its oil producing facilities and pipelines and the
operator of a number of the Trusts gas plants performing its annual
turnarounds during the second quarter. Costs also have continued to increase
for services related to well workovers.
    The Trust is facing continuing maintenance issues with regard to its
infrastructure to accommodate the additional production resulting from its
2006 and 2007 drill programs resulting in significant additional operational
costs. However, the swap of the Dodsland properties for additional Pembina
properties should result in a reduction of total operating costs on a go
forward basis since operating costs for the Dodsland area have recently been
in the $35.00 range per BOE compared to approximately $14.00 per BOE for
production in the Pembina field.
    The Trust's production comes primarily from low productivity wells. These
wells generally result in higher production costs on a per unit-of-production
basis as costs such as municipal taxes, surface lease, power and personnel
costs are not variable with production volumes. Production costs in the $14 to
$15 per BOE range are expected. The high production costs for the Trust are
substantially offset by low royalty rates of approximately 12.5 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 production
costs.

    General and Administrative Expenses
    -----------------------------------
    General and administrative expenses were $1,864,000 ($773,000 in the
third quarter) in the first nine months of 2007 compared to $1,814,000 in the
nine months ended September 30, 2006 and $527,000 in the three months ended
June 30, 2007. Costs on a BOE basis decreased to $1.63 per BOE in the first
nine months of 2007 compared to $1.65 per BOE in the first nine months of
2006. On a quarter over quarter basis, administrative expenses increased by
$246,000.
    During the third quarter the Trust incurred approximately $275,000 in
professional fees relating to the evaluation of several organizational
options. This review was part of the Trusts continuing examination of means to
address the changes resulting from the federal government's taxation of Trusts
announcement on October 31, 2006. Off-setting these expenditures were
increased recoveries (approximately $240,000) of administration expenses
charged to the Trust's various partners and capital projects. Increases in
employee salary compensation were offset by reduced bonus accruals and a
general reduction in overall office expenditures.

    Interest Expense
    ----------------
    Interest expense increased to $2,150,000 ($709,000 in the third quarter)
for the nine months ended September 30, 2007 compared to $1,068,000 for the
nine months ended September 30, 2006. Increased average debt levels and
increased interest rates were the primary factors in the increase in interest
expense. The Trust's average borrowing rate for 2007 is approximately
5.6 percent compared to 5.5 percent for the first nine months of 2006. Quarter
over quarter saw a decrease of $35,000. Although ending Q3 debt level was
higher than Q2, the average outstanding debt balance was less. The Trust's net
debt as a percentage of annualized third quarter adjusted distribution base
was approximately eleven and a half months which is slightly below the Trust's
goal of one year.

    Unit Based Compensation
    -----------------------
    Unit based compensation is a statistically calculated value representing
the estimated expense of issuing employee unit options. The Trust records a
compensation expense over the vesting period based on the fair value of
options granted to employees, directors and consultants.
    In 2007, the Trust issued 546,000 unit options of which 517,000 were
issued at the end of June 2007 at an average price of $28.31 and a fair value
of $2.75 per unit. The fair value of the options granted has been estimated
using the Black-Scholes option pricing model, assuming a weighted risk free
interest rate of 4.7 (2006 - 4.1) percent, expected weighted average
volatility of 27 percent (2006 - 27), expected weighted average life of
2.5 years (2006 - 2.5) and an annual dividend rate based on the distributions
paid to the Unitholders during the year. As the options were issued at the end
of the second quarter no significant expense in relation to these options was
recorded in Q2. The future unit based compensation impact of these options is
approximately $235,000 per quarter over the next four quarters.

    Depletion, Depreciation and 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. Tangible assets are depreciated over an
expected 10 year life. 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.
    Provision for depletion, depreciation and accretion was $10,278,000 and
$8,726,000 for the nine month periods ending September 30, 2007 and
September 30, 2006 respectively. The increase was primarily due to increased
production resulting from the Trust's 2006 and spring 2007 drill programs. The
Trust continues to replace production declines with newly drilled wells that
have higher capital costs. The Trust has capital costs of approximately $6 per
proven BOE of reserves based on the December 31, 2006 independent engineering
report. The increase in Q3 of $208,000 from Q2 depletion amounts was due to
increased production volumes from newly completed wells resulting in higher
depletion claims per BOE of production.
    During the third quarter, the Trust reviewed its inventory of previously
drilled natural gas and CBM wells. Various tests were performed and based on
these results and continuing low natural gas prices it was determined that six
gross (4.7 net) natural gas and CBM wells did not have sufficient economics to
justify reserves and the capital costs for these wells totalling $1,244,000
were expensed as dry hole costs.

    Income Taxes
    ------------
    On October 31, 2006, the Canadian Federal Government announced a proposed
Trust taxation pertaining to taxation of distributions paid by publicly traded
income trusts and this was enacted by legislation in June 2007. Previously,
distributions paid to unitholders, other than returns of capital, are claimed
as a deduction by the Trust in arriving at taxable income whereby tax is
eliminated at the Trust level and is paid by the unitholders. The June, 2007
legislation results in a two-tiered tax structure whereby distributions
commencing in 2011 would first be subject to a 31.5 percent at the Trust level
tax and then investors would be subject to tax on the distribution as if it
were a taxable dividend paid by a taxable Canadian corporation.
    Future income tax expense for 2007 increased by a one time adjustment of
$3,801,000, with a corresponding increase to the future tax liability, upon
the June 2007 enactment. Until June 2007, the Trust had been tax effecting the
reversal of taxable temporary differences at a nil tax rate on the assumption
that the Trust would make sufficient tax deductible cash distributions to
unitholders such that the Trust's taxable income would be nil for the
foreseeable future and the tax burden would have continued to be with whomever
received the monthly distribution. The new legislation limits the tax
deductibility of cash distributions such that income taxes may become payable
in the future.
    The Trust has estimated its future income taxes based on its best
estimates of results from operations and tax pool claims and cash
distributions in the future assuming no material change to the Trust's current
organizational structure. As currently interpreted, Canadian Generally
Accepted Accounting Principles ("GAAP") does not permit the Trust's estimate
of future income taxes to incorporate any assumptions related to a change in
organizational structure until such structures are given legal effect even
though it is anticipated that many trusts will change their organizational
structure to attempt to reduce this impact.
    The Trust's estimate of its future income taxes will vary as to the
Trust's assumptions pertaining to the factors described above, and such
variations may be material.
    Until 2011, the new legislation does not directly affect the Trust's cash
flow from operations, and accordingly, the Trust's financial condition.
    Currently taxable income earned within the Trust is required to be
allocated to its Unitholders and as such the Trust will not incur any current
taxes. However, the Trust operates its oil and gas interests through its
100 percent owned subsidiaries Bonterra Energy Corp. ("Bonterra Corp.") and
Novitas Energy Ltd. ("Novitas") and these corporations may periodically be
taxable.
    These corporations pay the majority of their income to the Trust through
interest and royalty payments which are deductible for income tax purposes.
The current tax provision relates to resource surcharge payable by the Trusts
subsidiaries to the Province of Saskatchewan. The surcharge is calculated as a
flat percent of revenues generated from the sale of petroleum products
produced in Saskatchewan. The provincial government of Saskatchewan has
reduced the current resource surcharge rate of 3.3 percent to 3.1 percent on
July 1, 2007 and to 3.0 percent on July 1, 2008.
    The Trust's subsidiaries have the following tax pools, which may be used
to reduce taxable income in future years, limited to the applicable rates of
utilization:

    
                                                     Rate of
                                                   Utilization
                                                        %          Amount
    -------------------------------------------------------------------------
    Undepreciated capital costs                         20-100  $ 16,324,000
    Canadian oil and gas property expenditures              10     1,665,000
    Canadian development expenditures                       30    29,526,000
    Canadian exploration expenditures                      100        93,000
    Income tax losses carried forward(1)                   100    16,367,000
    -------------------------------------------------------------------------
                                                                $ 63,975,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Income tax losses carried forward expire in 2014 ($635,000),
        2015 ($3,574,000), 2026 ($4,826,000) and 2027 ($7,332,000).


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


                                                    Rate of
                                                   Utilization
                                                        %          Amount
    -------------------------------------------------------------------------
    Canadian oil and gas property expenditures              10  $ 14,583,000
    Finance costs                                           20       411,000
    Eligible capital expenditures                            7       354,000
    -------------------------------------------------------------------------
                                                                $ 15,348,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Canadian taxable portion of distributions for each taxation year is
calculated on an annual basis and is reported by February 28 of the following
year.

    Net Earnings
    ------------
    Net earnings decreased to $22,430,000 in the first nine months of 2007
from $30,779,000 in the corresponding 2006 period. Revenue increases due to
increased production volumes were generally offset by increased operating
costs, interest expense, depletion, depreciation, accretion and dry hole
costs, and provision for future income taxes. The Trust's quarter over quarter
net earnings increased by $4,646,000 primarily due to future income tax
adjustments.

    Comprehensive Income
    --------------------
    On January 1, 2007 the Trust became obliged to adopt the new accounting
standards regarding the accounting for financial instruments. On adoption the
Trust increased its investment in related party by $1,836,000 for the fair
value of this investment. On January 1, 2007 the Trust further recognized a
current asset of $1,148,000 for the fair value of its commodity derivative
contracts. These adjustments resulted in a further increase in the future
income tax liability and accumulated other comprehensive income of $604,000
and $2,380,000 respectively.
    Other comprehensive income for the nine months included an increase in
the unrealized gain on investment in a related party of $1,170,000 ($542,000
in the third quarter), a reduction of $654,000 ($77,000 in the third quarter)
relating to the recognition and transfer of previously reported hedging gains
in accumulated other comprehensive income and a gain of $202,000 was recorded
in relation to the fair value adjustment on outstanding commodity derivative
contracts. All of the above adjustments are net of applicable income tax
effects.

    Standardized Distributable Cash
    -------------------------------
    Compliance with Guidance

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

    
    Definition and Disclosure of Standardized Distributable Cash

    -------------------------------------------------------------------------
                                                                 Cumulative
                                     Nine Months  Nine Months   Amounts From
                                        Ended         Ended     Inception of
                                      September     September       Trust
                                         2007          2006    (July 1, 2001)
    -------------------------------------------------------------------------
    Cash Flow from Operating
     Activities                     $ 38,064,000  $ 40,019,000  $166,842,000
    -------------------------------------------------------------------------
    Less adjustment for:
      Capital expenditures           (12,087,000)  (28,891,000)  (75,198,000)
    -------------------------------------------------------------------------
      Financing restrictions caused
       by debt                                 -             -             -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Standardized Distributable Cash $ 25,977,000  $ 11,128,000  $ 91,644,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


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

    -------------------------------------------------------------------------
                                                                 Cumulative
                                     Nine Months  Nine Months   Amounts From
                                        Ended         Ended     Inception of
                                      September     September       Trust
                                         2007          2006    (July 1, 2001)
    -------------------------------------------------------------------------
    Standardized Distributable Cash
     - per above                    $ 25,977,000  $ 11,128,000  $ 91,644,000
    -------------------------------------------------------------------------
    Adjusted for:
      Capital expenditures            12,087,000    28,891,000    75,198,000
    -------------------------------------------------------------------------
      Gain on sale of property                 -       532,000     1,089,000
    -------------------------------------------------------------------------
      Changes in accounts receivable    (369,000)     (955,000)    4,494,000
    -------------------------------------------------------------------------
      Changes in crude oil inventory     (33,000)      186,000       304,000
    -------------------------------------------------------------------------
      Changes in parts inventory          41,000      (112,000)     (208,000)
    -------------------------------------------------------------------------
      Changes in prepaid expenses        188,000       604,000       254,000
    -------------------------------------------------------------------------
      Changes in accounts payable
       and accrued liabilities          (450,000)     (105,000)    1,594,000
    -------------------------------------------------------------------------
      Asset retirement obligations
       settled                           532,000       393,000     1,709,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Adjusted Distribution Base
     (formerly Funds Flow from
     Operations)(1)                 $ 37,973,000  $ 40,562,000  $176,078,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Adjusted distribution base (formerly funds flow from operations) is
        not a recognized measure under GAAP. The Trust believes that in
        addition to net earnings, adjusted distribution base is a useful
        supplemental measure as it demonstrates the Trust's ability to
        generate the cash necessary to make trust distributions, repay debt
        or fund future growth through capital investment. Investors are
        cautioned, however, that this measure should not be construed as an
        indication of the Trust's performance. The Trust's method of
        calculating this measure may differ from other issuers and
        accordingly, it may not be comparable to that used by other issuers.
        For these purposes, the Trust defines adjusted distribution base as
        funds provided by operations before changes in non-cash operating
        working capital items excluding gain on sale of property and asset
        retirement obligations.

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


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

    -------------------------------------------------------------------------
                       Nine Months
                          Ended       Year ended    Year ended    Year ended
                        September    December 31,  December 31,  December 31,
                           2007          2006          2005          2004
    -------------------------------------------------------------------------
    Standardized
     Distributable
     Cash              $25,977,000   $13,596,000   $22,316,000   $18,875,000
    -------------------------------------------------------------------------
    Distributions(1)  ($33,474,000) ($47,281,000) ($38,949,000) ($27,088,000)
    -------------------------------------------------------------------------
    Increase in
     bank debt         $11,215,000   $25,202,000   $11,717,000  ($17,969,000)
    -------------------------------------------------------------------------
    Proceeds on
     exercise of
     employee unit
     options           $   845,000   $ 5,161,000   $ 2,823,000   $ 3,292,000
    -------------------------------------------------------------------------
    Issuance of units
     (net of costs
     of issue)                   -             -     ($259,000)  $20,272,000
    -------------------------------------------------------------------------
    Proceeds on sale
     of properties               -   $   750,000   $ 1,097,000             -
    -------------------------------------------------------------------------
    Non cash financing
     and investing
     working capital
     adjustments      ($ 4,563,000)  $ 2,572,000   $ 1,255,000   $ 2,618,000
    -------------------------------------------------------------------------

    (1) Includes distribution declared in October in respect of September
        operations.


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

                                                     Expected
    Year                                           Expenditure
    -----------------------------------------------------------
    2007 (including expenditures incurred to date)  $  695,000
    2008                                               494,000
    2009                                               398,000
    2010                                               986,000
    2011                                               805,000
    -----------------------------------------------------------
    -----------------------------------------------------------
                                                    $3,378,000
    -----------------------------------------------------------
    -----------------------------------------------------------
    

    Definition and History of Productive Capacity and Strategy

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

    
    -------------------------------------------------------------------------
                           Nine Months
                              Ended     Year ended   Year ended   Year ended
                            September  December 31, December 31, December 31,
                              2007         2006         2005         2004
    -------------------------------------------------------------------------
    Proven and probable
     reserves at beginning
     of period (BOE's)     26,476,000   23,870,000   19,711,000   16,529,000
    -------------------------------------------------------------------------
    Reserves added due to
     acquisitions (BOE's)     161,000       16,000    2,393,000            -
    -------------------------------------------------------------------------
    Reserves added due to
     capital expenditures
     (BOE's)                       (1)   4,082,000    3,100,000    4,351,000
    -------------------------------------------------------------------------
    Production during
     period (BOE's)         1,144,000    1,476,000    1,334,000    1,169,000
    -------------------------------------------------------------------------
    Increase in productive
     capacity (BOE's)              (1)   2,606,000    4,159,000    3,182,000
    -------------------------------------------------------------------------
    Reserves per unit
     (fully diluted)           1.50(2)        1.57         1.46         1.39
    -------------------------------------------------------------------------
    Productive capacity
     maintenance
     requirements         $18,200,000  $17,472,000  $ 9,205,000  $ 3,460,000
    -------------------------------------------------------------------------
    Capital expenditures
     for the period       $12,087,000  $38,348,000  $56,703,000  $10,595,000
    -------------------------------------------------------------------------
    Capital expenditures
     in excess of
     maintenance
     requirements         ($6,113,000) $20,876,000  $47,498,000  $ 7,135,000
    -------------------------------------------------------------------------
    Cost of increased
     productive capacity
     (per BOE)                     (1) $      8.01  $     11.42  $      2.24
    -------------------------------------------------------------------------

    (1) The Trust does not update reserve information quarterly.
    (2) Assuming no other additional reserves in 2007.
    

    Financing Strategy

    The Trust maintains a strategy of limiting its debt levels to
approximately one year adjusted distribution base. Bonterra has a long term
goal to retain between 15 to 20 percent of its adjusted distribution base to
finance its capital maintenance expenditures. Over the past years, this level
of retention of adjusted distribution base has proven to be sufficient to
maintain the productive capacity of the Trust. To the extent additional
capital expenditures are incurred to increase reserves, the Trust anticipates
financing them through proceeds received on exercise of employee unit options,
equity placements or from its line of credit.
    Periods may exist where the cost of replacing reserves exceed the level
of funds withheld. However, the Trust with its long life reserves and
relatively low debt levels compared to other income trusts has the flexibility
to increase or decrease its capital commitments depending on commodity prices
and costs of development.
    It is management's strategy to finance the costs of reclamation as well
as potential income taxes (commencing in 2011) resulting from the recently
enacted income trust tax law from the adjusted distribution base. Management
is reviewing various organizational alternatives and operational strategies to
mitigate the impact of the new tax.

    Compliance with Financial Covenants

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

    
    Per Unit and Ratio Disclosures

                                                                 Cumulative
                                                                   Amounts
                                                               From Inception
                                                                  of Trust
                                     Nine Months   Nine Months (July 1, 2001)
                                        Ended         Ended          to
                                      September     September    December 31,
                                        2007          2006          2006
    -------------------------------------------------------------------------
    Standardized Distributable Cash $ 25,977,000  $ 11,128,000  $ 91,644,000
    -------------------------------------------------------------------------
    Per weighted average unit       $       1.54  $       0.67  $       6.11
    -------------------------------------------------------------------------
    Per fully diluted unit          $       1.53  $       0.66  $       6.06
    -------------------------------------------------------------------------
    Cash distributions(1)           $ 33,474,000  $ 35,132,000  $159,651,000
    -------------------------------------------------------------------------
    Payout ratio                            1.29          3.16          1.74
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Adjusted Distribution Base      $ 37,973,000  $ 40,562,000  $176,078,000
    -------------------------------------------------------------------------
    Per weighted average unit       $       2.25  $       2.43  $      11.75
    -------------------------------------------------------------------------
    Per fully diluted unit          $       2.24  $       2.40  $      11.64
    -------------------------------------------------------------------------
    Cash distributions(1)           $ 33,474,000  $ 35,132,000  $159,651,000
    -------------------------------------------------------------------------
    Payout ratio                            0.88          0.87          0.91
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes distribution declared in October 2007 and 2006 in respect of
        September 2007 and 2006 operations respectively.
    

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


    Tax Attributes of Distributions and the Trust's Assets

    See discussion under Income Taxes.

    Cash Netback
    ------------
    The following table illustrates the Trust's cash netback per BOE for the
nine month periods ending in September 2006 and 2007 (The 2007 netback
includes one time charges to royalties and field operating costs as described
above in this report):

    
                                          September 30  September 30
    $ per Barrel of Oil Equivalent (BOE)          2007          2006
    -----------------------------------------------------------------
    Production volumes (BOE)                 1,144,307     1,096,723
    Gross production revenue              $      61.05  $      61.11
    Royalties                                    (7.98)        (6.94)
    Field operating                             (16.20)       (14.81)
    -----------------------------------------------------------------
    Field netback                                36.87         39.36
    General and administrative                   (1.63)        (1.65)
    Interest and taxes                           (2.09)        (1.24)
    -----------------------------------------------------------------
    Cash netback                          $      33.15  $      36.47
    -----------------------------------------------------------------
    -----------------------------------------------------------------


    The following table illustrates the Trust's cash netback per BOE for the
three month periods ending September 30 and June 30, 2007 (The June 30 netback
includes one time charges to royalties and field operating costs as described
above in this report):


                                          September 30       June 30
    $ per Barrel of Oil Equivalent (BOE)          2007          2007
    -----------------------------------------------------------------
    Production volumes (BOE)                   375,962       380,891
    Gross production revenue              $      63.29  $      61.61
    Royalties                                    (7.13)       (10.16)
    Field operating                             (17.02)       (17.21)
    -----------------------------------------------------------------
    Field netback                                39.14         34.24
    General and administrative                   (2.06)        (1.38)
    Interest and taxes                           (2.12)        (2.17)
    -----------------------------------------------------------------
    Cash netback                          $      34.96  $      30.69
    -----------------------------------------------------------------
    -----------------------------------------------------------------
    

    Liquidity and Capital Resources
    -------------------------------
    During the first nine months of 2007, the Trust incurred capital costs of
$12,087,000. The Trust drilled 7 gross (6.4 net) Cardium oil wells and 2 gross
(0.7 net) shallow gas wells in the first nine months of 2007 on its operated
lands.
    The Trust currently has plans to drill a total of 17 gross (15 net) wells
in 2007 (8 wells will be drilled in Q4). Total capital cost of approximately
$20,000,000 is budgeted for 2007. The capital expenditures will be funded from
the adjusted distribution base, the Trust's lines of credit and funds from the
exercising of employee unit options.
    The Trust through its operating subsidiaries has a bank revolving credit
facility of $69,900,000 at September 30, 2007 (December 31, 2006 -
$49,900,000). The credit facilities carry an interest rate of Canadian
chartered bank prime.

    The TSX does not accept responsibility for the adequacy or accuracy of
    this release.

    
    BONTERRA ENERGY INCOME TRUST
    CONSOLIDATED BALANCE SHEETS
    As at September 30, 2007 (unaudited) and December 31, 2006

                                                      2007          2006
    -------------------------------------------------------------------------
    Assets
    Current
      Accounts receivable                         $  9,124,000  $ 10,486,000
      Crude oil inventory                              790,000       843,000
      Parts inventory                                  155,000       114,000
      Prepaid expenses                               1,274,000     1,086,000
      Derivative asset (Note 1)                        511,000             -
      Investments in related party (Notes 1 and 2)   3,669,000       461,000
    -------------------------------------------------------------------------
                                                    15,523,000    12,990,000
    -------------------------------------------------------------------------
    Property and Equipment (Note 3)
      Petroleum and natural gas properties
       and related equipment                       186,526,000   176,602,000
      Accumulated depletion and depreciation       (63,909,000)  (54,650,000)
    -------------------------------------------------------------------------
                                                   122,617,000   121,952,000
    -------------------------------------------------------------------------
                                                  $138,140,000  $134,942,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current
      Distributions payable                       $          -  $  4,050,000
      Accounts payable and accrued liabilities       8,970,000    13,748,000
      Debt (Note 4)                                 56,594,000    45,379,000
    -------------------------------------------------------------------------
                                                    65,564,000    63,177,000
    Future Income Tax Liability (Note 5)             6,914,000     3,587,000
    Asset Retirement Obligations                    14,842,000    14,819,000
    -------------------------------------------------------------------------
                                                    87,320,000    81,583,000
    -------------------------------------------------------------------------
    Commitments (Note 9)
    Unitholders' Equity (Note 6)
      Unit capital                                  90,426,000    89,488,000
      Contributed surplus                            1,863,000     1,116,000
    -------------------------------------------------------------------------
                                                    92,289,000    90,604,000
    -------------------------------------------------------------------------
      Deficit                                      (44,567,000)  (37,245,000)
      Accumulated other comprehensive income
       (Note 7)                                      3,098,000             -
    -------------------------------------------------------------------------
                                                   (41,469,000)  (37,245,000)
    -------------------------------------------------------------------------
                                                    50,820,000    53,359,000
    -------------------------------------------------------------------------
                                                  $138,140,000  $134,942,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    BONTERRA ENERGY INCOME TRUST
    CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
    For the periods ended September 30 (unaudited)

                              Three Months                Nine Months
                           2007          2006          2007         2006
    -------------------------------------------------------------------------
    Revenue
      Oil and gas
       sales           $23,685,000   $23,269,000   $68,934,000   $67,710,000
      Hedging gain
       (loss)              109,000       396,000       924,000      (695,000)
      Royalties         (2,682,000)   (2,647,000)   (9,128,000)   (8,098,000)
      Gain on sale
       of property               -             -             -       532,000
      Alberta royalty
       tax credits               -       149,000             -       484,000
      Interest and
       other                 9,000         4,000        42,000        39,000
    -------------------------------------------------------------------------
                        21,121,000    21,171,000    60,772,000    59,972,000
    -------------------------------------------------------------------------
    Expenses
      Production costs   6,401,000     5,689,000    18,538,000    16,241,000
      General and
       administrative      773,000       570,000     1,864,000     1,814,000
      Interest on debt     709,000       414,000     2,150,000     1,068,000
      Unit based
       compensation        437,000       332,000       840,000       697,000
      Dry hole costs     1,244,000             -     1,720,000             -
      Depletion,
       depreciation
       and accretion     3,492,000     3,219,000    10,278,000     8,726,000
    -------------------------------------------------------------------------
                        13,056,000    10,224,000    35,390,000    28,546,000
    -------------------------------------------------------------------------
    Earnings before
     Income Taxes        8,065,000    10,947,000    25,382,000    31,426,000
    -------------------------------------------------------------------------
    Income Taxes
     (Recovery)
      Current               89,000        97,000       247,000       287,000
      Future            (1,110,000)      409,000     2,705,000       360,000
    -------------------------------------------------------------------------
                        (1,021,000)      506,000     2,952,000       647,000
    -------------------------------------------------------------------------
    Net Earnings for
     the Period          9,086,000    10,441,000    22,430,000    30,779,000
    Deficit at beginning
     of period         (42,489,000)  (26,065,000)  (37,245,000)  (27,214,000)
    Distributions
     declared          (11,164,000)  (11,899,000)  (29,752,000)  (31,088,000)
    -------------------------------------------------------------------------
    Deficit at End
     of Period        ($44,567,000) ($27,523,000) ($44,567,000) ($27,523,000)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Earnings per
     Trust Unit -
     Basic (Note 6)    $      0.54   $      0.62   $      1.33   $      1.84
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Earnings per
     Trust Unit -
     Diluted (Note 6)  $      0.54   $      0.62   $      1.32   $      1.82
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    BONTERRA ENERGY INCOME TRUST
    CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
    For the periods ended September 30 (unaudited)

                              Three Months                Nine Months
                           2007          2006          2007         2006
    -------------------------------------------------------------------------
    Unitholders'
     equity, beginning
     of period         $51,920,000   $61,202,000   $53,359,000   $57,322,000
    Comprehensive
     income for the
     period              9,487,000    10,441,000    23,148,000    30,779,000
    Adjustment of
     opening accumulated
     comprehensive
     income (Note 1)             -             -     2,380,000             -
    Net capital
     contributions         140,000       311,000       845,000     2,677,000
    Unit based
     compensation
     adjustment            437,000       332,000       840,000       697,000
    Distributions
     declared          (11,164,000)  (11,899,000)  (29,752,000)  (31,088,000)
    -------------------------------------------------------------------------
    Unitholders'
     Equity, End of
     Period            $50,820,000   $60,387,000   $50,820,000   $60,387,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    BONTERRA ENERGY INCOME TRUST
    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
    For the periods ended September 30 (unaudited)

                                                   Three Months  Nine Months
                                                       2007          2007

    Net Earnings for the Period                    $ 9,086,000   $22,430,000
    Other comprehensive income, net of tax

    Unrealized gains and losses on investments
     (net of income taxes; Three months ended
     - $93,000, Nine months ended $202,000)            542,000     1,170,000
    -------------------------------------------------------------------------
    Gains and losses on derivatives designated as
     cash flow hedges (net of income taxes;
     Three months ended ($26,000),
     Nine months ended $83,000)                        (64,000)      202,000
    Gains and losses on derivatives designated
     as cash flow hedges in prior periods
     transferred to net earnings in the current
     period (net of income taxes; Three Months
     ended - ($32,000), Nine Months ended
     - ($268,000))                                     (77,000)     (654,000)
    -------------------------------------------------------------------------
    Changes in gains and losses on derivatives
     designated as cash flow hedges (net of
     income taxes; Three months ended ($58,000),
     Nine months ended ($185,000))                    (141,000)     (452,000)
    -------------------------------------------------------------------------
    Other Comprehensive Income                         401,000       718,000
    -------------------------------------------------------------------------
    Comprehensive Income                           $ 9,487,000   $23,148,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    BONTERRA ENERGY INCOME TRUST
    CONSOLIDATED STATEMENTS OF CASH FLOWS
    For the periods ended September 30 (unaudited)

                              Three Months                 Nine Months
                           2007          2006          2007          2006
    -------------------------------------------------------------------------
    Operating Activities
      Net earnings for
       the period      $ 9,086,000   $10,441,000   $22,430,000   $30,779,000
      Items not
       affecting cash
        Gain on sale
         of property             -             -             -      (532,000)
        Unit based
         compensation      437,000       332,000       840,000       697,000
        Dry hole costs   1,244,000             -     1,720,000             -
        Depletion,
         depreciation
         and accretion   3,492,000     3,219,000    10,278,000     8,726,000
        Future income
         taxes
         (recovery)     (1,110,000)      409,000     2,705,000       360,000
    -------------------------------------------------------------------------
                        13,149,000    14,401,000    37,973,000    40,030,000
    -------------------------------------------------------------------------
      Change in non-cash
       operating working
       capital
        Accounts
         receivable       (230,000)      665,000       369,000       955,000
        Crude oil
         inventory         (32,000)      (33,000)       33,000      (186,000)
        Parts inventory    (65,000)      116,000       (41,000)      112,000
        Prepaid expenses   266,000       (73,000)     (188,000)     (604,000)
        Accounts payable
         and accrued
         liabilities      (979,000)     (710,000)      450,000       105,000
      Asset retirement
       obligations
       settled            (223,000)     (268,000)     (532,000)     (393,000)
    -------------------------------------------------------------------------
                        (1,263,000)     (303,000)       91,000       (11,000)
    -------------------------------------------------------------------------
    Cash Provided by
     Operating
     Activities         11,886,000    14,098,000    38,064,000    40,019,000
    -------------------------------------------------------------------------
    Financing
     Activities
      Increase in debt   1,993,000     6,183,000    11,215,000    17,525,000
      Unit option
       proceeds            140,000       311,000       845,000     2,677,000
      Unit
       distributions   (11,164,000)  (11,899,000)  (33,802,000)  (34,726,000)
    -------------------------------------------------------------------------
    Cash Used in
     Financing
     Activities         (9,031,000)   (5,405,000)  (21,742,000)  (14,524,000)
    -------------------------------------------------------------------------
    Investing Activities
      Property and
       equipment
       expenditures     (2,763,000)  (12,597,000)  (12,087,000)  (28,891,000)
      Proceeds on sale
       of properties             -             -             -       750,000
      Change in non-cash
       working capital
        Accounts
         receivable              -       379,000       993,000      (342,000)
        Accounts payable
         and accrued
         liabilities       (92,000)    3,525,000    (5,228,000)    2,988,000
    -------------------------------------------------------------------------
    Cash Used in
     Investing
     Activities         (2,855,000)   (8,693,000)  (16,322,000)  (25,495,000)
    -------------------------------------------------------------------------
    Net Cash Inflow              -             -             -             -
    Cash, beginning
     of period                   -             -             -             -
    -------------------------------------------------------------------------
    Cash, End of
     Period            $         -   $         -   $         -   $         -
    -------------------------------------------------------------------------
    Cash Interest Paid $   709,000   $   414,000   $ 2,150,000   $ 1,068,000
    Cash Taxes Paid
     (Recovered)       $    90,000   $   102,000   $   273,000  ($   292,000)



    NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
    ------------------------------------------------------
    Periods Ended September 30, 2007 and 2006 unaudited

    1.  SIGNIFICANT ACCOUNTING POLICIES

    The accounting policies and methods of application followed in the
    preparation of the interim financial statements other than described
    below are the same as those followed in the preparation of the Trust's
    2006 annual financial statements. These interim financial statements do
    not include all disclosure requirements for annual financial statements.
    The interim financial statements as presented should be read in
    conjunction with the 2006 annual financial statements.

    Financial instruments - recognition and measurement

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

    The Trust has made the following classifications:

    -   Investment in related party is classified as available-for sale and
        will thus be marked-to-market through comprehensive income at each
        period end.
    -   Accounts receivable are classified as loans and receivables and are
        recorded at amortized cost using the effective interest method. Gains
        and losses are recognized in net earnings when the asset is no longer
        recognized.
    -   Accounts payable and accrued liabilities and bank debt are classified
        as other financial liabilities and are recorded at amortized cost
        using the effective interest method. Gains and losses are recognized
        in net earnings when the liability is no longer recognized.

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

    The impact on the consolidated financial balance sheet of measuring
    hedging derivatives at fair value as at January 1, 2007 was an increase
    in other assets of $1,148,000, an increase in future tax liability of
    $334,000 and an increase in accumulated other comprehensive income of
    $814,000.

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

    Comprehensive income

    On January 1, 2007, the Trust adopted Section 1530 of the CICA Handbook,
    "Comprehensive Income". It describes reporting and disclosure
    recommendations with respect to comprehensive income and its components.
    Comprehensive income is the change in unitholders' equity, which results
    from transactions and events from sources other than the Trust's
    unitholders. These transactions and events include unrealized gains and
    losses from changes in fair value of certain financial instruments.

    The adoption of this Section implied that the Trust now presents a
    consolidated statement of comprehensive income as a part of the
    consolidated financial statements.

    Equity

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

    Hedges

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

    Accounting changes

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

    2.  INVESTMENT IN RELATED PARTY

    The investment consists of 689,682 (December 31, 2006 - 689,682) common
    shares in Comaplex Minerals Corp. (Comaplex), a company with common
    directors and management. The investment is recorded at fair market
    value. The fair market value, as determined by using the trading price of
    the stock at September 30, 2007, was $3,669,000 (December 31, 2006 -
    $2,297,000). The common shares trade on the Toronto Stock Exchange under
    the symbol CMF. The investment represents less than a two percent
    ownership in the outstanding shares of Comaplex.

    3.  PROPERTY AND EQUIPMENT

                          September 30, 2007           December 31, 2006
                                    Accumulated                 Accumulated
                                   Depletion and               Depletion and
                           Cost     Depreciation       Cost     Depreciation
    -------------------------------------------------------------------------
    Undeveloped land  $    334,000  $          -  $    334,000  $          -
    Petroleum and
     natural gas
     properties and
     related equipment 185,202,000    63,242,000   175,353,000    54,008,000
    Furniture,
     equipment and
     other                 990,000       667,000       915,000       642,000
    -------------------------------------------------------------------------
                      $186,526,000  $ 63,909,000  $176,602,000  $ 54,650,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    4.  DEBT

    The Trust through its operating subsidiaries has a bank revolving credit
    facility of $69,900,000 at September 30, 2007 (December 31, 2006 -
    $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 the amount of outstanding letters of
    credit. Letters of credit totalling $340,000 were issued at
    September 30, 2007 (December 31, 2006 - $340,000). 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 generally accepted accounting principles. It has been
    management's experience that these types of 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 nine month periods ended
    September 30, 2007 and 2006 for these loans were $2,150,000 and
    $1,068,000 respectively.

    5.  INCOME TAXES

    The Trust has recorded a future income tax liability related to assets
    and liabilities and related tax amounts. The following figures reflect
    the consequences of the Canadian Federal Governments October 31, 2006
    announcement on the future taxation of Income Trusts:

                                                  September 30, December 31,
                                                       2007          2006
    -------------------------------------------------------------------------
    Future income tax liability related to assets
     and liabilities:                             $ 11,805,000  $  6,233,000
    Future tax asset related to finance costs:         (95,000)            -
    Future tax asset related to corporate
     tax losses carried forward in the subsidiary
     companies                                      (4,796,000)   (2,646,000)
    -------------------------------------------------------------------------
                                                  $  6,914,000  $  3,587,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

                                                       2007          2006
    -------------------------------------------------------------------------
    Earnings before income taxes                  $ 25,382,000  $ 31,426,000
    Combined federal and provincial income tax
     rates                                               32.38%        34.97%
    -------------------------------------------------------------------------
    Income tax provision calculated using
     statutory tax rates                             8,219,000    10,989,000
    Increase (decrease) in taxes resulting from:
      Saskatchewan resource surcharge                  247,000       287,000
      Unit-based compensation                          272,000       244,000
      Non-deductible crown royalties                         -       815,000
      Resource allowance                                     -    (1,452,000)
      Change in effective tax rate of the Trust      3,801,000             -
      Trust income allocated to Unitholders         (9,685,000)  (10,098,000)
      Others                                            98,000      (138,000)
    -------------------------------------------------------------------------
    Income tax expense                            $  2,952,000  $    647,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

                                                     Rate of
                                                   Utilization
                                                        %          Amount
    -------------------------------------------------------------------------
    Undepreciated capital costs                         20-100  $ 16,324,000
    Canadian oil and gas property expenditures              10     1,665,000
    Canadian development expenditures                       30    29,526,000
    Canadian exploration expenditures                      100        93,000
    Income tax losses carried forward(1)                   100    16,367,000
    -------------------------------------------------------------------------
                                                                $ 63,975,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Income tax losses carried forward expire in 2014 ($635,000), 2015
        ($3,574,000), 2026 ($4,826,000) and 2027 ($7,332,000).


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

                                                     Rate of
                                                   Utilization
                                                        %          Amount
    -------------------------------------------------------------------------
    Canadian oil and gas property expenditures              10  $ 14,583,000
    Finance costs                                           20       411,000
    Eligible capital expenditures                            7       354,000
    -------------------------------------------------------------------------
                                                                $ 15,348,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Prior to June 2007, the Trust estimated the future income tax on certain
    temporary differences between amounts recorded on its balance sheet for
    book and tax purposes at a nil effective tax rate. The entire balance of
    the future income tax liability reported related to assets and
    liabilities and related tax amounts held through the Trust's 100 percent
    held subsidiaries. Under the legislation, the Trust now estimates the
    effective tax rate on post 2010 reversal of these temporary differences
    to be 31.5%. Temporary differences at the Trust level reversing before
    2011 will still give rise to nil future income taxes.

    Based on its assets and liabilities as at September 30, 2007, the Trust
    has estimated the amount of its temporary differences which were
    previously not subject to tax and estimated the periods in which these
    differences will reverse. The Trust estimates that $12,070,000 net
    taxable temporary differences will reverse after January 1, 2011,
    resulting in an additional $3,801,000 future income tax liability. The
    taxable temporary differences relate principally to the excess of net
    book value of oil and gas properties over the remaining tax pools
    attributable thereto.

    As the legislation gives rise to a change in the Trust's estimated future
    income tax liability in the period, the recognition of the additional
    liability is accounted for prospectively in the period and an additional
    $3,801,000 of future income tax expense has been recorded for the period.

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

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

    6.  UNIT CAPITAL

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

    Issued                             Number        Amount
    -----------------------------------------------------------
    Trust Units
    Balance, January 1, 2007          16,874,658  $ 89,488,000
    Issued pursuant to Trust's unit
     option plan                          47,000       845,000
    Transfer of contributed surplus
     to unit capital                           -        93,000
    -----------------------------------------------------------
    Balance, September 30, 2007       16,921,658  $ 90,426,000
    -----------------------------------------------------------
    -----------------------------------------------------------

    The number of trust units used to calculate diluted net earnings per unit
    for the period ended September 30, 2007 of 16,941,635 (2006 - 16,809,422)
    included the basic weighted average number of units outstanding of
    16,907,105 (2006 - 16,703,957) plus 34,530 (2006 - 105,465) units related
    to the dilutive effect of unit options.

    The deficit balance is composed of the following items:

                                    September 30, September 30,
                                         2007          2006
    -----------------------------------------------------------
    Accumulated earnings            $144,836,000  $115,935,000
    Accumulated cash distributions  (189,403,000) (143,458,000)
    -----------------------------------------------------------
    Deficit                         ($44,567,000) ($27,523,000)
    -----------------------------------------------------------
    -----------------------------------------------------------

    The Trust provides an option plan for its directors, officers, employees
    and consultants. Under the plan, the Trust may grant options for up to
    1,692,000 (December 31, 2006 - 1,687,000) 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
    September 30, 2007 and December 31, 2006, and changes during the nine
    month and twelve month periods ending on those dates is presented below:

                          September 30, 2007          December 31, 2006
    -------------------------------------------------------------------------
                                      Weighted-                   Weighted-
                                       Average                     Average
                                      Exercise                    Exercise
                         Options        Price        Options        Price
    -------------------------------------------------------------------------
    Outstanding at
     beginning of
     period                721,500  $      26.55       646,000  $      18.67
    Options granted        546,000         28.12       447,000         29.18
    Options exercised      (47,000)        17.97      (339,500)        15.20
    Options cancelled      (44,000)        27.92       (32,000)        24.70
    -------------------------------------------------------------------------
    Outstanding at end
     of period           1,176,500  $      27.57       721,500  $      26.55
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Options exercisable
     at end of period      229,500  $      24.56       212,500  $      22.62
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following table summarizes information about unit options outstanding
    at September 30, 2007:

                            Options Outstanding        Options Exercisable
                     -------------------------------- ----------------------
                                  Weighted-
                                   Average   Weighted-             Weighted-
    Range of            Number    Remaining   Average    Number     Average
    Exercise         Outstanding Contractual Exercise Exercisable  Exercise
    Prices            At 9/30/07     Life      Price   At 9/30/07    Price
    -------------------------------------------------------------------------
    $22.45-$23.35        231,500  1.5 years  $   23.32    194,500  $   23.31
    $24.20-$25.00         20,000  2.3 years      24.21          -          -
    $26.60                 5,000  2.3 years      26.60          -          -
    $28.30-$28.75        880,000  2.2 years      28.49     15,000      28.72
    $32.00-$33.75         40,000  2.2 years      33.55     20,000      33.55
    -------------------------------------------------------------------------
    $22.45-$33.75      1,176,500  2.1 years  $   27.57    229,500  $   24.56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Trust records a compensation expense over the vesting period based on
    the fair value of options granted to employees, directors and
    consultants.

    7.  ACCUMULATED OTHER COMPREHENSIVE INCOME

    Nine months ended September 30, 2007

                                                    Other
                                                Comprehensive
                                    Opening         Income         Ending
    -------------------------------------------------------------------------
    Unrealized gains and losses
     on available-for sale
     financial assets            $   1,566,000  $   1,170,000  $   2,736,000
    Unrealized gains and losses
     on derivatives designated
     as cash flow hedges               814,000       (452,000)       362,000
                                 -------------- -------------- --------------
                                 $   2,380,000  $     718,000  $   3,098,000
                                 -------------- -------------- --------------
                                 -------------- -------------- --------------

    8.  RELATED PARTY TRANSACTIONS

    The Trust received a management fee from Comaplex of $225,000
    (2006 - $225,000) for management services, accounting services and office
    administration. This cost has been included as a recovery of general and
    administrative expenses. The above charge represents the fair value of
    the services rendered. At September 30, 2007 the Trust had an accounts
    receivable from Comaplex of $121,000 (December 31, 2006 - $38,000).

    The Trust received a management fee from Pine Cliff Energy Ltd.
    (Pine Cliff) of $162,000 (2006 - $162,000) for management services,
    accounting services and office administration. This fee has been included
    as a recovery in general and administrative expenses. As at
    September 30, 2007 the Trust had no amounts for accounts receivable from
    or accounts payable to Pine Cliff. The above charge represents the fair
    value of the services rendered.

    9.  COMMITMENTS - FUTURE SALES AGREEMENTS

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

                                          Volume
    Period of Agreement     Commodity     per day   Index    Price (Cdn.)
    -------------------------------------------------------------------------
    July 1, 2007 to
     December 31, 2007      Crude Oil    500 barrels   WTI   Floor of $75.00
                                                             and ceiling of
                                                             $93.00 per
                                                             barrel
    July 1, 2007 to
     December 31, 2007      Crude Oil    500 barrels   WTI   Floor of $70.00
                                                             and ceiling of
                                                             $80.06 per
                                                             barrel
    January 1, 2008 to
     June 30, 2008          Crude Oil  1,000 barrels   WTI   Floor of $73.00
                                                             and ceiling of
                                                             $83.00 per
                                                             barrel
    July 1, 2008 to
     December 30, 2008      Crude Oil    500 barrels   WTI   Floor of $73.00
                                                             and ceiling of
                                                             $80.68 per
                                                             barrel
    April 1, 2007 to
     October 31, 2007     Natural Gas     1,000 GJ's  AECO   Floor of $6.50
                                                             and ceiling of
                                                             $9.20 per GJ
    November 1, 2007 to
     March 31, 2008       Natural Gas     2,000 GJ's  AECO   Floor of $6.50
                                                             and ceiling of
                                                             $10.37 per GJ


    10. SUBSEQUENT EVENT - DISTRIBUTIONS

    Subsequent to September 30, 2007, the Trust declared distributions of
    $0.22 per unit payable on October 31 and November 30, 2007 to Unitholders
    of record on October 15 and November 15, 2007 respectively. The
    distributions represent amounts related to September and October 2007
    operations.
    

    %SEDAR: 00017467E




For further information:

For further information: Additional information relating to the Trust
may be found on SEDAR.COM as well as on the Trust's website 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

Organization Profile

Bonterra Energy Corp.

More on this organization


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890