Bonterra Energy Corp.

Bonterra Energy Corp.

May 13, 2008 23:59 ET

Bonterra Energy Income Trust Announces First Quarter Results

CALGARY, ALBERTA--(Marketwire - May 13, 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 ended March 31, 2008.



HIGHLIGHTS
----------

For the three months ended March 31, December 31, March 31,
($000 except $ per unit) 2008 2007 2007
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FINANCIAL
Revenue - realized oil and
gas sales 30,493 26,573 22,602
Adjusted Distribution Base(1) 18,058 15,842 13,129
Per Unit - Basic 1.07 0.94 0.78
Per Unit - Diluted 1.06 0.94 0.78
Cash Distributions per Unit 0.70 0.66 0.66
Payout Ratio 66% 70% 85%
Net Earnings 10,804 7,920 7,662
Per Unit - Basic 0.64 0.47 0.45
Per Unit - Diluted 0.64 0.47 0.45
Capital Expenditures and
Acquisitions 6,421 7,213 7,625
Total Assets 150,169 143,239 140,926
Working Capital Deficiency(2) 57,810 58,766 49,288
Unitholders' Equity 48,136 44,218 57,646
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OPERATIONS
Oil and NGL's - Barrels Per Day 3,153 3,098 3,227
- Average Price
($ per barrel) $ 87.20 $ 77.60 $ 62.53
Natural Gas - MCF Per Day 7,139 7,176 6,470
- Average Price
($ per MCF) $ 8.32 $ 6.70 $ 7.52
Total Barrels Per Day(3) 4,343 4,295 4,305

(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 pages 7 and8 of this press
release for the reconciliation between adjusted distribution base and
standardized distributable cash.
(2) Includes 100 percent of debt.
(3) BOE's are calculated using a conversion ratio of 6 MCF to 1 barrel of
oil. The conversion is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead and as such may be misleading if
used in isolation.


Forward-looking Information

Certain statements contained in this press release include statements which contain words such as "anticipate", "could", "should", "expect", "seek", "may", "intend", "likely", "will", "believe" and similar expressions, relating to matters that are not historical facts, and such statements of our beliefs, intentions and expectations about development, results and events which will or may occur in the future, constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and are based on certain assumptions and analysis made by us derived from our experience and perceptions. Forward-looking information in this press release includes, but is not limited to: expected cash provided by continuing operations; cash distributions; future capital expenditures, including the amount and nature thereof; oil and natural gas prices and demand; expansion and other development trends of the oil and gas industry; business strategy and outlook; expansion and growth of our business and operations; and maintenance of existing customer, supplier and partner relationships; supply channels; accounting policies; credit risks; and other such matters.

All such forward-looking information is based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate in the circumstances. The risks, uncertainties, and assumptions are difficult to predict and may affect operations, and may include, without limitation: foreign exchange fluctuations; equipment and labour shortages and inflationary costs; general economic conditions; industry conditions; changes in applicable environmental, taxation and other laws and regulations as well as how such laws and regulations are interpreted and enforced; the ability of oil and natural gas trusts to raise capital; the effect of weather conditions on operations and facilities; the existence of operating risks; volatility of oil and natural gas prices; oil and gas product supply and demand; risks inherent in the ability to generate sufficient cash flow from operations to meet current and future obligations; increased competition; stock market volatility; opportunities available to or pursued by us; and other factors, many of which are beyond our control.

Actual results, performance or achievements could differ materially from those expressed in, or implied by, this forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do, what benefits will be derived therefrom. Except as required by law, Bonterra disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

The forward-looking information contained herein is expressly qualified by this cautionary statement.

General

Bonterra is pleased to report its operating and financial results for the first quarter of 2008. It was the best quarter in the Trust's history, mainly attributable to higher commodity prices and a modest increase in production volumes.

When comparing results from Q1, 2008, with Q4, 2007, and Q1, 2007, revenue increased by 15 percent and 35 percent, respectively; adjusted distribution base (formerly funds flow from operations) increased by 14 percent and 38 percent, respectively; and net earnings increased by 36 percent and 41 percent, respectively.

During the first quarter 2008 distributions increased by 13.6 percent, from $0.22 to $0.25 per Unit per month. The payout ratio for Q1, 2008, was 66 percent compared to 70 percent in Q4, 2007, and 85 percent in Q1, 2007. Bonterra is projecting a payout ratio of between 75 and 80 percent for 2008 and will pay distributions accordingly.

During the first quarter Bonterra incurred capital expenditures of $6,421,000 (budget of $20,000,000 for 2008) in drilling 10 operated gross (8.1 net) Cardium oil wells and 1 operated gross (0.1 net) shallow gas well and 3 (0.4 net) Cardium oil wells on non-operated lands. At March 31, 2008, Bonterra had 8 gross (6.0 net) Cardium oil wells, 2 gross (1.1 net) natural gas wells, and 3 (2.5 net) coal bed methane (CBM) wells drilled but not on production. It is expected that the Cardium oil and one shallow gas well will be completed for production in Q2 and Q3, 2008. The CBM wells will not be completed until the Alberta government has finalized its regulations with regard to CBM wells.

The Trust will commence with further drilling of its large inventory of undrilled locations in Q3, 2008. Bonterra has an inventory of 15 years of undrilled locations. During 2008 approximately 10 wells will also be reworked and re-fraced.

Financial and Operational Discussion

Production

Production volumes for the first quarter were affected by several factors. Firstly, the operator of one of the Trusts non-operated properties discovered that the payout of a natural gas well had not been calculated properly. As a result the operator issued an adjustment of approximately 12,400 MCF of natural gas net to the Trust for production that was incorrectly paid to the Trust during the period 2002 to 2008. This reduced Bonterra's daily production by approximately 23 BOE. Secondly, the operator of a natural gas plant where approximately 30 percent of the Trust's Pembina production gets processed conducted an extensive turnaround during the month of March resulting in an average of approximately 400 MCF per day (67 BOE per day for the month of March) of natural gas being shut-in. Also the severe cold weather during the later part of January and early February resulted in several wells going down for an extended period of time. A significant work over program was conducted during the later part of February as well as March to ensure that as many of the wells as possible were back on production prior to spring breakup.

Revenue

Revenue from petroleum and natural gas sales (including realized hedge gains and losses) for the quarter was $30,493,000 (2007 - $22,602,000). This is the highest single quarter revenue ever recorded by the Trust. The increase in revenue over the 2007 first quarter was primarily due to higher commodity prices. The average price received for crude oil and natural gas liquids during the first quarter of 2008 was $87.20 per barrel and $8.32 per MCF for natural gas compared to $62.53 per barrel and $7.52 per MCF in the corresponding 2007 period. On a quarter over quarter basis, realized revenue increased by $3,920,000 due to increased production volumes and increases in commodity prices.

Included in revenue is a realized loss on risk management contracts of $1,367,000 ($590,000 gain in 2007). In addition the Trust also recorded an unrealized loss on risk management contracts of $2,389,000 (2007 - $1,753,000). All fair value adjustments related to outstanding risk management contracts are recorded as adjustments to net earnings.

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 March 31, 2008, the fair value of the outstanding risk management contracts was a net liability of $5,474,000 (December 31, 2007 - $3,085,000).

Royalties

Royalties paid by the Trust consist primarily of Crown royalties paid to the Provinces of Alberta and Saskatchewan. During the first quarter of 2008 the Trust paid $3,613,000 (2007 - $2,156,000) in Crown royalties and $731,000 (2007 - $422,000) in freehold royalties, gross overriding royalties and net carried interests. The majority of the Trust's wells are low productivity wells and therefore have low Crown royalty rates. The Trust's average Crown royalty rate is approximately 11.3 percent (2007 - 9.8 percent) and approximately 2.3 percent (2007 - 1.9 percent) for other royalties before hedging adjustments.

During the first quarter of 2008, the operator of one of the Trusts larger non-operated properties was reassessed by the Alberta government for underpayment for previous years Crown royalties of approximately $1,100,000 ($166,000 net to Bonterra). Bonterra continues to expect an average royalty rate of approximately 13 percent for the balance of 2008.

The recently announced royalty amendments will result in a slightly higher average royalty rate for Bonterra in 2009 and beyond. The Trust is still evaluating the impact of the new royalty rates to both its current production as well as its capital programs as the determination of how to calculate certain royalties still have to be finalized by the government.

Production Costs

Production costs for the three months ended March 31, 2008 were $6,317,000 compared to $5,581,000 for the three months ended March 31, 2007. On a BOE basis production costs averaged $15.98 in 2008 compared to $14.40 in the corresponding 2007 period.

Due to the severe cold weather in late January and early February the Trust incurred significantly higher production costs to reactivate wells that were effected by the cold. In addition, the Trust performed an enhanced field maintenance program in March in combination with the turnaround at one of its more significant non-operated gas plants resulting in excess of $500,000 of well workover costs in March. Although the Trust sees continued reduction in drilling costs, well service costs continue to increase.

The Trust's production comes primarily from low productivity wells. These wells generally result in higher production costs on a per unit-of-production basis as costs such as municipal taxes, surface lease, power and personnel costs are not variable with production volumes. Production costs in the $13.50 to $14.50 per BOE range are expected for the remainder of 2008. The high production costs for the Trust are substantially offset by low royalty rates of approximately 13 percent, which is much lower than industry average for conventional production and results in high cash net backs on a combined basis despite higher than average production costs.

General and Administrative Expenses

General and administrative expenses were $877,000 in the first quarter of 2008 compared to $564,000 in the three months ended March 31, 2007 and $739,000 in the three months ended December 31, 2007. Costs on a BOE bases increased to $2.22 per BOE in the first quarter of 2008 from $1.46 per BOE in the first quarter of 2007.

The increase in general and administrative expenses year over year was due to increased employee compensation of approximately $250,000 as well as increases in other professional service costs of approximately $75,000. The quarter over quarter increase was due primarily to increased employee compensation expense and increased annual report and TSX and security commission filing costs associated with filing of the annual report and other continuous disclosure documentation during the first quarter.

Interest Expense

Interest expense increased to $799,000 for the three months ended March 31, 2008 compared to $697,000 for the three months ended March 31, 2007 and decreased from $878,000 for the fourth quarter of 2007. The year over year increase was due to higher average debt levels of approximately $9,000,000 during the first quarter of 2008 offset by slightly lower average interest rates.

Quarter over quarter decrease was due primarily to significantly lower interest rates. Bonterra is currently able to borrow at rates between 4.35 and 4.75 percent per annum compared to an average rate of over 6 percent in the fourth quarter of 2007.

The Trust's bank loan of $58,913,000 increased by approximately $1.5 million from December 31, 2007. Increased cash flow resulting from record crude oil prices coupled with the Trust's lower payout ratio resulted in only a slight increase in the Trusts net debt despite an approximate $6.5 million capital program during the first quarter of 2008. With spring breakup during the second quarter (restricting Bonterra's capital programs) and continuing record commodity prices the Trust anticipates reduced debt levels for the second and third quarters of 2008 and therefore lower interest costs during the next two quarters.

The Trust's net debt as a percentage of annualized first quarter adjusted distribution base was approximately nine and a half months. The Trust believes that maintaining debt at or less than one year's adjusted distribution base (calculated quarterly based on annualized quarterly results) is an appropriate level to allow it to take advantage in the future of either acquisition opportunities or to provide flexibility to develop its infill oil, shallow gas and CBM potential from its cash flow and from additional bank loans and it will not be necessary to issue more trust units.

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. No employee unit options were issued during the first quarter of 2008. If no further options are issued approximately $720,000 of compensation expense will be expensed during 2008 and 2009.

Depletion, Depreciation, Accretion and Dry Hole Costs

Provision for depletion, depreciation and accretion was $3,494,000 and $3,502,000 for the three month periods ending March 31, 2008 and March 31, 2007 respectively. The marginal decline in the depletion amount was due primarily to increased reserves resulting from the Trust's December 31, 2007 independent engineering report offset by slightly higher production rates.

The Trust continues to replace production declines with 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 quarter of 2008 have been successful and therefore no dry hole costs were recorded during the first quarter of 2008.

Taxes

Future income tax expense for the first quarter of 2008 increased by $1,561,000 compared to the first quarter of 2007. Until June 2007, the Trust had been tax effecting the reversal of taxable temporary differences at a nil tax rate on the assumption that the Trust would make sufficient tax deductible cash distributions to Unitholders such that the Trust's taxable income would be nil for the foreseeable future and the tax burden would have continued to be with whomever received the monthly distribution. The new legislation limits the tax deductibility of cash distributions such that income taxes may become payable in the future.

The Trust has estimated its future income taxes based on its best estimates of results from operations and tax pool claims and cash distributions in the future assuming no material change to the Trust's current organizational structure. As currently interpreted, Canadian Generally Accepted Accounting Principles ("GAAP") does not permit the Trust's estimate of future income taxes to incorporate any assumptions related to a change in organizational structure until such structures are given legal effect even though it is anticipated that many trusts will change their organizational structure to attempt to reduce this impact.

The Trust's estimate of its future income taxes will vary as to the Trust's assumptions pertaining to the factors described above, and such variations may be material.

Until 2011, the new legislation does not directly affect the Trust's cash flow from operations, and accordingly, the Trust's financial condition.

Currently taxable income earned within the Trust is required to be allocated to its Unitholders and as such the Trust will not incur any current taxes. However, the Trust operates its oil and gas interests through its 100 percent owned subsidiaries Bonterra Energy Corp. ("Bonterra Corp.") and Novitas Energy Ltd. ("Novitas") and these corporations may periodically be taxable.

These corporations pay the majority of their income to the Trust through interest and royalty payments which are deductible for income tax purposes. The current tax provision relates to resource surcharge payable by the Trust's subsidiaries to the Province of Saskatchewan. The surcharge is calculated as a flat percent of revenues generated from the sale of petroleum products produced in Saskatchewan. The provincial government of Saskatchewan has reduced the resource surcharge rate to 3.1 percent on July 1, 2007 and to 3.0 percent on July 1, 2008.

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

Net Earnings

Net earnings increased to an all time high of $10,804,000 in the first quarter of 2008 from $7,662,000 in the corresponding 2007 period. Revenue increases due to increased commodity prices and production were partially offset by increased operating costs and a higher future tax provision. The Trust's quarter over quarter net earnings increased $2,884,000 primarily due to increased commodity prices.

The Trust returned to its Unitholders in excess of 35 percent of its gross realized revenues in net earnings. The Trust's low capital costs combined with a low debt to adjusted distribution base ratio all contribute to the high return. Bonterra's higher than industry average per unit operating costs are more than offset with its low royalty rates resulting in one of the highest cash net backs in the industry (see cash netback).

Comprehensive Income

On January 1, 2007 the Trust 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 quarter of 2008 included an increase in the unrealized gain on investment in a related party of $171,000 (2007 - $982,000) net of applicable income taxes.

Standardized Distributable Cash

Compliance with Guidance

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



Definition and Disclosure of Standardized Distributable Cash

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Cumulative
Amounts From
Inception of
Three Three Trust (July 1,
Months Ended Months Ended 2001) to
March 31, March 31, March 31,
($000) 2008 2007 2008
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Cash Flow from Operating
Activities 16,212 12,765 234,487
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Less adjustment for:
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Capital expenditures (6,421) (7,625) (100,919)
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Financing restrictions
caused by debt - - -
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Standardized Distributable
Cash 9,791 5,140 133,568
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Definition and Disclosure of Adjusted Distribution Base (Formerly Funds
Flow from Operations)
-------------------------------------------------------------------------
Cumulative
Amounts From
Inception of
Three Three Trust (July 1,
Months Ended Months Ended 2001) to
March 31, March 31, March 31,
($000) 2008 2007 2008
-------------------------------------------------------------------------
Standardized Distributable
Cash - per above 9,791 5,140 133,568
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Adjusted for:
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Capital expenditures 6,421 7,625 100,919
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Gain on sale of property - - 1,089
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Changes in accounts receivable 3,201 (539) 8,777
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Changes in crude oil inventory (142) 14 111
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Changes in parts inventory (14) (8) (204)
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Changes in prepaid expenses (55) (48) 443
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Changes in accounts payable
and accrued liabilities (2,871) 897 (1,008)
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Asset retirement obligations
settled 1,727 48 4,256
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Adjusted Distribution Base(1) 18,058 13,129 247,951
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(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 reoccurring items that would cause a seasonal impact in working capital.



Analysis of Relationship between Standardized Distributable Cash,
Distributions, and Investing and Financing Activities
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Three
Months Ended Year ended Year ended Year ended
March 31, December 31, December 31, December 31,
($000) 2008 2007 2006 2005
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Standardized
Distributable
Cash 9,791 32,133 14,346 23,413
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Distributions(1) (11,862) (44,648) (47,281) (38,949)
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Increase in bank
debt 1,491 12,043 25,202 11,717
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Proceeds on
exercise of
employee unit
options 280 993 5,161 2,823
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Issuance of units
(net of costs of
issue) - - - (259)
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Non cash financing
and investing
working capital
adjustments 300 (521) 2,572 1,255
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(1) Includes the distribution declared in April in respect of March
operations and excludes the January 31, 2008 distribution as it was
in respect of December 2007 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)
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2008 (including expenditures incurred to date) 2,227
2009 250
2010 175
2011 563
2012 856
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4,071
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Definition and History of Productive Capacity and Strategy

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



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Three
Months Ended Year ended Year ended Year ended
March 31, December 31, December 31, December 31,
2008 2007 2006 2005
-------------------------------------------------------------------------
Proven and
probable reserves
at beginning of
period (BOE's) 27,320,000 26,476,000 23,870,000 19,711,000
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Reserves added due
to acquisitions
(BOE's) - (421,000) 16,000 2,393,000
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Reserves added due
to capital
expenditures
(BOE's) (1) 2,806,000 4,082,000 3,100,000
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Production during
period (BOE's) 395,000 1,540,000 1,476,000 1,334,000
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Increase in
productive
capacity (BOE's) (1) 845,000 2,606,000 4,159,000
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Reserves per unit
(fully diluted) 1.59(1)(2) 1.62 1.57 1.46
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Productive
capacity
maintenance
requirements $ 4,373,000 $ 17,043,000 $ 17,472,000 $ 9,205,000
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Capital
expenditures for
the period $ 6,421,000 $ 19,300,000 $ 38,348,000 $ 56,703,000
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Capital
expenditures in
excess of
maintenance
requirements $ 2,048,000 $ 2,257,000 $ 20,876,000 $ 47,498,000
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Cost of increased
productive
capacity (per BOE) (1) $ 2.67 $ 8.01 $ 11.42
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(1) The Trust does not update reserve information quarterly.
(2) Assuming no other additional reserves 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 to finance its capital maintenance expenditures. Over the past years, this level of retention of adjusted distribution base, along with the exercising or 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, equity placements or from its line of credit.

Periods may exist where the cost of replacing reserves exceed the level of funds withheld. However, the Trust with its long life reserves and relatively low debt levels compared to other income trusts has the flexibility to increase or decrease its capital commitments depending on commodity prices and costs of development.

It is management's strategy to finance the costs of reclamation as well as potential income taxes (commencing in 2011) resulting from the recently enacted income trust tax law from the adjusted distribution base. Management is reviewing various organizational alternatives and operational strategies to mitigate the impact of the new tax.

Compliance with Financial Covenants

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



Per Unit and Ratio Disclosures
-------------------------------------------------------------------------
Cumulative
Amounts From
Inception of
Three Three Trust (July 1,
Months Ended Months Ended 2001) to
March 31, March 31, March 31,
($000 except $ per unit) 2008 2007 2008
-------------------------------------------------------------------------
Standardized Distributable Cash 9,791 5,140 133,568
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Per weighted average unit 0.58 0.30 8.59
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Per fully diluted unit 0.58 0.30 8.54
-------------------------------------------------------------------------
Cash distributions(1) 11,862 11,145 216,161
-------------------------------------------------------------------------
Payout ratio 1.21 2.17 1.74
-------------------------------------------------------------------------
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Adjusted Distribution Base 18,058 13,129 247,951
-------------------------------------------------------------------------
Per weighted average unit 1.07 0.78 16.00
-------------------------------------------------------------------------
Per fully diluted unit 1.06 0.78 15.88
-------------------------------------------------------------------------
Cash distributions(1) 11,862 11,145 216,161
-------------------------------------------------------------------------
Payout ratio 0.66 0.85 0.87
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(1) Includes distribution declared in April 2008 and 2007 in respect of
March 2008 and 2007 operations respectively.


On a go forward basis the Trust plans to reduce the payout ratio in respect of Standardized Distributable Cash to a level between 110 to 120 percent to facilitate a debt to cash flow level of approximately one year and to not incur current tax (excluding Saskatchewan Resource Surcharge). This will be attained through controlling costs of capital replacement, by examining lower cost methods of reserve replacement as well as increased cash flow from wells currently producing.

Tax Attributes of Distributions and the Trust's Assets

See discussion under Taxes.

Cash Netback

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



$ per Barrel of Oil March 31 December 31 March 31
Equivalent (BOE) 2008 2007 2007
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Production volumes (BOE) 395,176 395,154 387,454
Gross production revenue $ 80.62 $ 68.02 $ 56.81
Realized gain (loss) on risk
management contracts (3.46) (0.77) 1.52
Royalties (10.99) (8.39) (6.65)
Field operating (15.98) (14.01) (14.40)
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Field netback 50.19 44.85 37.28
General and administrative (2.22) (1.87) (1.46)
Interest and taxes (2.30) (2.89) (1.99)
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Cash netback $ 45.67 $ 40.09 $ 33.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Liquidity and Capital Resources

During the first quarter of 2008, the Trust incurred capital costs of $6,421,000 (2007 - $7,625,000). The Trust and its partners drilled 13 gross (8.5 net) Cardium oil wells and one gross (0.1 net) shallow gas wells in the first quarter of 2008.

The Trust currently has plans to drill a total of 25 gross (20 net) Cardium infill oil wells in 2008 as well as up to 10 gross shallow gas wells. Total capital costs of approximately $20,000,000 are budgeted for 2008. It is anticipated that the entire 2008 capital expenditures will be funded from cash flow and funds from the exercising of employee unit options. Should it be necessary the Trust will use its financial facilities to cover any shortfall.

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

Sensitivity Analysis

Commodity prices have fluctuated significantly over the recent past. The following table updates the cash flow sensitivity for movements in the commodity prices of $1 US 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 the first quarter of 2008 as well as updated diluted unit calculations.



Cash Flow
Cash Flow Per Unit
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U.S. $1.00 per barrel $ 692,000 $ 0.041
Canadian $0.10 per MCF $ 181,000 $ 0.011
Change of Canadian $0.01/U.S. $ exchange rate $ 587,000 $ 0.035
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CONSOLIDATED BALANCE SHEETS
As at March 31, 2008 (unaudited) and
December 31, 2007
($000) 2008 2007
Assets
Current
Accounts receivable 13,776 10,575
Crude oil inventory 597 792
Parts inventory 118 132
Prepaid expenses 1,275 1,330
Future income tax asset (Note 5) 1,617 913
Investments in related party (Note 2) 4,138 4,014
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21,521 17,756
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Property and Equipment (Note 3)
Petroleum and natural gas properties and
related equipment 193,709 187,288
Accumulated depletion and depreciation (65,061) (61,805)
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Net Property and Equipment 128,648 125,483
-------------------------------------------------------------------------
150,169 143,239
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Liabilities
Current
Distribution payable - 3,724
Accounts payable and accrued liabilities 14,944 12,291
Derivative liability (Note 9) 5,474 3,085
Debt (Note 4) 58,913 57,422
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79,331 76,522
Future Income Tax Liability (Note 5) 9,339 7,595
Asset Retirement Obligations 13,363 14,904
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102,033 99,021
-------------------------------------------------------------------------
Commitments (Note 9)
Unitholders' Equity (Note 6)
Unit capital 90,900 90,590
Contributed surplus 2,393 2,140
-------------------------------------------------------------------------
93,293 92,730
-------------------------------------------------------------------------
Deficit (48,359) (51,543)
Accumulated other comprehensive income (Note 7) 3,202 3,031
-------------------------------------------------------------------------
(45,157) (48,512)
-------------------------------------------------------------------------
Total Unitholders' Equity 48,136 44,218
-------------------------------------------------------------------------
150,169 143,239
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

For the Three Months Ended March 31 (unaudited)
($000) 2008 2007
Unitholders' equity, beginning of period 44,218 53,359
Comprehensive income for the period 10,975 8,644
Adjustment of opening accumulated
comprehensive income - 2,380
Net capital contributions (Note 6) 280 471
Unit based compensation adjustment 283 218
Distributions declared (7,620) (7,426)
-------------------------------------------------------------------------
Unitholders' Equity, End of Period 48,136 57,646
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

For the Three Months Ended March 31 (unaudited)
($000, except $ per unit) 2008 2007

(Note 10)
Revenue
Oil and gas sales 31,860 22,012
Realized gain (loss) on risk management
contracts (1,367) 590
Unrealized loss on risk management contracts (2,389) (1,753)
Royalties (4,344) (2,578)
Interest and other 13 21
-------------------------------------------------------------------------
23,773 18,292
-------------------------------------------------------------------------
Expenses
Production costs 6,317 5,581
General and administrative 877 564
Interest on debt 799 697
Unit option based compensation 283 218
Dry hole costs - 467
Depletion, depreciation and accretion 3,494 3,502
-------------------------------------------------------------------------
11,770 11,029
-------------------------------------------------------------------------
Earnings Before Taxes 12,003 7,263
-------------------------------------------------------------------------
Taxes (Recovery) (Note 5)
Current 111 74
Future 1,088 (473)
-------------------------------------------------------------------------
1,199 (399)
-------------------------------------------------------------------------
Net Earnings for the Period 10,804 7,662
Deficit at beginning of period (51,543) (37,245)
Distributions declared (7,620) (7,426)
-------------------------------------------------------------------------
Deficit at End of Period (48,359) (37,009)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Earnings Per Unit - Basic and Diluted 0.64 0.45
-------------------------------------------------------------------------
-------------------------------------------------------------------------


CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the Three Months Ended March 31 (unaudited)
($000, except $ per unit) 2008 2007
(Note 10)
Net Earnings for the Period 10,804 7,662
Other Comprehensive Income, net of income tax
Unrealized gains and losses on investments
(net of income taxes of 2008 - ($47), 2007 - $170) 171 982
-------------------------------------------------------------------------
Other Comprehensive Income 171 982
-------------------------------------------------------------------------
Comprehensive Income 10,975 8,644
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Comprehensive Income Per Trust Unit - Basic
and Diluted 0.65 0.51
-------------------------------------------------------------------------


CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31 (unaudited)
($000) 2008 2007
(Note 10)
Operating Activities
Net earnings for the period 10,804 7,662
Items not affecting cash
Unrealized loss on risk management contracts 2,389 1,753
Unit option based compensation 283 218
Dry hole costs - 467
Depletion, depreciation and accretion 3,494 3,502
Future income taxes 1,088 (473)
-------------------------------------------------------------------------
18,058 13,129
-------------------------------------------------------------------------
Change in non-cash working capital
Accounts receivable (3,201) 539
Crude oil inventory 142 (14)
Parts inventory 14 8
Prepaid expenses 55 48
Accounts payable and accrued liabilities 2,871 (897)
Asset retirement obligations settled (1,727) (48)
-------------------------------------------------------------------------
(1,846) (364)
-------------------------------------------------------------------------
Cash Provided by Operating Activities 16,212 12,765
-------------------------------------------------------------------------
Financing Activities
Increase in debt 1,491 7,456
Unit option proceeds 280 471
Unit distributions (11,344) (11,476)
-------------------------------------------------------------------------
Cash Used in Financing Activities (9,573) (3,549)
-------------------------------------------------------------------------
Investing Activities
Property and equipment expenditures (6,421) (7,625)
Change in non-cash working capital
Accounts receivable - 264
Accounts payable and accrued liabilities (218) (1,855)
-------------------------------------------------------------------------
Cash Used in Investing Activities (6,639) (9,216)
-------------------------------------------------------------------------
Net Cash Inflow - -
Cash, beginning of period - -
-------------------------------------------------------------------------
Cash, End of Period - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash Interest Paid 799 697
Cash Taxes Paid 278 90
-------------------------------------------------------------------------


NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

Periods Ended March 31, 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 is currently evaluating the impact of the adoption of this new Section on its consolidated financial statements. The Trust does not expect that the adoption of this new Section will have a material impact on its consolidated financial statements.

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 March 31, 2008 of $6 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

March 31, 2008 December 31, 2007
Accumulated Accumulated
Depletion and Depletion and
($000) Cost Depreciation Cost Depreciation
-------------------------------------------------------------------------
Undeveloped land 316 - 316 -
Petroleum and natural gas
properties and
related equipment 192,348 64,334 185,947 61,105
Furniture, equipment
and other 1,045 727 1,025 700
-------------------------------------------------------------------------
193,709 65,061 187,288 61,805
-------------------------------------------------------------------------
-------------------------------------------------------------------------


4. DEBT

The Trust, through its operating subsidiaries, has a bank revolving credit facility of $69,900,000 at March 31, 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 March 31, 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. Cash interest paid during the three month periods ended March 31, 2008 and 2007 for these loans was $799,000 and $697,000 respectively.



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:

March 31, December 31,
($000) 2008 2007
-------------------------------------------------------------------------
Future income tax liability to assets
and liabilities: 12,226 11,517
Future tax asset related to finance costs: (63) (79)
Future tax asset related to corporate tax
losses carried forward in the subsidiary companies (2,824) (3,843)
-------------------------------------------------------------------------
Future income tax liability 9,339 7,595
-------------------------------------------------------------------------
Future income tax asset related to current
portion of derivative liability 1,617 913
-------------------------------------------------------------------------
Income tax expense varies from the amounts that would be computed by
applying Canadian federal and provincial income tax rates as follows:
($000) 2008 2007
-------------------------------------------------------------------------
Earnings before income taxes 12,003 7,263
Combined federal and provincial income tax rates 30.09% 32.27%
-------------------------------------------------------------------------
Income tax provision calculated using statutory
tax rates 3,612 2,344
Increase (decrease) in taxes resulting from:
Saskatchewan resource surcharge 111 74
Unit-based compensation 85 91
Change in statutory tax rates (675) (688)
Trust income allocated to Unitholders (1,822) (2,396)
Others (112) 176
-------------------------------------------------------------------------
Tax expense (recovery) 1,199 (399)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


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 17,817
Canadian oil and gas property expenditures 10 1,727
Canadian development expenditures 30 32,177
Canadian exploration expenditures 100 93
Income tax losses carried forward(1) 100 11,212
-------------------------------------------------------------------------
63,026
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Income tax losses carried forward expire in 2015 ($365,000), 2026
($4,826,000) and 2027 ($6,021,000).


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

Rate of
Utilization
($000) % Amount
-------------------------------------------------------------------------
Canadian oil and gas property expenditures 10 13,886
Finance costs 20 267
Eligible capital expenditures 7 342
-------------------------------------------------------------------------
14,495
-------------------------------------------------------------------------
-------------------------------------------------------------------------


On October 31, 2006, the Canadian Federal Government announced a proposed Trust taxation pertaining to taxation of distributions paid by publicly traded income trusts and this was enacted by legislation in June, 2007.

Previously, distributions paid to Unitholders, other than returns of capital, were claimed as a deduction by the Trust in arriving at taxable income whereby tax is eliminated at the Trust level and tax is paid on the distributions by the Unitholders. The June, 2007 legislation results in a two-tiered tax structure whereby distributions commencing in 2011 would first be subject to a 31.5 percent tax at the Trust level and then investors would be subject to tax on the distribution as if it were a taxable dividend paid by a taxable Canadian corporation. The tax rate was subsequently lowered to 29.5 percent in 2011 and 28 percent in 2012 and thereafter.

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 March 31, 2008, the Trust has estimated the amount of its temporary differences which are estimated to reverse post 2010 will be $14,757,000 (December 31, 2007 - $14,496,000) resulting in an additional $4,150,000 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.

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

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

6. UNIT CAPITAL

Authorized

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



Issued Number Amount
-------------------------------------------------------------------------
Trust Units ($000)
Balance, January 1, 2008 16,928,158 90,590
Issued pursuant to Trust's unit option plan 12,000 280
Transfer of contributed surplus to unit capital - 30
-------------------------------------------------------------------------
Balance, March 31, 2008 16,940,158 90,900
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The number of trust units used to calculate diluted net earnings per unit for the period ended March 31, 2008 of 16,957,486 (2007 - 16,913,263) included the basic weighted average number of units outstanding of 16,938,333 (2007 - 16,899,000) plus 19,153 (2007 - 14,263) units related to the dilutive effect of unit options.



The deficit balance is composed of the following items:

March 31, March 31,
($000) 2008 2007
-------------------------------------------------------------------------
Accumulated earnings 163,560 130,068
Accumulated cash distributions (211,919) (167,077)
-------------------------------------------------------------------------
Deficit (48,359) (37,009)
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The Trust provides an option plan for its directors, officers, employees and consultants. Under the plan, the Trust may grant options for up to 1,694,000 (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 March 31, 2008 and December 31, 2007, and changes during the three month and twelve month periods ended on those dates is presented below:



March 31, 2008 December 31, 2007
-------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding at
beginning of period 1,177,000 $27.59 721,500 $26.55
Options granted - - 553,000 28.11
Options exercised (12,000) 23.35 (53,500) 18.56
Options cancelled - - (44,000) 27.92
-------------------------------------------------------------------------
Outstanding at end
of period 1,165,000 $27.63 1,177,000 $27.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable
at end of period 528,000 $26.66 530,000 $26.63
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The following table summarizes information about unit options outstanding
at March 31, 2008:

Options Outstanding Options Exercisable
----------------------------------- ------------------------
Weighted-
Average Weighted- Weighted-
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices At 3/31/08 Life Price At 3/31/08 Price
-------------------------------------------------------------------------
$22.45-$23.35 213,000 1.1 years $23.34 213,000 $23.34
$24.20-$27.50 32,000 2.0 years 25.30 10,000 24.21
$28.30-$28.75 880,000 1.4 years 28.49 285,000 28.75
$32.00-$33.75 40,000 1.7 years 33.55 20,000 33.55
-------------------------------------------------------------------------
$22.45-$33.75 1,165,000 1.3 years $27.63 528,000 $26.66
-------------------------------------------------------------------------
-------------------------------------------------------------------------


The Trust records compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. No options have been granted in 2008, however, the Trust granted 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:



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


7. ACCUMULATED OTHER COMPREHENSIVE INCOME

Other
January 1, Comprehensive March 31,
($000) 2008 Income 2008
-------------------------------------------------------------------------
Unrealized gains and losses on
available-for sale financial assets 3,031 171 3,202
-------------------------------------------------------------------------


8. RELATED PARTY TRANSACTIONS

The Trust received a management fee from Comaplex of $82,000 (2007 - $75,000) for management services and office administration. This fee has been included as a recovery in general and administrative expenses. As at March 31, 2008 the Trust had an account receivable from Comaplex of $77,000 (December 31, 2007 - $63,000).

The Trust received a management fee from Pine Cliff Energy Ltd. (Pine Cliff) of $59,000 (2007 - $54,000) for management services and office administration. This fee has been included as a recovery in general and administrative expenses. As at March 31, 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 or other risk factors. The Trust does not speculatively trade in risk management contracts. The Trust's risk management contracts are entered into to hedge 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 or less than 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 coal bed methane potential without requiring the issuance of trust units.

Bonterra has a long term goal to retain between 20 to 25 percent of its adjusted distribution base to finance its capital expenditures.

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 and hedges 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 March 31, 2008 As at December 31, 2007
Carrying Fair Face Carrying Fair Face
($000) Value Value Value Value Value Value
Financial
assets
Accounts
receivable 13,776 13,776 13,801 10,575 10,575 10,595
Investments in
related party 4,138 4,138 - 4,014 4,014 -
Financial
liabilities
Distributions
payable - - - 3,724 3,724 3,724
Accounts payable
and accrued
liabilities 14,944 14,944 14,944 12,291 12,291 12,291
Derivative
liability 5,474 5,474 - 3,085 3,085 -
Debt 58,913 58,913 58,913 57,422 57,422 57,422
The net debt and adjusted distribution base figures for the quarters
ended March 31, 2008, December 31, 2007 and March 31, 2007 are
presented in Table 2.

Table 2
For the three month
periods ended March 31, December 31, March 31,
($000) 2008 2007 2007
---------------------------------------------------------------------
Debt 58,913 57,422 52,835
Distribution payable - 3,724 -
Accounts payable and accrued
liabilities 14,944 12,291 10,996
Derivative liability 5,474 3,085 605
Current assets (21,521) (17,756) (15,148)
---------------------------------------------------------------------
Net Debt 57,830 58,766 49,288
---------------------------------------------------------------------
Cash flow from operations 16,212 13,369 12,765
Changes in non-cash operating
working capital 119 2,185 316
Asset retirement obligations
settled 1,727 288 48
---------------------------------------------------------------------
Adjusted Distribution Base 18,058 15,842 13,129
Annualized adjusted
distribution base 72,232 63,368 52,516
---------------------------------------------------------------------
Net debt to adjusted
distribution base 0.80 0.93 0.94
---------------------------------------------------------------------


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 cash flow sensitivity for movements in the commodity prices of $1 US 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 the first quarter of 2008 as well as updated diluted unit calculations.



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 one year. This allows flexibility in obtaining cost effective financing.

Sensitivity Analysis

Based on historic movements and volatilities in the interest rate markets and managements 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. Noincome 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
March 31, 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
-----------
Accounts
payable and
accrued
liabilities - - - - - - - -
Derivative
liability - - - - - - - -
Debt (589) (589) 589 589 (574) (574) 574 574
-------------------------------------------------------------------------
Total
increase
(decrease) (589) (589) 589 589 (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 US currency then converted to Canadian currency. Bonterra mitigates this risk by using risk management contracts for 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.

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

Of the accounts receivable balance of March 31, 2008 ($13,776,000) 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 March 31, 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 March 31, 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 Trusts 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 a one year debt to adjusted distribution base.

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

- 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:



Period of Agreement Commodity Volume per day Index Price (Cdn.)
---------------------------------------------------------------------
January 1, 2008 to
June 30, 2008 Crude Oil 1,000 barrels WTI Floor of $73.00
and ceiling of
$83.00 per
barrel
July 1, 2008 to
December 31, 2008 Crude Oil 500 barrels WTI Floor of $73.00
and ceiling of
$80.68 per
barrel
July 1, 2008 to
December 31, 2008 Crude Oil 500 barrels WTI Floor of $85.00
and ceiling of
$104.80 per
barrel
April 1, 2008 to
October 31, 2008 Natural Gas 1,500 GJ's AECO Floor of $6.00
and ceiling of
$7.60 per GJ
As of March 31, 2008, the fair value of the outstanding commodity
hedging contracts was a net liability of $5,474,000 (December 31,
2007 - $3,085,000).


10. RESTATEMENT

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



Three months ended March 31, 2007
($000 except $ per unit) Reported Adjustment Restated
-------------------------------------------------------------------------
Unrealized loss on risk management
contracts - (1,753) (1,753)
Future tax expense (recovery) 38 (511) (473)
Net earnings for the period 8,904 (1,242) 7,662
Deficit at end of period (35,767) (1,242) (37,009)
Net earnings per unit (basic
and diluted) 0.53 (0.08) 0.45
Other comprehensive income (260) 1,242 982
-------------------------------------------------------------------------


11. SUBSEQUENT EVENT - DISTRIBUTION

Subsequent to March 31, 2008, the Trust declared distributions of $0.25 and $0.25 per unit payable on April 30 and May 30, 2008 to Unitholders of record on April 15 and May 15, 2008 respectively.

%SEDAR: 00017467E

For further information: Additional information relating to the Trust may be found on SEDAR.COM.

Contact Information

  • 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