News Releases

Bonterra Energy Income Trust Announces Third Quarter Results

Nov 7, 2008 - 12:00 ET

CALGARY, ALBERTA--(Marketwire - Nov. 7, 2008) - Bonterra Energy Income Trust (the Trust or Bonterra) (www.bonterraenergy.com) (TSX:BNE.UN) is pleased to announce its financial and operational results for the three months and nine months ended September 30, 2008.

HIGHLIGHTS



                                   Three Months Ended  Nine Months Ended
                                      September 30        September 30
                                     2008      2007      2008      2007
-------------------------------------------------------------------------
FINANCIAL ($000, except $ per unit)
Revenue - realized oil and gas      34,226    23,794    99,117    69,858
Adjusted Distribution Base(1)       21,158    13,149    60,568    37,973
  Per Unit - Basic                    1.24      0.78      3.56      2.25
  Per Unit - Diluted                  1.22      0.77      3.53      2.24
Cash Distributions per Unit           0.96      0.66      2.50      1.98
Payout Ratio                            77%       85%       70%       88%
Net Earnings                        21,125     8,945    44,841    21,978
  Per Unit - Basic                    1.23      0.53      2.63      1.30
  Per Unit - Diluted                  1.22      0.53      2.61      1.30
Capital Expenditures
 and Acquisitions                    6,038     2,763    15,002    12,087
Total Assets                                           150,120   138,140
Working Capital Deficiency(2)                           47,499    50,041
Unitholders' Equity                                     57,623    50,820
-------------------------------------------------------------------------
OPERATIONS
Oil and NGLs
  Barrels Per Day                    3,013     3,054     3,063     3,118
  Average Price ($ per barrel)      103.36     73.68     97.29     67.87
Natural Gas
  MCF Per Day                        7,233     6,196     7,215     6,442
  Average Price ($ per MCF)           8.20      5.47      8.71      6.77
Total BOE per Day(3)                 4,219     4,088     4,266     4,192
(1) Adjusted distribution base is not a recognized measure under GAAP.
    Management believes that in addition to cash flow from operations,
    adjusted distribution base is a useful supplemental measure as it
    demonstrates the Trust's ability to generate the funds 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) published
    recommendations regarding disclosure of a measure called Standardized
    Distributable Cash. Please refer to page 9 of this report for the
    reconciliation between adjusted distribution base and standardized
    distributable cash.
(2) Includes 100 percent of debt.
(3) BOE 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.

 


Report to Shareholders

Bonterra Energy Income Trust (Bonterra or the Trust) is pleased to report its operating and financial results for the three months and nine months ended September 30, 2008.

Bonterra delivered another quarter of excellent results despite the significant volatility due to the continued fallout from the global credit crisis which has resulted in major stock market declines; ongoing recession fears in both the United States and Canada; and a subsequent weakening in commodity prices for the last month of the quarter.

Highlights include:

- Record net earnings of approximately $21.1 million for the third quarter of 2008, a 64 percent increase over the previous quarter and a 136 percent increase over the third quarter of 2007;

- Third quarter revenue was approximately $34.2 million and remained relatively stable when compared with revenue of $34.4 million during the second quarter of the year. Compared with the third quarter of 2007, revenue increased 61 percent;

- Bonterra's adjusted distribution base remained stable at approximately $21.2 million compared to $21.4 million recorded in the second quarter of 2008 and increased 17 percent compared with the same period in 2007; and

- Solid execution in the Trust's operations with record cash netbacks of $56.45 per barrel of oil equivalent (BOE) and a 100 percent drilling success rate during the quarter.

Bonterra has continued its long-term, disciplined approach to creating value for its investors and during the third quarter proposed a plan that if implemented will provide certainty and clarity with regards to its future. The Board of Directors and Management recommended a proposal to convert from a trust to a corporation through a plan of arrangement that includes the acquisition of Silverwing Energy Inc. (Silverwing) and the reorganization with SRX Post Holdings Inc. (SRX).

Management strongly believes that the corporate structure is better suited to the Trust's core business model of growth, capital appreciation and income generation for Unitholders. Bonterra has been successful in providing strong returns for investors, however with the federal government's introduction of trust taxation on October 31, 2006 and subsequent legislation, there has been diminished value associated with the income trust structure with negative impacts including prolonged depression in trust unit prices, decreased access to capital and a limited ability to grow based on the "normal growth" guidelines.

The plan of arrangement was overwhelmingly approved by over 99 percent of Unitholders at the special meeting held on October 16, 2008 and the plan implementation date is expected to be on or about November 12, 2008 after further diligence with regard to the SRX transaction.

Selected benefits of the new corporate structure include:

- The ability to continue to provide income oriented investors with a substantial cash yield. Bonterra intends to continue with a cash dividend policy similar to that followed by the Trust, subject to commodity prices and volumes of production, while allowing Bonterra to aggressively pursue growth opportunities;

- Substantial tax pools of approximately $450 million which will allow Bonterra to extend its taxable horizon to approximately 2015, depending on commodity prices.

- Higher after-tax earnings for investors as dividends are taxed at lower rates than distributions;

- Access to a broader domestic investor base that may result in more financing opportunities;

- Removal of the current foreign ownership limitations of 50 percent of the outstanding trust units, thereby potentially broadening the investor base internationally;

- Removal of the growth limitation which currently exists under the "normal growth" guidelines;

- The ability to increase capital investment over the next several years with a view to providing enhanced returns to investors; and Bonterra is positioned to be valued as a growth-oriented, high-dividend paying corporation with a proven history of accretive growth and long term returns for investors.

The acquisition of Silverwing provides Bonterra with a new core area and an additional 650 BOE per day of production and 2.2 MMBOE of reserves (proved plus probable). The Silverwing assets are predominantly high-working interest, largely operated properties located in northeastern British Columbia (BC). In addition, Bonterra receives 10,000 net acres of undeveloped land with the right to earn an additional 38,000 acres of non-producing lands in Alberta and BC providing the Trust with significant potential for further development.

Production remained relatively flat quarter over quarter at 4,219 BOE per day. During the first nine months of 2008, Bonterra incurred capital costs of $15.0 million and drilled 18 gross (12.7 net) Cardium oil wells and one gross (0.1 net) shallow gas well. The winter drilling program is well underway and Bonterra anticipates drilling a total of 12 gross (11.4 net) Cardium oil wells, six gross (five net) Edmonton sands natural gas wells and three gross (2.8 net) Shaunavon oil wells in the fourth quarter.

It is currently anticipated that the majority of wells drilled during the third and fourth quarter will be on production by the end of December with all remaining drilled wells to be completed and tied-in during the first quarter of 2009. Including additional production associated with the Silverwing acquisition, Bonterra estimates a year end exit rate of approximately 5,100 to 5,200 BOE per day.

The ongoing global financial crisis has led to significant declines in share prices across the energy sector and Bonterra's trust unit price has been impacted as well. In respect to the substantial deterioration in oil prices along with natural gas continuing to trade lower, the Board of Directors and management has deemed it necessary to reduce the monthly dividend from $0.32 to $0.26 per trust unit to reflect the current pricing environment. The $0.32 distribution was based on approximate pricing of $115 per barrel for oil, $65 per barrel for liquids and $8.00 per MCF for natural gas (all Canadian dollars). Commodity price forecasts for the foreseeable future are much lower necessitating the reduction. The board will continue to monitor dividend levels, payout ratios and capital expenditures on a monthly basis.

In conclusion, Bonterra remains well-positioned in the industry to continue providing investors with above average results and returns. The company's superior asset base provides a strong foundation for continued success with a drilling inventory in excess of 10 years. The corporate conversion positions the company to provide increased after-tax returns to investors and removes uncertainty associated with trust taxation legislation. Finally, the challenging conditions in the capital and commodity markets will likely present further acquisition opportunities in the oil and gas sector. Bonterra's balance sheet strength and conservative debt levels well-positions the company to make additional strategic acquisitions. The company will continue to assess all opportunities diligently to further add value on behalf of investors.

Forward-looking Information

Certain statements contained in this discussion 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 discussion 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 there from. 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.



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

Production
----------
                           Three months ended         Nine months ended
                     September     June  September  September  September
                      30, 2008 30, 2008   30, 2007   30, 2008   30, 2007
-------------------------------------------------------------------------
Crude oil and NGLs
 (barrels per day)       3,013    3,024      3,054      3,063      3,118
Natural gas
 (MCF per day)           7,233    7,272      6,196      7,215      6,442
-------------------------------------------------------------------------
Average BOE per day      4,219    4,236      4,086      4,266      4,192
-------------------------------------------------------------------------

 


Barrels of oil equivalent (BOE) 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.

Production volumes for the third quarter were relatively unchanged from the second quarter. Production increases resulting from the tie-in of 4 gross and net Cardium wells and a 0.1 net natural gas well were offset by the Trust's natural decline rate of approximately 9 percent.

The Trust drilled 15 gross (12.3 net) Cardium oil wells and 1 gross (0.1 net) shallow gas well in the first nine months of 2008 on its operated lands. In addition the Trust participated in the drilling of 3 (0.4 net) Cardium wells on non-operated lands. As at September 30, 2008, Bonterra had 5 gross (4.2 net) Cardium oil wells and 3 gross (2.5 net) coalbed methane wells (CBM) drilled but not on production. During the first nine months of 2008, the Trust tied-in 20 gross (14.8 net) Cardium wells and 3 gross (2.1 net) natural gas wells. The Trust anticipates drilling a total of 12 gross (11.4 net) Cardium oil wells, 6 gross (5 net) Edmonton sands natural gas wells as well as 3 gross (2.8 net) Shaunavon oil wells in the fourth quarter of 2008. In addition, Bonterra anticipates closing the Silverwing acquisition on or about November 12, 2008 resulting in additional production of approximately 650 BOE per day.

It is currently projected that between 10 to 15 of the Cardium wells and 4 to 5 of the Edmonton sand wells drilled in the third and fourth quarters will be on production by the end of December. All the remaining drilled wells are scheduled to be completed and tied-in during the first quarter of 2009.

Should the Trust be successful in closing the Silverwing acquisition and tie-ins as scheduled, it is estimated that the Trust's 2008 exit production will be approximately 5,100 to 5,200 BOE per day.



Revenue
-------
                          Three months ended         Nine months ended
                     September     June  September  September  September
                      30, 2008 30, 2008   30, 2007   30, 2008   30, 2007
-------------------------------------------------------------------------
Revenue - oil
 and gas sales (000's)  34,226   34,398     23,794     99,117     69,858
Average Realized Prices:
Crude oil and NGLs
 (per barrel)           103.36   101.69      73.68      97.29      67.87
Natural gas (per MCF)     8.20     9.61       5.47       8.71       6.77
-------------------------------------------------------------------------

 


Third quarter realized gross revenue of $34,226,000 was slightly lower than the second quarter 2008 due to slightly lower production volumes. Included in revenue is a realized loss on risk management contracts of $8,329,000 for the first nine months of 2008 ($924,000 gain in the first nine months of 2007). In addition, the Trust also recorded an unrealized gain on risk management contracts of $1,041,000 for the first nine months of 2008 (first nine months of 2007 - ($638,000)). All fair value adjustments related to outstanding risk management contracts are recorded as adjustments to net earnings.

The Trust anticipates lower fourth quarter realized revenue as commodity prices have dropped over 40 percent from their highs in June and July. A portion of this reduction should be offset with the Silverwing acquisition and additional production from wells tied-in during the fourth quarter.

During the first quarter of 2008, the Trust reassessed its hedging policy. With the disposal of the Trust's interest in the Dodsland properties, which had production volume of approximately one barrel per day per well and operating costs per barrel in the mid $30's, as well as the reduction in the payout ratio from the high 80 percent to mid 60 percent range, Bonterra has decided that at least in the near term it will not enter into further risk management contracts. The Trust will however maintain the existing risk management agreements until they expire. Kindly refer to Note 9 to the attached interim financial statements for details of outstanding risk management contracts. As at September 30, 2008, the fair value of the outstanding risk management contracts was a net liability of $2,044,000 (December 31, 2007 - $3,085,000).



Royalties
---------
                          Three months ended         Nine months ended
                     September     June  September  September  September
                      30, 2008 30, 2008   30, 2007   30, 2008   30, 2007
-------------------------------------------------------------------------
Crown royalties          3,523    4,263      2,030     11,399      6,575
Freehold royalties,
 gross overriding
 royalties and net
 carried interests       1,134    1,056        652      2,921      2,553
-------------------------------------------------------------------------
Total royalty expense    4,657    5,319      2,682     14,320      9,128
-------------------------------------------------------------------------

 


Royalties paid by the Trust consist primarily of Crown royalties paid to the Provinces of Alberta and Saskatchewan. The non-Crown royalty figure for the nine months ended September 30, 2007 includes a one-time prior year royalty charge adjustment of $800,000.

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 10.6 percent (2007 - 9.5 percent) and approximately 2.7 percent (2007 - 2.5 percent) for other royalties before hedging adjustments. Bonterra continues to expect an average combined royalty rate of approximately 13.5 percent for the balance of 2008.

The recently announced new Alberta Crown royalty rates vary by prices as well as productivity levels. With the recent decline in commodity prices as well as the Silvering acquisition (mostly BC production with lower Crown royalty rates) may result in a lower average Crown royalty rate for Bonterra in 2009.



Production Costs
----------------
                          Three months ended         Nine months ended
                     September     June  September  September  September
                      30, 2008 30, 2008   30, 2007   30, 2008   30, 2007
-------------------------------------------------------------------------
Production costs         6,148    6,089      6,401     18,554     18,538
  $ per BOE              15.84    15.79      17.03      15.87      16.20
-------------------------------------------------------------------------

 


Due to increased demand for services resulting from high commodity prices over the past year have resulted in service cost increases in the 5 to 10 percent range on a year over year basis. The Trust continues to monitor costs and anticipates that costs should decline due to the recent commodity price declines as well as the lower cost per BOE related to the Silverwing production. The Trust expects costs per BOE to remain in the $15.50 to $16.00 range for the remainder of 2008 and $15.00 to $15.50 in 2009.

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 leases, power and personnel costs are not variable with production volumes. The high production costs for the Trust are substantially offset by current low royalty rates of approximately 13.5 percent, which is much lower than industry average for conventional production and results in high cash netbacks on a combined basis despite higher than industry average production costs.



General and Administrative (G&A) Expense
----------------------------------------
                          Three months ended         Nine months ended
                     September     June  September  September  September
                      30, 2008 30, 2008   30, 2007   30, 2008   30, 2007
-------------------------------------------------------------------------
G&A Expense                845      855        773      2,577      1,864
  $ per BOE               2.18     2.22       2.06       2.20       1.63
-------------------------------------------------------------------------

 


The increase in G&A expense year over year was due to increased employee compensation of approximately $822,000 as well as increases in other professional service costs of approximately $100,000. Offsetting a portion of the increase was increased cost recoveries of $40,000 from related corporations (see Related Party section) and approximately an $80,000 increase in general and administration charges to joint venture partners.



Interest Expense
----------------
                           Three months ended         Nine months ended
                     September     June  September  September  September
                      30, 2008 30, 2008   30, 2007   30, 2008   30, 2007
-------------------------------------------------------------------------
Interest Expense           545      650        709      1,994      2,150
-------------------------------------------------------------------------

 


Interest charges declined as decreases in average outstanding debt balances and reduction in borrowing rates resulted in a reduction of $156,000 in 2008 borrowing costs compared to 2007. The quarter over quarter decrease was due to slightly lower interest rates as well as reduced debt balances. Increased cash flow resulting from high crude oil prices coupled with the Trust's lower payout ratio resulted in a reduction of approximately $4,100,000 in the Trust's debt in Q3 from Q2 2008.

The acquisition of Silverwing as well as the reorganization with SRX into a corporation will result in an approximate additional $44.5 million of debt. This will result in higher interest expense in future quarters. Bonterra is currently able to borrow at rates between 3.5 and 4 percent per annum, however the new credit facility has an increased interest rate at approximately 0.75 to 0.85 percent.

The Trust's net debt as a percentage of annualized third quarter adjusted distribution base was approximately seven months (56 percent). The Trust believes that maintaining debt of approximately one year's adjusted distribution base (calculated quarterly based on annualized quarterly results) is an appropriate level to either take advantage of future acquisition opportunities or provide flexibility to develop its infill oil, shallow gas and CBM potential from its cash flow and additional bank loans.

Reorganization Costs

Bonterra has incurred approximately $752,000 in costs related to the conversion to a corporation. These costs consist primarily of legal, accounting and printing costs related to the negotiation, due diligence and preparation of the information circular. These are one time costs that will not be incurred on a continuous basis. The Trust is liable to pay a finders fee of $1,000,000 for the reorganization which will be expensed in the fourth quarter if the transaction closes.

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. During 2008, 29,000 employee unit options were issued with an estimated fair value of $115,000 ($3.95 per option) using the Black-Scholes pricing model. With the affirmative vote by the Trust's Unitholders, all Trust options have vested due to the reorganization and therefore the remaining balance of $275,000 of unit based compensation expense will be expensed during the fourth quarter of 2008. Further compensation expense will be expensed when new options in the new corporation are issued.

Depletion, Depreciation, Accretion and Dry Hole Costs

Provision for depletion, depreciation and accretion was $10,611,000 and $10,278,000, respectively for the nine month periods ending September 30, 2008 and September 30, 2007. The increase in the depletion amount was due primarily to increased production volumes and a marginal increase in the average cost of reserves.

The Trust continues to replace production declines with reserves from newly drilled wells. The Trust has capital costs of approximately $6.10 per proved BOE of reserves based on the December 31, 2007 independent engineering report.

All wells drilled during the fourth quarter of 2007 and first nine months of 2008 have been successful and therefore no dry hole costs were recorded during 2008.

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. This was enacted by legislation in June 2007. Currently distributions paid to Unitholders, other than return 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 at each Unitholder's rate of taxation. The June, 2007 legislation results in a two-tiered tax structure whereby distributions commencing in 2011 would first be subject to a 31.5 percent tax at the Trust level and then investors would be subject to tax on the distribution as if it were a taxable dividend paid by a taxable Canadian corporation. The tax rate was subsequently lowered to 29.5 percent in 2011 and 28 percent in 2012 and thereafter.

On February 26, 2008, the Minister of Finance announced that instead of basing the provincial component of the trust tax rate on a flat rate of 13 percent, the provincial component will instead be based on the general provincial corporate tax rate in each province in which the income trust has a permanent establishment. Under the proposal the Trust would be considered to have a permanent establishment in Alberta, where the provincial tax rate in 2011 is expected to be 10 percent.

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 approval. The reorganization currently contemplated by the arrangement agreement should result in the new corporate entity having no current tax liability until 2015 depending on commodity prices. Upon closing of the plan of arrangement, the resulting corporation will report an estimated $75,000,000 future income tax asset with a corresponding $65,000,000 deferred tax credit which will be amortized into income as the benefit of the additional tax pools are used to shelter future income tax.

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 a resource surcharge payable by the Trust's subsidiaries to the Province of Saskatchewan. The surcharge is calculated as a flat percent of revenues generated from the sale of petroleum products produced in Saskatchewan. The provincial government of Saskatchewan has reduced the resource surcharge rate to 3.1 percent on July 1, 2007 and to 3.0 percent on July 1, 2008.

When the plan of arrangement is completed, the resulting corporation should have consolidated tax pools of approximately $440,000,000 which can be used to shelter income from the oil and gas operations.

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
------------
                          Three months ended         Nine months ended
                     September     June  September  September  September
                      30, 2008 30, 2008   30, 2007   30, 2008   30, 2007
-------------------------------------------------------------------------
Net Earnings            21,125   12,912      8,945     44,841     21,978
-------------------------------------------------------------------------

 


Net earnings increased to an all time high of $44,841,000 in the first nine months of 2008 from $21,978,000 in the corresponding 2007 period. Revenue increases due to increased commodity prices and production were partially offset by increased loss on realized risk management contracts as well as increased royalty expense. The Trust's quarter over quarter net earnings increased $8,212,000 due primarily to reduction in the loss on unrealized risk management contracts offset partially by the future tax impact of those contracts.

The Trust continues to return in excess of 40 percent of its gross realized revenues in net earnings. The Trust's low capital costs combined with a low debt to adjusted distribution base ratio all contribute to the high return. Bonterra's higher than industry average per unit operating costs are more than offset with its low royalty rates resulting in one of the highest cash netbacks in the industry (see cash netback).

Comprehensive Income

On January 1, 2007, the Trust adopted the new GAAP accounting standards regarding the accounting for financial instruments. On adoption, the Trust increased its investment in a related party by $1,836,000 for the fair value of this investment. Other comprehensive income for the first nine months of 2008 included a decrease in the unrealized gain on investment in a related party of $488,000 (2007 increase of $1,170,000) net of applicable income taxes.

Standardized Distributable Cash

Compliance with Guidance

This discussion 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".

The following discussion is presented for comparison purposes to previous results. The resulting corporation from the plan of arrangement will not be subject to the CICA's publication.



Definition and Disclosure of Standardized Distributable Cash
                                                              Cumulative
                                                            Amounts From
                                                               Inception
                                 Nine Months   Nine Months      of Trust
                                       Ended         Ended (July 1, 2001)
                                September 30, September 30, to September
($000)                                  2008          2007      30, 2008
-------------------------------------------------------------------------
Cash Flow from Operating Activities   59,234        38,064       277,509
Less adjustment for:
  Capital expenditures               (15,002)      (12,087)     (109,500)
  Financing restrictions caused
   by debt                                 -             -             -
-------------------------------------------------------------------------
Standardized Distributable Cash       44,232        25,977       168,009
------------------------------------------------------------------------- 

Definition and Disclosure of Adjusted Distribution Base (Formerly Funds
Flow from Operations)
                                                              Cumulative
                                                            Amounts From
                                                               Inception
                                 Nine Months   Nine Months      of Trust
                                       Ended         Ended (July 1, 2001)
                                September 30, September 30, to September
($000)                                  2008          2007      30, 2008
-------------------------------------------------------------------------
Standardized Distributable Cash
 - per above                          44,232        25,977       168,009
Adjusted for:
  Capital expenditures                15,002        12,087       109,500
  Gain on sale of property                 -             -         1,089
  Changes in accounts receivable       1,936          (369)        7,512
  Changes in crude oil inventory         (99)          (33)          154
  Changes in parts inventory             (26)           41          (216)
  Changes in prepaid expenses            997           188         1,495
  Changes in accounts payable
   and accrued liabilities            (4,102)         (450)       (2,239)
  Asset retirement obligations
   settled                             2,628           532         5,157
-------------------------------------------------------------------------
Adjusted Distribution Base(1)         60,568        37,973       290,461
-------------------------------------------------------------------------
(1) Adjusted distribution base is not a recognized measure under GAAP.
    The Trust believes that in addition to cash flow from operations the
    adjusted distribution base is a useful supplemental measure as it
    demonstrates the Trust's ability to generate the funds 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 recurring items that would cause a seasonal 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 30,    December      December      December,
($000)                     2008     31, 2007      31, 2006      31, 2005
-------------------------------------------------------------------------
Standardized
 Distributable Cash      44,232       32,133        14,346        23,413
Distributions(1)        (42,660)     (44,648)      (47,281)      (38,949)
Increase (decrease)
 in bank debt            (8,577)      12,043        25,202        11,717
Proceeds on exercise of
 employee unit options    5,393          993         5,161         2,823
Issuance of units
 (net of costs of issue)      -            -             -          (259)
Non-cash financing and
 investing working capital
 adjustments              1,612         (521)        2,572         1,255
-------------------------------------------------------------------------
(1) Includes the distribution declared in October in respect of September
    operations and excludes the January, distribution as it was in
    respect of December 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
                                                             Expenditure
Year                                                               ($000)
-------------------------------------------------------------------------
2008 (including expenditures incurred to date)                     2,750
2009                                                                 250
2010                                                                 175
2011                                                                 563
2012                                                                 856
-------------------------------------------------------------------------
                                                                   4,594
-------------------------------------------------------------------------

 


Definition and History of Productive Capacity and Strategy

Bonterra's primary objective is to continue paying distributions to its Unitholders and if the reorganization closes in the future, dividends to its shareholders. This is accomplished by developing and growing its reserves from which cash flow is generated. The Trust defines Productive Capacity Maintenance as the maintaining of the Trust's proven plus probable reserves. The Trust follows a policy of internal development as its primary method of planned growth. Bonterra has a significant inventory of undrilled Cardium oil infill drilling locations as well as several shallow gas opportunities on its lands or through farm-in agreements. It is management's view that the calculation of the amount required for Productive Capacity Maintenance is the amount of reserves produced in the relevant time period multiplied by the Trust's finding and development costs for proven plus probable reserves. For this purpose the Trust believes that the use of a three-year average rate is reasonable given fluctuations in annual costs due to market conditions.



                    Nine Months
                          Ended   Year ended    Year ended    Year ended
                   September 30,    December      December      December,
                           2008     31, 2007      31, 2006      31, 2005
-------------------------------------------------------------------------
Proven and probable
 reserves at
 beginning of period
 (BOE)               27,320,000   26,476,000    23,870,000    19,711,000
Reserves added due
 to acquisitions
 (BOE)                        -     (421,000)       16,000     2,393,000
Reserves added due
 to capital
 expenditures (BOE)          (1)   2,806,000     4,082,000     3,100,000
Production during
 period (BOE)         1,169,000    1,540,000     1,476,000     1,334,000
Increase in
 productive capacity
 (BOE)                       (1)     845,000     2,606,000     4,159,000
Reserves per unit
 (fully diluted)      1.52(1)(2)        1.62          1.57          1.46
Productive capacity
 maintenance
 requirements       $12,941,000  $17,043,000   $17,472,000    $9,205,000
Capital
 expenditures
 for the period     $15,002,000  $19,300,000   $38,348,000   $56,703,000
Capital
 expenditures
 in excess of
 maintenance
 requirements        $2,061,000   $2,257,000   $20,876,000   $47,498,000
Cost of increased
 productive
 capacity
 (per BOE)                   (1)       $2.67         $8.01        $11.42
-------------------------------------------------------------------------
(1) The Trust does not update reserve information quarterly.
(2) Assuming no other additional reserves from all the wells drilled in
    2008 or from acquisitions in 2008.

 


Financing Strategy

The Trust maintains a strategy of limiting its debt levels to approximately one year adjusted distribution base. Bonterra has a long-term goal to retain between 20 to 25 percent of its adjusted distribution base (in the future 20 to 30 percent of its cash flow) to finance its capital maintenance expenditures. Over the past years, this level of retention of adjusted distribution base, along with the exercising of unit options and modest increases in its bank loans 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 (share options), equity placements or from its line of credit.

Periods may exist where the cost of replacing reserves exceeds the level of funds withheld. However, the Trust with its long life reserves and relatively low debt levels compared to other income trusts/corporations 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 from the adjusted distribution base (cash flow).

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

                                                              Cumulative
                                                            Amounts From
                                                               Inception
                                 Nine Months   Nine Months      of Trust
                                       Ended         Ended (July 1, 2001)
                                September 30, September 30, to September
($000)                                  2008          2007      30, 2008
-------------------------------------------------------------------------
Standardized Distributable Cash       44,232        25,977       168,009
Per weighted average unit               2.60          1.54         10.60
Per fully diluted unit                  2.60          1.53         10.56
Cash distributions(1)                 42,660        33,474       246,959
Payout ratio                            0.96          1.29          1.47
Adjusted Distribution Base            60,568        37,973       290,461
Per weighted average unit               3.56          2.25         18.49
Per fully diluted unit                  3.53          2.24         18.34
Cash distributions(1)                 42,660        33,474       246,959
Payout ratio                            0.70          0.88          0.86
-------------------------------------------------------------------------
(1) Includes distributions declared in October 2008 and 2007 in respect
    of September 2008 and 2007 operations, respectively.

 


Tax Attributes of Distributions and the Trust's Assets

See discussion under Taxes.

Cash Netback

The following table illustrates the Trust's cash netback from operations (excludes reorganization costs) for the nine month periods ended (the 2007 netback includes one time charges to royalties as described above in this report):



                                              September 30, September 30,
$ per Barrel of Oil Equivalent (BOE)                  2008          2007
-------------------------------------------------------------------------
Production volumes (BOE)                         1,168,665     1,144,307
Gross production revenue                            $91.94        $60.24
Realized gain (loss) on risk
 management contracts                                (7.13)         0.81
Royalties                                           (12.25)        (7.98)
Field operating costs                               (15.87)       (16.20)
-------------------------------------------------------------------------
Field netback                                        56.69         36.87
General and administrative                           (2.20)        (1.63)
Interest and taxes                                   (2.03)        (2.09)
-------------------------------------------------------------------------
Cash netback                                        $52.46        $33.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The following table illustrates the Trust's cash netback from operations
(excludes reorganization costs) for the three month periods: 

                                              September 30,      June 30,
$ per Barrel of Oil Equivalent (BOE)                  2008          2008
-------------------------------------------------------------------------
Production volumes (BOE)                           388,021       385,468
Gross production revenue                            $95.80        $99.66
Realized loss on risk management contracts           (7.60)       (10.43)
Royalties                                           (12.00)       (13.81)
Field operating                                     (15.84)       (15.80)
-------------------------------------------------------------------------
Field netback                                        60.36         59.62
General and administrative                           (2.18)        (2.22)
Interest and taxes                                   (1.73)        (2.06)
-------------------------------------------------------------------------
Cash netback                                        $56.45        $55.34
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


Liquidity and Capital Resources

During the first nine months of 2008, the Trust incurred capital costs of $15,002,000 (2007 - $12,087,000). The Trust and its partners drilled 18 gross (12.7 net) Cardium oil wells and one gross (0.1 net) shallow gas well in the first nine months of 2008.

The Trust currently has plans to drill a total of 12 gross (11.4 net) Cardium infill oil wells, 6 gross (5 net) Edmonton sands natural gas wells, and 3 gross (2.8 net) Shaunavon oil wells in the fourth quarter of 2008. Total capital costs of approximately $25,000,000 are budgeted for 2008. It is anticipated that the entire 2008 capital expenditures will be funded from cash flow, funds from the exercise of employee unit options and its lines of credit.

As previously mentioned, Bonterra will be acquiring Silvering for consideration of approximately $13,468,000 cash, 7,745 units and the assumption of approximately $16,500,000 in negative working capital and debt. In addition, payments of approximately $11,250,000 cash to creditors of SRX Post Holdings Inc. and a $1,000,000 finder's fee will be required on the closing of the arrangement.

The Trust, through its operating subsidiaries, has a bank revolving credit facility of $69,900,000 at September 30, 2008 (December 31, 2007 - $69,900,000). The credit facilities carry an interest rate of Canadian chartered bank prime.

The Trust is in the process of amending its credit facility to increase its borrowing capacity to $100,000,000. As a result of the increased facility, the borrowing rate of the Trust will increase to bank prime plus 0.75 to 0.85 percent depending on the ratio of debt to the preceding twelve month cash flow.



BONTERRA ENERGY INCOME TRUST

CONSOLIDATED BALANCE SHEETS

As at September 30, 2008 (unaudited) and December 31, 2007
($000)                                                2008          2007
-------------------------------------------------------------------------
Assets
Current
  Accounts receivable                               12,511        10,575
  Crude oil inventory                                  638           792
  Parts inventory                                      106           132
  Prepaid expenses                                   2,327         1,330
  Future income tax asset (Note 5)                     604           913
  Investments in related party (Note 2)              3,448         4,014
-------------------------------------------------------------------------
                                                    19,634        17,756
-------------------------------------------------------------------------
Property and Equipment (Note 3)
  Petroleum and natural gas properties
   and related equipment                           202,243       187,288
  Accumulated depletion and depreciation           (71,757)      (61,805)
-------------------------------------------------------------------------
Net Property and Equipment                         130,486       125,483
-------------------------------------------------------------------------
                                                   150,120       143,239
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities
Current
  Distributions payable                                  -         3,724
  Accounts payable and accrued liabilities          16,244        12,291
  Derivative liability                               2,044         3,085
  Debt (Note 4)                                     48,845        57,422
-------------------------------------------------------------------------
                                                    67,133        76,522
Future Income Tax Liability (Note 5)                12,530         7,595
Asset Retirement Obligations                        12,834        14,904
-------------------------------------------------------------------------
                                                    92,497        99,021
-------------------------------------------------------------------------
Commitments (Note 9)
Unitholders' Equity (Note 6)
  Unit capital                                      96,515        90,590
  Contributed surplus                                2,442         2,140
-------------------------------------------------------------------------
                                                    98,957        92,730
-------------------------------------------------------------------------
  Deficit                                          (43,877)      (51,543)
  Accumulated other comprehensive income (Note 7)    2,543         3,031
-------------------------------------------------------------------------
                                                   (41,334)      (48,512)
-------------------------------------------------------------------------
Total Unitholders' Equity                           57,623        44,218
-------------------------------------------------------------------------
                                                   150,120       143,239
-------------------------------------------------------------------------
------------------------------------------------------------------------- 

BONTERRA ENERGY INCOME TRUST

CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

For the periods ended September 30 (unaudited)
                          Three Months                 Six Months
($000)                 2008          2007          2008          2007
-------------------------------------------------------------------------
Unitholders'
 equity,
 beginning of
 period                 46,612        51,920        44,218        53,359
Comprehensive
 income for the
 period                 20,801         9,487        44,353        23,148
Adjustment of
 opening
 accumulated
 comprehensive
 income                      -             -             -         2,380
Net capital
 contributions             903           140         5,393           845
Unit option based
 compensation
 adjustment                273           437           835           840
Distributions
 declared              (10,966)      (11,164)      (37,176)      (29,752)
-------------------------------------------------------------------------
Unitholders'
 Equity, End of
 Period                 57,623        50,820        57,623        50,820
-------------------------------------------------------------------------
------------------------------------------------------------------------- 

BONTERRA ENERGY INCOME TRUST

CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

For the periods ended September 30 (unaudited)
($000,                    Three Months                 Six Months
except $ per unit)     2008          2007          2008          2007
-------------------------------------------------------------------------
Revenue
  Oil and gas sales     37,174        23,685       107,446        68,934
  Realized gain
   (loss) on risk
   management
   contracts            (2,948)          109        (8,329)          924
  Unrealized gain
   (loss) on risk
   management
   contracts
   (Note 10)             8,066          (199)        1,041          (638)
  Royalties             (4,657)       (2,682)      (14,320)       (9,128)
  Interest and other         7             9            29            42
-------------------------------------------------------------------------
                        37,642        20,922        85,867        60,134
-------------------------------------------------------------------------
Expenses
  Production costs       6,148         6,401        18,554        18,538
  General and
   administrative          845           773         2,577         1,864
  Interest on debt         545           709         1,994         2,150
  Reorganization costs     752             -           752             -
  Unit option based
   compensation            273           437           835           840
  Dry hole costs             -         1,244             -         1,720
  Depletion,
   depreciation and
   accretion             3,601         3,492        10,611        10,278
-------------------------------------------------------------------------
                        12,164        13,056        35,323        35,390
-------------------------------------------------------------------------
Earnings before Taxes   25,478         7,866        50,544        24,744
-------------------------------------------------------------------------
Taxes (Recovery)
  Current                  128            89           381           247
  Future                 4,225        (1,168)        5,322         2,519
-------------------------------------------------------------------------
                         4,353        (1,079)        5,703         2,766
-------------------------------------------------------------------------
Net Earnings for
 the Period             21,125         8,945        44,841        21,978
Deficit at beginning
 of period             (54,037)      (42,800)      (51,543)      (37,245)
Distributions declared (10,965)      (11,164)      (37,175)      (29,752)
-------------------------------------------------------------------------
Deficit at End
 of Period             (43,877)      (45,019)      (43,877)      (45,019)
-------------------------------------------------------------------------
Net Earnings
 per Trust Unit
 - Basic (Note 6)         1.23          0.53          2.63          1.30
-------------------------------------------------------------------------
Net Earnings
 per Trust Unit
 - Diluted (Note 6)       1.22          0.53          2.61          1.30
------------------------------------------------------------------------- 

BONTERRA ENERGY INCOME TRUST

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the periods ended September 30 (unaudited)
                          Three Months                 Six Months
($000,                 2008          2007          2008          2007
except $ per unit)               (Note 11)                   (Note 11)
-------------------------------------------------------------------------
Net Earnings for
 the Period             21,125         8,945        44,841        21,978
Unrealized gains
 and losses on
 investments
 (net of income
 taxes; three
 months ended
 2008 - (56),
 2007 - 93, nine
 months ended 2008
 - (78), 2007 - 202)      (324)          542          (488)        1,170
-------------------------------------------------------------------------
Other Comprehensive
 Income (Loss)            (324)          542          (488)        1,170
-------------------------------------------------------------------------
Comprehensive Income    20,801         9,487        44,353        23,148
-------------------------------------------------------------------------
Comprehensive Income
 Per Trust Unit
 - Basic                  1.21          0.56          2.60          1.37
-------------------------------------------------------------------------
Comprehensive Income
 Per Trust Unit
 - Diluted                1.21          0.56          2.59          1.37
------------------------------------------------------------------------- 

BONTERRA ENERGY INCOME TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the periods ended September 30 (unaudited)

                          Three Months                 Six Months
($000)                 2008          2007          2008          2007
-------------------------------------------------------------------------
Operating Activities
  Net earnings for
   the period           21,125         8,945        44,841        21,978
  Items not affecting
   cash
    Unrealized (gain)
     loss on risk
     management
     contracts         (8,066)           199        (1,041)          638
    Unit option based
     compensation         273            437           835           840
    Dry hole costs          -          1,244             -         1,720
    Depletion,
     depreciation and
     accretion          3,601          3,492        10,611        10,278
    Future income
     taxes              4,225         (1,168)        5,322         2,519
-------------------------------------------------------------------------
                       21,158         13,149        60,568        37,973
-------------------------------------------------------------------------
  Change in non-cash
   working capital
    Accounts
     receivable         2,901           (230)       (1,936)          369
    Crude oil
     inventory             12            (32)           99            33
    Parts inventory        15            (65)           26           (41)
    Prepaid expenses       61            266          (997)         (188)
    Accounts payable
     and accrued
     liabilities         (940)          (979)        4,102           450
  Asset retirement
   obligations settled   (715)          (223)       (2,628)         (532)
-------------------------------------------------------------------------
                        1,334         (1,263)       (1,334)           91
-------------------------------------------------------------------------
Cash Provided by
 Operating Activities  22,492         11,886        59,234        38,064
-------------------------------------------------------------------------
Financing Activities
  Increase (decrease)
   in debt             (4,135)         1,993        (8,577)       11,215
  Unit option proceeds    903            140         5,393           845
  Unit distributions  (16,439)       (11,164)      (40,899)      (33,802)
-------------------------------------------------------------------------
Cash Used in
 Financing Activities (19,671)        (9,031)      (44,083)      (21,742)
-------------------------------------------------------------------------
Investing Activities
  Property and
   equipment
   expenditures        (6,038)        (2,763)      (15,002)      (12,087)
  Change in non-cash
   working capital
    Accounts
     receivable             -              -             -           993
    Accounts payable
     and accrued
     liabilities        3,217            (92)         (149)       (5,228)
-------------------------------------------------------------------------
Cash Used in
 Investing Activities  (2,821)        (2,855)      (15,151)      (16,322)
-------------------------------------------------------------------------
Net Cash Inflow             -              -             -             -
Cash, beginning of period   -              -             -             -
-------------------------------------------------------------------------
Cash, End of Period         -              -             -             -

-------------------------------------------------------------------------
Cash Interest Paid        545            709         1,994         2,150
Cash Taxes Paid           109             90           477           273 

 


NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

Periods Ended September 30, 2008 and 2007 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
2007 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 2007 annual financial statements.

The Trust adopted Section 1535 "Capital Disclosures", Section 3862,
"Financial Instruments - Disclosures" and Section 3863, "Financial
Instruments - Presentation". All the above Sections were required to be
adopted for fiscal years beginning on or after October 1, 2007. As a
result, the Trust has added Note 9 providing the required disclosures
regarding the Trust's objectives, policies and processes for managing
capital and the significance of financial instruments for the entity's
financial position and performance; and the nature, extent and management
of risks arising from financial instruments to which the entity is
exposed.

The Trust also adopted Section 3031 - "Inventories", which replaces
Section 3030. This section is harmonized with International Accounting
Standards and provides additional guidance on the measurement and
disclosure requirements for inventories. This new standard did not have
an impact on the Trust's financial statements.

Accounting changes

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

2. INVESTMENT IN RELATED PARTY

The investment consists of 689,682 (December 31, 2007 - 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, 2008 of $5.00 per share and at December 31,
2007 of $5.82 per share. The common shares trade on the Toronto Stock
Exchange under the symbol CMF. The investment represents less than one
and a half percent ownership in the outstanding shares of Comaplex.



3.  PROPERTY AND EQUIPMENT

                   September 30, 2008           December 31, 2007
-------------------------------------------------------------------------
                                Accumulated                 Accumulated
                               Depletion and               Depletion and
($000)                 Cost     Depreciation       Cost     Depreciation
-------------------------------------------------------------------------
Undeveloped land           433             -           316             -
Petroleum and natural
 gas properties and
 related equipment      21,153        70,970       185,947        61,105
Furniture, equipment
 and other               1,090           787         1,025           700
-------------------------------------------------------------------------
                       202,243        71,757       187,288        61,805
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


4. DEBT

The Trust, through its operating subsidiaries, has a bank revolving
credit facility of $69,900,000 at September 30, 2008 (December 31, 2007 -
$69,900,000). 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 $355,000 (December 31, 2007 -
$355,000) were issued at September 30, 2008. 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. Cash interest paid during the nine month periods ended September
30, 2008 and 2007 for these loans was $1,994,000 and $2,150,000,
respectively.

Subsequent to September 30, 2008, the Trust has amended its credit
facility. The new facility has a credit limit of $100,000,000 of which
$80,000,000 is a committed syndicated facility with the balance remaining
as a demand facility with the Trust's principle banker. With the increase
in the facility, the Trust's borrowing rate has increased to Canadian
chartered bank prime plus 0.75 to 0.85 percent depending on the ratio of
debt to preceding twelve months cash flow.

5. TAXES

The Trust has recorded a future income tax liability and a current income
tax asset related to assets and liabilities and related tax amounts:



                                              September 30,  December 31,
($000)                                                2008          2007
-------------------------------------------------------------------------
Future income tax liability related to
 assets and liabilities:                            13,063        11,517
Future tax asset related to finance costs:             (29)          (79)
Future tax asset related to corporate tax
 losses carried forward in the subsidiary companies   (504)       (3,843)
-------------------------------------------------------------------------
Future income tax liability                         12,530         7,595
-------------------------------------------------------------------------
Future income tax asset related to current portion
 of derivative liability                               604           913
-------------------------------------------------------------------------

 


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
($000)                                                %           Amount
-------------------------------------------------------------------------
Undepreciated capital costs                         20-100        17,431
Canadian oil and gas property expenditures              10         1,685
Canadian development expenditures                       30        31,373
Canadian exploration expenditures                      100            11
Income tax losses carried forward(1)                   100         1,949
-------------------------------------------------------------------------
                                                                  52,449
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Income tax losses carried forward expire in 2015 ($114,000), 2026
    ($112,000) and 2027 ($1,723,000).


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

                                            Rate of Utilization
($000)                                                %           Amount
-------------------------------------------------------------------------
Canadian oil and gas property expenditures              10        13,225
Finance costs                                           20           123
Eligible capital expenditures                            7           864
-------------------------------------------------------------------------
                                                                  14,212
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


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

On February 26, 2008, the Minister of Finance announced that instead of
basing the provincial component of the trust tax rate on a flat rate of
13 percent, the provincial component will instead be based on the general
provincial corporate tax rate in each province in which the income trust
has a permanent establishment. Under the proposal, the Trust would be
considered to have a permanent establishment in Alberta, where the
provincial tax rate in 2011 is expected to be 10 percent. This would
result in an overall tax rate to the Trust of 26.5 percent in 2011 and 25
percent thereafter.

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

Based on its assets and liabilities as at September 30, 2008, the Trust
has estimated the amount of its temporary differences which are estimated
to reverse post 2010 will be $14,303,000 (December 31, 2007 -
$14,496,000) resulting in an additional $4,022,000 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.

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. As
announced, the Trust has commenced with the conversion from a trust to a
corporation by plan of arrangement dated September 17, 2008 and ratified
by the Unitholders and other parties to the Arrangement on October 16,
2008. Subject to court approval the reorganization is scheduled to close
on or about November 12, 2008. The Arrangement, when completed, will have
a material change on the future income tax amount.



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                                                        ($000)
Balance, January 1, 2008                        16,928,158        90,590
Issued pursuant to Trust's unit option plan        213,200         5,393
Transfer of contributed surplus to unit capital          -           532
-------------------------------------------------------------------------
Balance, September 30, 2008                     17,141,358        96,515
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The number of trust units used to calculate diluted net earnings per unit
for the periods ended September 30:

                          Three Months                Nine Months
                       2008          2007          2008          2007
-------------------------------------------------------------------------
Basic units
 outstanding        17,111,033    16,915,767    17,030,399    16,907,105
Dilutive effect of
 unit options          171,492        38,390       125,406        34,530
-------------------------------------------------------------------------
Diluted units
 outstanding        17,282,525    16,954,157    17,155,805    16,941,635
-------------------------------------------------------------------------

The deficit balance is composed of the following items:

                                              September 30, September 30,
($000)                                             2008          2007
-------------------------------------------------------------------------
Accumulated earnings                             197,597       144,836
Accumulated cash distributions                  (241,474)     (189,403)
-------------------------------------------------------------------------
Deficit                                          (43,877)      (44,567)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


The Trust provides an option plan for its directors, officers, employees
and service providers. Under the plan, the Trust may grant options for up
to 1,714,100 (December 31, 2007 - 1,693,000) 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, 2008 and December 31, 2007, and changes during the nine
month and twelve month periods ended on those dates is presented below:



                      September 30, 2008            December 31, 2007
-------------------------------------------------------------------------
                    Options  Weighted-Average  Options   Weighted-Average
                              Exercise Price              Exercise Price
-------------------------------------------------------------------------
Outstanding at
 beginning of
 period              1,177,000        $27.59       721,500        $26.55
Options granted         29,000         39.09       553,000         28.11
Options exercised     (213,200)        25.29       (53,500)        18.56
Options cancelled            -             -       (44,000)        27.92
-------------------------------------------------------------------------
Outstanding at end
 of period             992,800        $28.42     1,177,000        $27.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable
 at end of period      436,300        $27.94       530,000        $26.63
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The following table summarizes information about unit options outstanding
at September 30, 2008:

                       Options Outstanding          Options Exercisable
               ----------------------------------  ----------------------
                             Weighted-
                              Average   Weighted-               Weighted-
Range of           Number    Remaining    Average     Number     Average
Exercise        Outstanding Contractual  Exercise  Exercisable  Exercise
Prices           At 9/30/08     Life       Price   At 9/30/08     Price
-------------------------------------------------------------------------
$23.35               98,500   0.3 years    $23.35      98,500     $23.35
24.20-27.50          19,500   1.6 years     25.65           -          -
28.30-28.75         805,800   1.0 years     28.46     297,800      28.71
32.00-33.75          40,000   1.1 years     33.55      40,000      33.55
38.80-39.20          29,000   2.3 years     39.09           -          -
-------------------------------------------------------------------------
$23.35-$39.20       992,800   1.1 years    $28.42     436,300     $27.94
-------------------------------------------------------------------------
-------------------------------------------------------------------------

 


As a result of the affirmative vote of the Trust's Unitholders on
October 16, 2008 to the arrangement agreement and if the transaction
closes, all the remaining outstanding options will vest upon closing.
The Trust records compensation expense over the vesting period based on
the fair value of options granted to employees, directors and
consultants. The Trust granted 29,000 unit options with an estimated fair
value of $115,000 ($3.95 per option) in 2008 and 553,000 unit options in
2007 with an estimated fair value of $1,494,000 ($2.70 per option) using
the Black-Scholes option pricing model with the following key
assumptions:



                                        2008          2007
----------------------------------------------------------------
Weighted-average risk free interest
 rate (%)                                2.9           4.7
Expected life (years)                    2.5           2.3
Weighted-average volatility (%)         29.2          27.2
Dividend yield                       based on the percentage of
                                     distributions paid to the
                                   Unitholders during the period

7.  ACCUMULATED OTHER COMPREHENSIVE INCOME

                                                  Other
                                   January 1, Comprehensive September 30,
($000)                                2008     Income (Loss)     2008
-------------------------------------------------------------------------
Unrealized gains (losses) on
 available-for-sale financial
 assets                              3,031         (488)        2,543
------------------------------------------------------------------------- 
                                                  Other
                                   January 1, Comprehensive December 31,
($000)                                2007        Income         2007
-------------------------------------------------------------------------
Unrealized gains on
 available-for-sale financial
 assets                              1,566        1,465         3,031
-------------------------------------------------------------------------

 


8. RELATED PARTY TRANSACTIONS

The Trust received a management fee from Comaplex of $247,500 (2007 -
$225,000) for management services and office administration. This fee has
been included as a recovery in general and administrative expenses. As at
September 30, 2008, the Trust had an account receivable from Comaplex of
$108,000 (December 31, 2007 - $63,000).

The Trust received a management fee from Pine Cliff Energy Ltd. (Pine
Cliff) of $178,200 (2007 - $162,000) for management services and office
administration. This fee has been included as a recovery in general and
administrative expenses. As at September 30, 2008 the Trust had an
account receivable from Pine Cliff of $Nil (December 31, 2007 - $4,000).

The above charges represent the agreed to exchange amount of the services
rendered.

9. FINANCIAL AND CAPITAL RISK MANAGEMENT

Financial Risk Factors

The Trust undertakes transactions in a range of financial instruments

including:

- Receivables

- Payables

- Common share investments

- Bank loans

- Derivatives

The Trust's activities result in exposure to a number of financial risks
including market risk (commodity price risk, interest rate risk, foreign
exchange risk, credit risk, and liquidity risk).

Bonterra's overall risk management program seeks to mitigate these risks
and reduce the volatility on the Trust's financial performance. Financial
risk management is carried out by senior management under the direction
of the Directors of Bonterra Energy Corp. (a subsidiary of the Trust).
The Trust enters into various risk management contracts in accordance
with Board approval to manage Bonterra's exposure to commodity price
fluctuations. Currently no risk management agreements are in place in
respect of interest rate risk. The Trust does not speculatively trade in
risk management contracts. The Trust's risk management contracts are
entered into to manage the risks relating to commodity prices from its
business activities.

Capital Risk Management

The Trust's objectives when managing capital are to safeguard the Trust's
ability to continue as a going concern, so that it can continue to
provide returns to its Unitholders and benefits for other stakeholders
and to maintain an optimal capital structure to reduce the cost of
capital. In order to maintain or adjust the capital structure, the Trust
may adjust the amount of distributions, the percentage of return of
capital or issue new units.

The Trust monitors capital on the basis of the ratio of debt to adjusted
distribution base. This ratio is calculated using each quarter end net
debt (total debt adjusted for working capital) and divided by the
annualized current quarter adjusted distribution base. For these
purposes, the Trust defines adjusted distribution base as funds provided
by operations before changes in non-cash operating working capital items
excluding gains or losses on sale of property and asset retirement
obligations.

The Trust believes that maintaining debt at approximately one year's
adjusted distribution base is an appropriate level to allow it to take
advantage in the future of either acquisition opportunities or to provide
flexibility to develop its infill oil, shallow gas and coalbed methane
potential without requiring the issuance of trust units.

The following section (a) of this note provides a summary of the Trust's
underlying economic positions as represented by the carrying values, fair
values and contractual face values of the Trust's financial assets and
financial liabilities. The Trust's debt to adjusted distribution base is
also provided.

The following section (b) addresses in more detail the key financial risk
factors that arise from the Trust's activities including its policies for
managing these risks.

The following section (c) provides details of the Trust's risk management
contracts that are used for financial risk management.

a) Financial assets, financial liabilities and debt ratio

The carrying amounts, fair value and face values of the Trust's financial
assets and liabilities are shown in Table 1.



Table 1

                   As at September 30, 2008   As at December 31, 2007
-------------------------------------------------------------------------
                 Carrying     Fair     Face   Carrying     Fair     Face
($000)              Value    Value    Value      Value    Value    Value
Financial assets
Accounts
 receivable        12,511   12,511   12,550     10,575   10,575   10,595
Investments in
 related party      3,448    3,448      N/A      4,014    4,014      N/A
Financial
 liabilities
Distribution payable    -        -        -      3,724    3,724    3,724
Accounts payable
 and accrued
 liabilities       16,244   16,244   16,244     12,291   12,291   12,291
Derivative
 liability          2,044    2,044        -      3,085    3,085        -
Debt               48,845   48,845   48,845     57,422   57,422   57,422

The net debt and adjusted distribution base figures for the three months
ended September 30, 2008 and September 30, 2007 are presented in Table 2.
Table 2

For the three month
 periods ended                  September 30, September 30,
($000)                                  2008          2007
----------------------------------------------------------------
Debt                                  48,845        56,594
Accounts payable and accrued
 liabilities                          16,244         8,970
Derivative liability                   2,044             -
Current assets                       (19,634)      (15,523)
----------------------------------------------------------------
Net Debt                              47,499        50,041
----------------------------------------------------------------
Cash flow from operations             22,492        11,886
Changes in non-cash operating
 working capital                      (2,049)        1,040
Asset retirement obligations
 settled                                 715           223
----------------------------------------------------------------
Adjusted Distribution Base            21,158        13,149
Annualized adjusted distribution
 base                                 84,632        52,596
----------------------------------------------------------------
Net debt to adjusted distribution
 base                                   0.56          0.95
----------------------------------------------------------------

 


b) Risks and mitigations

Market risk is the risk that the fair value or future cash flow of the
Trust's financial instruments will fluctuate because of changes in market
prices. Components of market risk to which Bonterra is exposed are
discussed below.

Commodity price risk

The Trust's principal operation is the production and sale of crude oil,
natural gas and natural gas liquids. Fluctuations in prices of these
commodities directly impact the Trust's performance and ability to
continue with its distributions.

The Trust currently uses various risk management contracts to set price
parameters for a portion of its production (see section c below).
Management, in agreement with the Board of Directors, recently decided
that at least in the near term it will discontinue the use of commodity
price agreements. The Trust will assume full risk in respect of commodity
prices.

Sensitivity Analysis

Commodity prices have fluctuated significantly over the recent past. The
following table updates the annual cash flow sensitivity for movements in
the commodity prices of $1 U.S. WTI for crude oil, $0.10 per MCF AECO for
natural gas and $0.01 fluctuation in exchange rates. These figures have
been updated from December 31, 2007 to include commodity price hedges
entered into during 2008.



                                                 Cash Flow
-----------------------------------------------------------
U.S. $1.00 per barrel                            $ 692,000
Canadian $0.10 per MCF                           $ 181,000
Change of Canadian $0.01/U.S. $ exchange rate    $ 587,000
-----------------------------------------------------------

 


Interest rate risk

Interest rate risk refers to the risk that the value of a financial
instrument or cash flows associated with the instrument will fluctuate
due to changes in market interest rates. Interest rate risk arises from
interest bearing financial assets and liabilities that Bonterra uses. The
principal exposure of the Trust is on its bank borrowings which have a
variable interest rate which gives rise to a cash flow interest rate
risk.

Bonterra's debt consists of an operating line as well as borrowings by
means of banker acceptances (BA's). The Trust manages its exposure to
interest rate risk through entering into various term lengths on its BA's
but in no circumstances do the terms exceed six months. As discussed
above, the Trust manages its capital such that its debt to adjusted
distribution base is no higher than approximately one year. This allows
flexibility in obtaining cost effective financing.

Sensitivity Analysis

Based on historic movements and volatilities in the interest rate markets
and management's current assessment of the financial markets, the Trust
believes that a one percent variation in the Canadian prime interest rate
is reasonably possible over a 12-month period. No income tax effect has
been calculated as the Trust remains non-taxable until January 1, 2011.

The following illustrates the annual impact of a one percent fluctuation
in the Canadian prime rate:



                            As at                      As at
                    September 30, 2008          December 31, 2007
-------------------------------------------------------------------------
              Plus 1%        Minus 1%        Plus 1%         Minus 1%
($000)   Earnings Equity Earnings Equity Earnings Equity Earnings Equity
Financial
 assets
---------
Accounts
 receivable   -       -       -       -      -       -       -       -
Investments
 in related
 party        -       -       -       -      -       -       -       -
Financial
 liabilities
------------
Distribution
 payable      -       -       -       -      -       -       -       -
Accounts
 payable
 and
 accrued
 liabilities  -       -       -       -      -       -       -       -
Derivative
 liability    -       -       -       -      -       -       -       -
Debt        (488)   (488)    488     488   (574)   (574)    574     574
-------------------------------------------------------------------------
Total
 increase
 (decrease) (488)   (488)    488     488   (574)   (574)    574     574
-------------------------------------------------------------------------

 


Foreign exchange risk

The Trust has no foreign operations and currently sells all its product
sales in Canadian currency. The Trust however is exposed to currency risk
in that crude oil is priced in U.S. currency then converted to Canadian
currency. Bonterra mitigates some of this risk by using risk management
contracts for a portion of its crude oil production in Canadian dollars.
Please refer to sensitivity analysis under commodity price risk as well
as section "c" below for a list of currently outstanding risk management
agreements. Management, in agreement with the Board of Directors,
recently decided that at least in the near term it will discontinue the
use of commodity price agreements. The Trust will assume full risk in
respect of foreign exchange fluctuations.

Credit risk

Credit risk is the risk that a contracting party will not complete its
obligations under a financial instrument and cause the Trust to incur a
financial loss. Bonterra is exposed to credit risk on all financial
assets included on the balance sheet. To help mitigate this risk:



-   The Trust only enters into material agreements with credit worthy
    counterparties. These include major oil and gas companies or one of
    the major Canadian chartered banks;

-   Agreements for product sales are primarily on 30 day renewal terms;
    and

-   Investments are generally only with companies that have common
    management with the Trust.

 


Of the accounts receivable balance of September 30, 2008 ($12,511,000)
and December 31, 2007 ($10,575,000) over 90 percent relates to product
sales with international oil and gas companies. All of the derivative
contracts as of both September 30, 2008 and December 31, 2007 were with
either Bonterra's principal banker or its major crude oil purchaser.
The Trust assesses quarterly, if there has been any impairment of the
financial assets of the Trust. During the three month period ended
September 30, 2008 there was no impairment provision required on any of
the financial assets of the Trust due to historical success of collecting
receivables. The Trust does have a credit risk exposure as the majority
of the Trust's accounts receivable are with counterparties having similar
characteristics. However, payments from the Trust's largest accounts
receivable counter parties have always been received within 30 days and
the sales agreements with these parties are cancellable with 30 days
notice if payments are not received.

The carrying value of accounts receivable approximates their fair value
due to the relatively short periods to maturity on this instrument. The
maximum exposure to credit risk is represented by the carrying amount on
the balance sheet. There are no material financial assets that the Trust
considers past due.

Liquidity risk

Liquidity risk includes the risk that, as a result of Bonterra's
operational liquidity requirements:



-   The Trust will not have sufficient funds to settle a transaction on
    the due date;

-   Bonterra will not have sufficient funds to continue with its
    distributions

-   The Trust will be forced to sell assets at a value which is less than
    what they are worth; or

-   Bonterra may be unable to settle or recover a financial asset at all.

To help reduce these risks the Trust:

-   Has a capital policy of maintaining no more than approximately one
    year debt to adjusted distribution base;

-   Uses of derivative instruments that are readily tradable should the
    need arise; and

-   Maintains a portfolio of high-quality, long reserve life oil and gas
    assets.

c) Risk management contracts

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

                                      Volume
Period of Agreement     Commodity     per day   Index    Price (Cdn.)
-------------------------------------------------------------------------
July 1, 2008 to         Crude Oil    500 barrels   WTI   Floor of $73.00
 December 31, 2008                                       and ceiling of
                                                         $80.68 per
                                                         barrel
July 1, 2008 to         Crude Oil    500 barrels   WTI   Floor of $85.00
 December 31, 2008                                       and ceiling of
                                                         $104.80 per
                                                         barrel
April 1, 2008 to        Natural Gas  1,500 GJ's   AECO   Floor of $6.00
 October 31, 2008                                        and ceiling of
                                                         $7.60 per GJ 

 


As of September 30, 2008, the fair value of the outstanding commodity
risk management contracts was a net liability of $2,044,000
(December 31, 2007 - $3,085,000).

10. UNREALIZED LOSS ON RISK MANAGEMENT CONTRACTS

The following table reconciles the movement in the fair value of the
Trust's financial risk management contracts that have not been designated
as effect accounting hedges for the periods ended September 30:



                          Three Months                Nine Months
($000)                2008          2007          2008          2007
-------------------------------------------------------------------------
Fair Value,
 beginning of period   (10,110)          710        (3,085)        1,149
Fair Value, end of
 period                 (2,044)          511        (2,044)          511
-------------------------------------------------------------------------
Unrealized gain (loss)
 on risk management
 contracts               8,066          (199)        1,041          (638)
-------------------------------------------------------------------------

 


11. RESTATEMENT

The Trust has determined that its cash flow hedges on commodities are no
longer effective hedges for accounting purposes. The following financial
statement items have been restated to eliminate the use of hedge
accounting:



Three months ended
 September 30, 2007
($000 except $ per unit)            Reported    Adjustment      Restated
-------------------------------------------------------------------------
Unrealized loss on risk management
 contracts                                 -          (199)         (199)
Future tax expense (recovery)         (1,110)          (58)       (1,168)
Net earnings for the period            9,086          (141)        8,945
Deficit at beginning of period       (42,489)         (311)      (42,800)
Deficit at end of period             (44,567)         (452)      (45,019)
Net earnings per unit
 (basic and diluted)                    0.54         (0.01)         0.53
Other comprehensive income               401           141           542
-------------------------------------------------------------------------
Nine months ended
 September 30, 2007
($000 except $ per unit)            Reported    Adjustment      Restated
-------------------------------------------------------------------------
Unrealized loss on risk management
 contracts                                 -          (638)         (638)
Future tax expense (recovery)          2,705          (186)        2,519
Net earnings for the period           22,430          (452)       21,978
Deficit at end of period             (44,567)         (452)      (45,019)
Net earnings per unit
 (basic and diluted)                    1.33         (0.03)         1.30
Other comprehensive income               718           452         1,170
-------------------------------------------------------------------------

 


12. SUBSEQUENT EVENT - DISTRIBUTIONS

Subsequent to September 30, 2008, the Trust declared a distribution of
$0.32 per unit payable on October 31, 2008 to Unitholders of record on
October 16, 2008.

On November 6, 2008, the Trust declared a distribution of $0.26 per unit
payable on November 28, 2008 to Unitholders as of November 17, 2008.
However, if the plan of arrangement does close as scheduled, the payment
will be considered a dividend payable on November 28, 2008 to
shareholders of record as of November 24, 2008.

13. SUBSEQUENT EVENT - REORGANIZATION

Trust has commenced with the conversion from a trust to a corporation by
plan of arrangement dated September 17, 2008 along with a corporate
acquisition both of which were ratified by the Unitholders and other
parties to the arrangement on October 16, 2008. Subject to court approval
the reorganization and acquisition are scheduled to close on or about

November 12, 2008.

The corporate acquisition will be completed by a cash payment of
approximately $13,468,000, issue of 7,745 trust units and the assumption
of approximately $16,500,000 of negative working capital and debt. In
addition, payments of approximately $11,250,000 cash to creditors of SRX
Post Holdings Inc. and a $1,000,000 finder's fee will be required on the
closing of the arrangement.

%SEDAR: 00017467E

Additional information relating to the Trust may be found on www.sedar.com


FOR FURTHER INFORMATION PLEASE CONTACT:

Bonterra Oil & Gas Ltd.
George F. Fink
President, and CEO
(403) 262-5307
Fax: (403) 265-7488

or

Bonterra Oil & Gas Ltd.
Garth E. Schultz
Vice President - Finance, and CFO
(403) 262-5307
Fax: (403) 265-7488
info@bonterraenergy.com
www.bonterraenergy.com

 

 
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