Bonterra Energy Corp.
TSX : BNE

Bonterra Energy Corp.

March 24, 2011 17:10 ET

Bonterra Energy Corp. Announces Fourth Quarter and Annual 2010 Results

CALGARY, ALBERTA--(Marketwire - March 24, 2011) - Bonterra Energy Corp. ("Bonterra" or the "Company") (www.bonterraenergy.com) (TSX:BNE) is pleased to announce its financial and operational results for the three months and fiscal year ended December 31, 2010.



Annual Comparisons

As at and for the years ended December 31,
Financial ($000s, except $ per share) 2010 2009 2008
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Revenue - realized oil and gas 118,980 85,712 121,730
Funds Flow(1) 79,602 66,504 70,448
Per share basic 4.23 3.69 4.13
Per share diluted 4.12 3.67 4.12
Payout Ratio 60% 46% 76%
Cash flow from operations 66,262 38,893 69,570
Per share basic 3.52 2.16 4.07
Per share fully diluted 3.42 2.15 4.06
Payout ratio(2) 72% 79% 77%
Cash payments per share(2) 2.55 1.70 3.12
Net earnings (3) 49,864 68,563 55,426
Per share basic 2.65 3.81 3.25
Per share diluted 2.58 3.78 3.23
Capital expenditures and acquisitions
(net of disposals) 70,680 5,640 45,407
Total assets 335,144 293,987 265,301
Working capital deficiency 14,602 10,162 23,878
Long-term debt 85,386 59,823 79,910
Shareholders' equity 138,413 118,874 56,777
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Operations and liquids (barrels per day) 3,875 3,141 3,073
Natural gas (MCF per day) 10,521 11,120 7,637
Total BOE per day 5,628 4,994 4,346
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(1) Funds flow is not a recognized measure under GAAP. For these purposes,
the Company defines funds flow as funds provided by operations before
changes in non-cash operating working capital items but including gain
on sale of property, adjustments of investment tax credit receivable,
and excluding restricted cash and asset retirement obligations settled.
(2) Cash dividend payments per share are based on payments made in respect
of production months as opposed to the month paid.
(3) Net earnings includes gains from the sale of properties and investments
and recognition of investment tax credits before tax effect as follows:
(2010 - $10,820,000, 2009 - $51,868,000, 2008 - $Nil)

Quarterly Comparisons

2010
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Financial ($000s, except $ per share) 4th 3rd 2nd 1st
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Revenue - realized oil and gas 34,209 28,332 29,191 27,248
Funds Flow(1) 21,104 19,622 17,550 21,326
Per share basic 1.11 1.04 0.94 1.14
Per share fully diluted 1.08 1.01 0.91 1.11
Payout ratio(2) 61% 63% 68% 50%
Cash flow from operations 16,987 17,558 16,644 15,073
Per share basic 0.89 0.93 0.89 0.81
Per share diluted 0.86 0.91 0.86 0.79
Payout ratio(2) 74% 71% 72% 70%
Cash dividends per share(2) 0.68 0.66 0.64 0.57
Net earnings(3) 14,213 12,724 10,887 12,040
Per share basic 0.75 0.68 0.58 0.64
Per share diluted 0.73 0.66 0.56 0.63
Capital expenditures and acquisitions
(net of disposals) 25,318 19,227 10,994 15,141
Total assets 335,144 318,493 307,934 305,440
Working capital deficiency 14,602 17,891 2,281 13,178
Long-term debt 85,386 73,901 78,434 63,097
Shareholders' equity 138,413 128,492 126,045 125,392
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Operations
Oil and liquids (barrels per day) 4,378 3,890 3,874 3,345
Natural gas (MCF per day) 10,214 10,674 11,157 10,038
Total BOE per day 6,080 5,669 5,733 5,018
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(1) Funds flow is not a recognized measure under GAAP. For these purposes,
the Company defines funds flow as funds provided by operations before
changes in non-cash operating working capital items but including gain
on sale of property and investments, adjustments of investment tax
credit receivable, and excluding restricted cash and asset retirement
obligations settled.
(2) Cash dividend payments per share are based on payments made in respect
of production months as opposed to the month paid.
(3) Net earnings includes gains from the sale of properties and investments
and recognition of investment tax credits before tax effect as follows:
(2010 - $10,820,000, 2009 - $51,868,000)

2009
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Financial ($000s, except $ per share) 4th 3rd 2nd 1st
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Revenue - realized oil and gas 24,946 20,965 20,501 19,300
Cash flow from operations 13,673 9,350 9,238 6,632
Per share basic 0.76 0.50 0.52 0.38
Per share diluted 0.75 0.50 0.52 0.38
Payout ratio(2) 66% 87% 77% 94%
Funds Flow(1) 37,595 10,753 9,780 8,376
Per share basic 2.07 0.58 0.55 0.49
Per share diluted 2.06 0.57 0.55 0.49
Payout ratio(2) 24% 76% 73% 74%
Cash dividends per share(1) 0.50 0.44 0.40 0.36
Net earnings 52,136 5,790 4,544 6,093
Per share basic 2.88 0.32 0.26 0.35
Per share diluted 2.85 0.32 0.26 0.35
Capital expenditures and acquisitions
(net of disposals) (16,976) 17,660 2,255 2,701
Total assets 293,987 273,543 258,393 260,732
Working capital deficiency 10,162 14,455 13,989 14,909
Long-term debt 59,823 81,386 71,573 89,383
Shareholders' equity 118,874 74,025 72,332 56,377
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Operations
Oil and liquids (barrels per day) 3,182 3,084 3,029 3,268
Natural gas (MCF per day) 10,193 10,881 11,551 11,877
Total BOE per day 4,881 4,898 4,954 5,245
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(1) Funds flow is not a recognized measure under GAAP. For these purposes,
the Company defines funds flow as funds provided by operations before
changes in non-cash operating working capital items but including gain
on sale of property, adjustments of investment tax credit receivable,
and excluding restricted cash and asset retirement obligations settled.
(2) Cash dividend payments per share are based on payments made in respect
of production months as opposed to the month paid.
(3) Net earnings includes gains from the sale of properties and investments
and recognition of investment tax credits before tax effect as follows:
(2009 - $51,868,000).


2010 Financial Highlights

- Financial results were positively impacted by increased production levels and improved commodity prices. Overall, Bonterra generated cash flow from operations of $66.3 million and net earnings of $49.9 million or $3.52 and $2.65 on a per share basis (basic), respectively;

- The Company's average realized price for crude oil and natural gas liquids increased 21.5 percent year over year to $72.69 per barrel. Natural gas prices remained depressed and the Company's average realized price was $4.14 per MCF;

- The improved crude oil pricing environment is positive for the Company as Bonterra's production is composed predominantly of light oil. The Company's production was 69 percent crude oil and liquids;

- Bonterra paid cash dividends to shareholders of $2.55 per share, a substantial increase of 50 percent from the 2009 level of $1.70 per share. Bonterra had increased its dividend twice in 2010 and subsequent to year-end due to volume increases in Q4 2010, Bonterra was able to once again increase the monthly dividend to its current level of $0.24 per share which began with the dividend paid out in January 2011;

- The payout ratio was 60 percent of funds flow and within the Company's 2010 annual target of 60 to 75 percent); and

- Bonterra ended 2010 with a total of debt and working capital to cash flow ratio of 1.18 times (based on a total of debt and working capital of $100.0 million and annualized 2010 fourth quarter funds flow of $84.4 million). As a result of its strong financial position, Bonterra is well funded to execute the 2011 capital program and to pursue additional opportunities that may become available.

2010 Operational Highlights

- Bonterra drilled 22 gross operated Cardium horizontal, multi-stage fractured wells with a 100 percent success rate in the Halo area;

- During the year, the Company participated in 5 gross (0.75 net) successful non-operated Cardium horizontal, multi-stage fractured wells in the main Pembina Cardium pool;

- The Company's average daily production increased by 13 percent to 5,628 BOE per day and production per share increased by 8 percent to 0.109 BOE per share;

- Bonterra's Total Proved plus Probable reserves increased by 10 percent to 39.4 million BOE and Total Proved plus Probable reserves per share increased by 5 percent to 2.09 BOE per share;

- Total Proved reserves increased by 13 percent to 28.6 million BOE;

- Proved plus Probable reserve adds 2.7 times 2010 production;

- Bonterra's Proved plus Probable reserve life index of 17.8 years is one of the highest among conventional producers in the Canadian energy sector.

2011 Guidance

- Bonterra plans to invest between $50 to $60 million on its capital development program. The Company plans to drill a minimum of 20 gross horizontal Cardium wells mainly in the halo area of the Pembina and Willesden Green fields with the remainder in the main pool of the Pembina field;

- Maintain a steady pace of development targeting 10 to 15 percent growth in production. Production for 2011 is estimated to average between 6,200 to 6,500 BOE per day;

- Bonterra plans to pay dividends in 2011 that will target a payout ratio in the range of 55 to 70 percent of funds flow.

- Implement further cost reduction initiatives on the horizontal drill program including new drilling and completion methods to not only decrease costs but also improve well performance and reserve recovery; and

- Review operational practices and apply improvements throughout the Company's operations to reduce operating costs to the $12.50 to $13.50 per BOE range.

A Discussion of Financial and Operational Results

This press release is a review of the operations, current financial position, and outlook for Bonterra Energy Corp. ("Bonterra" or the "Company") and should be read in conjunction with the Management's Discussion and Analysis (MD&A) and the audited financial statements for the year ended December 31, 2010, together with the notes related thereto.

Non-GAAP Measures

Throughout this press release we use the terms "payout ratio" and "cash netback" to analyze operating performance. We calculate payout ratio by dividing cash dividends to shareholders by cash flow from operating activities both of which are measures prescribed by GAAP which appear on our consolidated statements of cash flows. We calculate cash netback by dividing various operation and deficit statement items as determined by GAAP by total production on a barrel of oil equivalent basis.

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, statements 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; dividends; 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 companies 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. The foregoing factors are not exhaustive and are further discussed herein under the heading Business Prospects, Risks and Outlooks as well as in the Company's Annual Information Form filed on SEDAR at www.sedar.com.

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 so, what benefits will be derived therefrom. Except as required by law, the Company 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.



Production
Three Months Ended Twelve Months Ended
December September December December December
31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
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Crude oil and NGLs
(barrels per day) 4,378 3,890 3,182 3,875 3,141
Natural gas (MCF per day) 10,214 10,674 10,193 10,521 11,120
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Average BOE per day 6,080 5,669 4,881 5,628 4,994
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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.

Bonterra's 2010 average production increased 12.7 percent on a per BOE per day basis over 2009 which includes the production from the February 2010 sale of the Pinto property of approximately 60 BOE per day and the November 2009 sale of the Shaunavon property of approximately 200 BOE per day. Crude oil production increased by 23.4 percent while gas production decreased by 5.4 percent. The natural gas decrease was due primarily to the shut in of a portion of the Company's Pembina natural gas production. In June 2010, a non-operated natural gas plant, to which Bonterra delivers a portion of its natural gas, reached capacity and resulted in the shut in of a number of the Company's natural gas wells. The average amount of shut in natural gas during Q3 was approximately 660 MCF per day (110 BOE per day).

Effective October 1, 2010, the Company was notified of additional shut in requirements due to other owners in the plant increasing their throughput. Although Bonterra is an owner in the facility, the Company had been delivering natural gas volumes well in excess of its ownership percentage. The amount of natural gas shut in effective October 1, 2010 was approximately 1,100 MCF per day (183 BOE per day) net to the Company. The Company is currently reviewing alternatives, while considering the current low natural gas prices, to either redirect this natural gas production or participate with the other owners in the plant in the expansion of the facility. A short-term solution has been presented by one of the other owners where they would redirect a portion of their natural gas to an alternative natural gas processing facility. Once this is complete, anticipated by the end of Q1 2011, Bonterra would be able to reactivate all of its currently shut in production, but due to low natural gas prices may elect to keep these wells shut in for the present time.

The Company drilled 22 gross (20.0 net) operated Pembina Cardium horizontal oil wells (five gross and net in Q4 2010) and one gross and net Pembina Cardium vertical oil well during 2010. The Company also participated in the drilling of five gross (0.75 net) (two gross and 0.3 net in Q4 2010) non-operated Pembina Cardium horizontal oil wells and two gross (0.3 net) non-operated Pembina Cardium vertical oil wells during 2010. Bonterra's working interest in the non-operated wells is approximately 15 percent. Bonterra had a 100 percent success rate in 2010.

As of December 31, 2010 the Company had four gross (3.75 net) operated horizontal wells drilled but not on production. One of the remaining operated horizontal oil wells (one net) was placed on production January 2, 2011. The remaining three (2.75 net) horizontal wells were on production in February, 2011.

The Company's fourth quarter 2010 production saw increases in crude oil of 488 barrels per day and a decline in natural gas of 460 MCF per day production compared to Q3 2010. During the fourth quarter, the Company was able to place on production two 100 percent gross and net horizontal wells in October, four gross (3.43 net) horizontal wells in November and one gross and net horizontal well in late December, 2010. Offsetting the increase in solution gas from these wells was the additional shut in of approximately 600 MCF per day of natural gas production due to the above mentioned gas plant capacity restrictions.

Bonterra expects 2011 production to average between 6,200 and 6,500 BOE per day.



Revenue
Three Months Ended Twelve Months Ended
December September December December December
31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
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Revenue - oil and
gas sales ($ 000s) 34,209 28,332 24,946 118,980 85,712
Average Realized Prices:
Crude oil and NGLs
($ per barrel) 75.91 68.79 68.40 72.69 59.82
Natural gas ($ per MCF) 3.78 3.74 4.76 4.14 4.15
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Revenue from petroleum and natural gas sales increased 38.8 percent in 2010 compared to 2009. The increase was primarily due to a 23.4 percent increase in crude oil production as well as a 21.5 percent increase in crude oil prices. During 2010 the Company did not enter into any risk management contracts.

Quarter over quarter the Company saw an increase in revenues of $5,877,000, a 20.7 percent increase, due primarily to increased crude oil production as well as increased crude oil pricing.



Royalties
Three Months Ended Twelve Months Ended
December September December December December
($ 000s except $ per BOE) 31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
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Crown royalties 2,092 1,907 1,451 7,562 4,737
Freehold royalties,
gross overriding royalties
and net carried interests 757 1,041 892 3,875 2,677
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Total royalty expense 2,849 2,948 2,343 11,437 7,414
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Percentage of revenue 8.3 10.4 9.4 9.6 8.6
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$ per BOE 5.09 5.65 5.22 5.57 4.07
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Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta, Saskatchewan and British Columbia. The Company's average Crown royalty rate was approximately 6.4 percent (2009 - 5.5 percent) and approximately 3.3 percent (2009 - 3.1 percent) for other royalties.

The fourth quarter royalties decreased $99,000 over the third quarter. During the fourth quarter the Company reviewed several of its other royalty agreements and discovered some overpayments. The adjustment recorded in Q4 2010 amounted to approximately $160,000 of overpayments in previous periods. In addition, production subject to the freehold royalty rate of 17 percent has been declining while production from the Company's new crown horizontal wells, which have a five percent royalty rate, has increased resulting in an overall lower royalty expense.

ALBERTA GOVERNMENT COMPETITIVENESS REVIEW

On March 11, 2010, the Government of Alberta announced it will modify conventional oil and natural gas royalties effective January 2011 to increase Alberta's competitiveness in the upstream energy sector. The current five percent front-end royalty rate on conventional oil and natural gas will become a permanent feature of the royalty system. The maximum royalty rate for conventional oil will be reduced to 40 percent from 50 percent. The maximum royalty rate for conventional and unconventional natural gas will be reduced at higher prices from 50 to 36 percent. Other royalty incentive programs will remain in effect. Management believes these changes to the royalty system should have a positive effect on the Company's future cash flow.



Other Revenue

Three Months Ended Twelve Months Ended
December September December December December
($ 000s) 31, 2010 30, 2010 30, 2009 31, 2010 31, 2009
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Investment tax credit
recovery - - 27,670 - 27,670
Gain on sale of property - 700 24,198 6,485 24,198
Gain on sale of investments 782 3,536 - 4,335 -
Interest and other 10 2 95 36 158
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Total other revenue 792 4,238 51,963 10,856 52,026
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As part of the Company's conversion from a trust to a corporation in 2008, Bonterra assumed approximately $27,670,000 of investment tax credits (ITC's) from SRX Post holdings Inc. Due to the depressed commodity prices as of December 31, 2008, the Company was not able to justify the ability to claim these ITC's prior to their expiration. The recovery in the price of crude oil as well as the Company's success in its horizontal crude oil development has resulted in significantly higher future anticipated cash flow from Bonterra's oil and gas operations and therefore justified that the ITC's are likely to be claimed in the future. The Company was able to do so in 2009.

On November 6, 2009, the Company closed the sale of a portion of its Shaunavon oil production to Eagle Rock Exploration Ltd. (Eagle Rock) (TSXV: ERX). The proceeds of disposition consisted of $23,729,000 cash and 30,769,200 common shares in Eagle Rock (representing approximately 4.2 percent of the outstanding common shares of that company at the time). The closing price of the Eagle Rock common shares on November 6, 2009 was $0.21 resulting in total consideration for the property of $30,191,000. The book value (net of asset retirement provision) of the property to the Company was approximately $5,993,000 resulting in a gain on sale of $24,198,000. Eagle Rock has since changed its name to Wild Stream Exploration Inc. (Wild Stream) (TSXV: WSX) and consolidated its common shares on a 30:1 basis.

In February 2010, the Company disposed of its Southeast Saskatchewan Pinto property. The proceeds of disposition were $5,534,000 cash. At the time of disposition, the Company had a net book value of $120,000 for the property and had an asset retirement obligation related to the property of $371,000 that was transferred resulting in a gain on sale of property of $5,785,000. In addition, during the third quarter of 2010 the Company disposed of non-producing land for proceeds of $700,000. The Company had no capital costs associated with this land.

Effective July 6, 2010, Comaplex Minerals Corp. (Comaplex) (a company with common directors and management with the Company) was acquired by Agnico-Eagle Mines Limited (Agnico-Eagle) (TSX: AEM). In exchange for Bonterra's 689,682 common shares in Comaplex, the Company received 689,682 shares in Geomark Exploration Ltd. (Geomark) (TSXV: GME) (a company with common directors and management with the Company) and 108,693 common shares in Agnico-Eagle. The value of the Agnico-Eagle shares is included with investments while the value of the Geomark shares is listed as investment in related party on the December 31, 2010 balance sheet.

During 2010, Bonterra disposed of a portion of its investments. Gross proceeds from the sales were $5,603,000 resulting in an accounting gain of $4,335,000. The Company holds in excess of $11,000,000 worth of investments as of December 31, 2010.



Production Costs
Three Months Ended Twelve Months Ended
December September December December December
($ 000s except $ per BOE) 31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
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Production costs 8,699 8,069 6,870 30,451 27,848
$ per BOE 15.55 15.47 15.30 14.82 15.28
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Total production costs in 2010 have increased by $2,603,000 over 2009. The increase is substantially due to approximately $2.5 million in 2007, 2008 and 2009 natural gas processing fee adjustments billed to Bonterra during 2010 by the operator of several of the natural gas plants that the Company uses to process its natural gas. On a per BOE basis, production costs have declined in 2010 compared to 2009 by $0.46, and excluding the natural gas processing fee adjustments, by $1.66 mainly due to higher rate horizontal wells, field optimization and cost control procedures implemented by Bonterra.

Total operating costs increased in the fourth quarter of 2010 compared to the prior quarter due primarily to the billing of 2009 natural gas processing charge adjustments of approximately $800,000 (see above discussion).



General and Administrative Expense
Three Months Ended Twelve Months Ended
December September December December December
($ 000s except $ per BOE) 31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
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G&A Expense 1,468 1,204 1,623 5,406 4,458
$ per BOE 2.62 2.31 3.61 2.63 2.45
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General and administrative (G&A) expenses increased 21.3 percent in 2010 compared to 2009. The Company provides administrative services to Geomark and Pine Cliff Energy Ltd. (Pine Cliff) (TSXV: PNE), companies that share common directors and management. Please refer to discussion under Related Party Transactions for details.

The Company's significant general and administrative costs include employee compensation; professional services such as legal, engineering and accounting; computer services, bank charges and occupancy costs. Employee compensation expense increased by approximately 21 percent ($742,000) in 2010 from 2009 due to a larger bonus accrual and an increase in staff. The Company's bonus plan consists of cash payments equal to three percent of before tax net earnings (excluding the 2009 investment tax credit recovery of $27,670,000) to be paid to employees and key consultants. Bonus payments to individuals are based on performance. Costs associated with professional services were relatively unchanged year over year. Costs associated with computer services (decrease of $72,000) and bank charges (decrease of $43,000) were offset by increased occupancy cost of $138,000.

The quarter over quarter increase of $264,000 was primarily due to increased employee and consultant compensation.

During the year the Company capitalized $Nil (2009 - $460,000) of general and administrative costs.



Interest Expense
Three Months Ended Twelve Months Ended
December September December December December
($ 000s except $ per BOE) 31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
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Interest on long-term debt 654 562 620 2,244 2,833
Other interest 192 140 118 555 461
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Interest Expense 846 702 738 2,799 3,294
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$ per BOE 1.51 1.35 1.64 1.35 1.81
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Bank debt at December 31, 2010 was $70,386,000 (December 31, 2009 - $59,823,000). The Company's banking arrangements allow it to use Bankers Acceptances (BA's) as part of its loan facility. Interest charges on BA's are generally one half percent lower than that charged on the general loan account.

The Company has also borrowed $32,000,000 (December 31, 2009 - $23,500,000) from two related parties as well as $15,000,000 (December 31, 2009 - Nil) from a private investor. Please see Related Party Transactions and Liquidity and Capital Resources sections for further details.

Interest charges decreased in 2010 as decreased interest rates more than overset the increase in average outstanding debt balance. The interest rate decrease is due to a reduced bank rate resulting from a better debt to cash flow ratio and to increases in loans from related parties and private investments which have a lower interest rate than bank loans.

Quarter over quarter saw an increase in interest charges due to increased debt balances resulting from the Company's fourth quarter capital program.

Effective April 9, 2010, the Company renewed its bank facility under similar terms and conditions with the exception of extending the revolving period to April 27, 2012, reducing its interest and bank fees and amending one of the material covenants (see below).

The interest rate on the credit facility is calculated as follows:



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Level I Level II Level III Level IV Level V
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Consolidated Total
Funded Debt (1) to Over Over Over
Consolidated Cash flow Under 1.0:1 1.5:1 2.0:1 Over
Ratio 1.0:1 to 1.5:1 to 2.0:1 to 2.5:1 2.5:1
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Canadian Prime Rate Plus (2) 100 150 175 200 250
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Bankers' Acceptances
Rate Plus (2) 225 275 300 325 375
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(1) Consolidated total funded debt excludes related party amounts and
subordinated debenture but includes working capital. Consolidated cash
flow is calculated as cash flow according to GAAP excluding adjustments
for non-cash working capital items. (`(2) Numbers in table represent
basis points.
(2) Numbers in table represent basis points.


Consolidated total funded debt to consolidated cash flow ratio shall be calculated each fiscal quarter and the interest rates adjusted effective as of the first day of the fiscal quarter commencing immediately after the fiscal quarter in which Bonterra files a compliance certificate containing the ratio, with each such adjustment to be effective until the next such adjustment.

As of December 31, 2010 the Company will continue to qualify for the Level I interest rates.

The following is a list of the material covenants of the Company's bank facility:

- The Company is required to not exceed $120,000,000 in consolidated debt (includes negative working capital but excludes debt to related parties and the subordinated promissory note). As of December 31, 2010 the Company had consolidated total funded debt of $52,995,000.

- Total dividends paid in the current quarter and the three previous quarters shall not exceed 80 percent of the previous four quarters' cash flow as defined under GAAP. Dividend payments totalled $46,867,000 during the quarter and the three previous quarters while cash flow totalled $68,782,000 during the same period for an overall payout ratio of 68 percent.

Stock-Based Compensation

Stock-based compensation is a statistically calculated value representing the estimated expense of issuing employee stock options. The Company records a compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. The Company issued only 36,000 stock options during 2010 resulting in a reduction of stock-based compensation by $428,000. As of December 31, 2010, the Company has a total of $290,000 of stock-based compensation to amortize over the next two years.

The 36,000 common share options were issued with a weighted average exercise price of $36.98 per share and a fair value of $5.67 per option. The fair value of the options granted has been estimated using the Black-Scholes option pricing model, assuming a weighted risk free interest rate of 1.9 percent (2009 - 1.4 percent), expected weighted average volatility of 33 percent (2009 - 33 percent), expected weighted average life of 2.8 years (2009 - 3.0 years) and an annual dividend rate based on the dividends paid to the shareholders during the year.

Depletion, Depreciation, Accretion and Dry Hole Costs

The Company follows the successful efforts method of accounting for petroleum and natural gas exploration and development costs. Under this method, the costs associated with dry holes are charged to operations. For intangible capital costs that result in the addition of reserves, the Company depletes its oil and natural gas intangible assets using the unit-of-production basis by field.

For tangible assets such as well equipment, the Company now uses a 10 percent declining basis for depreciation calculation. The Company changed from the straight line basis due to the increasing reserve life index which continues to indicate a longer service life for its production assets.

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

At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $62,579,000 (2009 - $64,482,000). The $1,903,000 decrease is due primarily to a reduction in anticipated inflation from two percent to one and a half percent.

These obligations will be settled based on the useful lives of the underlying assets, which extend up to 50 years into the future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent. The discount rate is reviewed annually and adjusted if considered necessary. A change in the rate would have a significant impact on the amount recorded for asset retirement obligations. Based on the current provision, a one percent increase in the risk adjusted rate would decrease the asset retirement obligation by $2,827,000, while a one percent decrease in the risk adjusted rate would increase the asset retirement obligation by $3,875,000.

The above calculation requires an estimation of the amount of the Company's petroleum reserves by field. This figure is calculated annually by an independent engineering firm and is used to calculate depletion. This calculation is to a large extent subjective. Reserve adjustments are affected by economic assumptions as well as estimates of petroleum products in place and methods of recovering those reserves. To the extent reserves are increased or decreased, depletion costs will vary.

For the fiscal year ending December 31, 2010, the Company expensed $22,278,000 (2009 - $19,277,000) for the above-described items. The increase is predominately due to increased production volumes resulting from the Company's Pembina Cardium horizontal oil well drill program. The higher BOE depletion charges on the horizontal wells are primarily due to lack of production history on these wells resulting in lower proved reserves being assigned but with substantial probable reserves being assigned. The Company's policy is to deplete the cost of the wells based on proved reserves. When there is longer production history on the horizontal wells there may be a conversion of the probable reserves to proven reserves which would result in a reduction of depletion charges per BOE in future years.

The Company continues to have relatively low finding and development costs. Based on year end reserves, the Company's average cost of proved reserves is $7.80 (2009 - $6.62) per BOE.

The Company currently has an estimated reserve life for its proved developed producing reserves of 10.1 (2009 - 11.7) years calculated using the Company's gross reserves (prior to allowance for royalties) based on the third party engineering report dated December 31, 2010 and using fourth quarter 2010 average production rates of 6,080 BOE per day (2009 - 4,879 BOE per day). Based on total proved reserves the Company has a 12.9 (2009 - 14.2) year reserve life and on a proved and probable basis the reserve life increases to 17.8 (2009 - 20.1) years. These figures are some of the longest reserve life indexes (excluding oil sands) in the Canadian oil and gas industry.

Taxes

The current tax provision relates to a resource surcharge of $141,000 (2009 - $282,000) payable to the Province of Saskatchewan. The resource surcharge is calculated as a flat percent of revenues generated from the sale of petroleum products produced in Saskatchewan. The resource surcharge rate is three percent in 2010. In 2009, a capital tax amount of $269,000 payable to the Province of Quebec was incurred due to the 2008 reorganization for the conversion from a Trust to a Corporation. The capital tax payable to the Province of Quebec was a one-time charge.

The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization:



($ 000s) Rate of Utilization (%) Amount
----------------------------------------------------------------------------
Undepreciated capital costs 20-100 $ 25,441
Eligible capital expenditures 7 6,849
Share issue costs 20 1,424
Canadian oil and gas property expenditures 10 19,074
Canadian development expenditures 30 109,642
Canadian exploration expenditures 100 11,140
SR&ED expenditures 100 39,985
Income tax losses carried forward (1) 100 222,596
----------------------------------------------------------------------------
$ 436,151
----------------------------------------------------------------------------

(1) Income tax losses carried forward expire in the following years;
2024 - $3,347,000, 2025 - $7,532,000, 2026 - $46,671,000, 2027 -
$117,189,000, 2028 - $34,726,000, 2029 - $13,131,000.


In addition to the above pools, the Company also has $27,670,000 (December 31, 2009 - $27,670,000) remaining of investment tax credits that expire in the following years; 2019 - $3,469,000, 2020 - $3,059,000, 2021 - $4,667,000, 2022 - $3,909,000, 2023 - $3,155,000, 2024 - $1,995,000, 2025 - $2,257,000, 2026 - $2,405,000, 2027 - $2,009,000, 2028 - $745,000.

The Company also has $141,417,000 (December 31, 2009 - $143,061,000) of capital loss carry forwards which can only be claimed against taxable capital gains.

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



Net Earnings
Three Months Ended Twelve Months Ended
December September December December December
($ 000s except $ per share)31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
----------------------------------------------------------------------------
Net Earnings 14,213 12,724 52,136 49,864 68,563
----------------------------------------------------------------------------
$ per share - Basic 0.75 0.68 2.88 2.65 3.81
----------------------------------------------------------------------------
$ per share - Fully Diluted 0.73 0.66 2.85 2.58 3.78
----------------------------------------------------------------------------



Bonterra's net earnings for the year ended December 31, 2010 represents a 27.3 percent decrease over the Company's 2009 net earnings. Two significant factors contributing to the 2009 net earnings were the Company's recordings of the investment tax credit recovery of $27,670,000 and the sale of a portion of the Company's Shaunavon production for a gain of $24,198,000; all of which occurred in the fourth quarter of 2009. Excluding these items (net of 29.15 percent tax effect), 2009 net earnings would decrease by $36,748,000 from $68,563,000 to an adjusted net earnings of $31,815,000. In 2010, a gain on sale of property of $4,665,000 (net of 28.06 percent tax effect) was incurred. Excluding these items, Bonterra's 2010 net earnings increased by $13,384,000, or 42 percent, over 2009.

Higher revenues resulting from increased production and increased commodity prices were the main reason for the significant net earnings increase. The Company continues to return in excess of 40 percent of its gross crude oil and natural gas revenues in net earnings. The Company's low capital costs per BOE of reserves combined with the Company's low production decline rates should allow for continued positive earnings.

Other Comprehensive Income

Other comprehensive income for 2010 consists of an unrealized gain before tax on investments (including investments in a related party) of $8,602,000 (2009 - $697,000) including a fourth quarter unrealized gain before tax of $2,642,000 relating to an increase in the investment's fair value. The Company also sold some of these investments, which comprise of marketable securities, for a realized gain before tax of $4,335,000 (2009 - $Nil) including a fourth quarter realized gain before tax of $782,000. Realized gains decrease other comprehensive income, as the gains are transferred to net earnings. Other comprehensive income varies from net earnings by unrealized changes in the fair value of Bonterra's holdings of investments including the investment in Geomark, net of tax.



Cash Flow from Operations
Three Months Ended Twelve Months Ended
December September December December December
($ 000s except $ per share)31, 2010 30, 2010 31, 2009 31, 2010 31, 2009
----------------------------------------------------------------------------
Cash flow from operations 16,987 17,558 13,673 66,262 38,893
----------------------------------------------------------------------------
$ per share - basic 0.89 0.93 0.76 3.52 2.16
----------------------------------------------------------------------------
$ per share - fully diluted 0.86 0.91 0.75 3.42 2.15
----------------------------------------------------------------------------



Cash flow from operations increased 70 percent year over year, mainly due to increased production and crude oil prices. Fourth quarter cash flow decreased by $571,000 over Q3 due to adjustments of $3,335,000 relating to changes in non-cash working capital items. The Company has not entered into any risk management agreements and as such is fully exposed to changes in commodity prices and exchange rates.

Cash Netbacks

The following table illustrates the Company's annual cash netback:



($ per BOE) 2010 2009
----------------------------------------------------------------------------
Production volumes (BOE) 2,054,375 1,822,628
----------------------------------------------------------------------------
Gross production revenue $ 57.92 $ 47.04
Royalties (5.57) (4.07)
Production costs (14.82) (15.28)
----------------------------------------------------------------------------
Field netback 37.53 27.69
General and administrative (2.63) (2.45)
Interest and taxes (1.43) (2.11)
----------------------------------------------------------------------------
Cash netback $ 33.47 $ 23.13
----------------------------------------------------------------------------

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

($ per BOE) December 31, 2010 September 30, 2010
----------------------------------------------------------------------------
Production volumes (BOE) 559,400 521,601
----------------------------------------------------------------------------
Gross production revenue $ 61.15 $ 54.32
Royalties (5.09) (5.65)
Production costs (15.55) (15.47)
----------------------------------------------------------------------------
Field netback 40.51 33.20
General and administrative (2.62) (2.31)
Interest and taxes (1.58) (1.39)
----------------------------------------------------------------------------
Cash netback $ 36.31 $ 29.50
----------------------------------------------------------------------------



Related Party Transactions

As a result of the acquisition of Comaplex by Agnico-Eagle, the loan agreement and Bonterra common shares previously held by Comaplex were transferred to Geomark. A new management agreement was entered into between Bonterra and Geomark with the only amendment to the former agreement with Comaplex being a reduction in the monthly management fee from $30,000 to $22,500.

Geomark and Comaplex combined paid a management fee to the Company of $316,500 (2009 - $330,000). Geomark also shares office rental costs and reimburses the Company for costs related to employee benefits and office materials. In addition, Geomark owns 204,633 (Comaplex December 31, 2009 - 204,633) common shares in the Company. Services provided by the Company included executive services (chief executive officer, president and vice president, finance duties), accounting services, oil and gas administration and office administration. All services performed were charged at estimated fair value. At December 31, 2010, Geomark owed the Company $35,000 (Comaplex December 31, 2009 - $105,000).

As of December 31, 2010, Geomark has loaned the Company $20,000,000 (Comaplex December 31, 2009 - $12,000,000). The loan is unsecured, bears interest at Canadian chartered bank prime less 5/8th of a percent and has no set repayment terms. The loan cannot be repaid, or demanded to be paid by Geomark, unless the Company has sufficient available borrowing limits under the Company's credit facility. Interest paid on both the Comaplex and Geomark loans during 2010 was $313,000 (2009 - $194,000). This loan results in being a substantial benefit to Bonterra and to Geomark. The interest paid to Geomark by Bonterra is substantially lower than bank interest and for Geomark, the interest earned is substantially higher than Geomark would receive by investing in bank instruments such as BA's or GIC's.

The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors and management with the Company. Pine Cliff paid a management fee to the Company of $90,000 (2009 - $120,000). Services provided by the Company include executive services (CEO, president and vice president, finance duties), accounting services, oil and gas administration and office administration. All services performed are charged at estimated fair value. The Company has no share ownership in Pine Cliff. At December 31, 2010, the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2009 - $1,000).

As of December 31, 2010, the Company's CEO and major shareholder has loaned the Company $12,000,000 (December 31, 2009 - $11,500,000). The loan is unsecured, bears interest at Canadian chartered bank prime less 5/8th of a percent and has no set repayment terms. The loan cannot be repaid, or demanded to be paid by the Company's CEO, unless the Company has sufficient available borrowing limits under the Company's credit facility. Interest paid on this loan during 2010 was $242,000 (2009 - $209,000). This loan results in being a substantial benefit to Bonterra and to the CEO. The interest paid to the CEO by Bonterra is substantially lower than bank interest and for the CEO, the interest earned is substantially higher than the CEO would receive by investing in bank instruments such as BA's or GIC's.

Liquidity and Capital Resources

During 2010, the Company incurred capital costs of $76,914,000 (2009 - $28,726,000) net of drilling tax credits. The costs relate primarily to the drilling, completing, tie-in and equipping of 22 gross (20.0 net) operated Pembina Cardium horizontal wells as well as its proportion of the non-operated drilling costs. During the fourth quarter of 2010, Bonterra elected to drill two additional operated horizontal oil wells and the operator of non-operated property also added two additional (0.3 net to Bonterra) horizontal oil wells to its drilling program.

The Company currently has plans to spend approximately $50,000,000 to $60,000,000 on its 2011 Pembina Cardium horizontal well program and non-operated capital programs. Bonterra anticipates funding the 2011 capital program out of cash flow, proceeds from the exercise of employee stock options, sale of investments and the Company's line of credit.

As of December 31, 2010 and December 31, 2009, the Company has a bank facility consisting of a $100,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated revolving credit facility. Amounts drawn under these facilities at December 31, 2010 were $70,386,000 (December 31, 2009 - $59,823,000). The interest rates on the outstanding debt as of December 31, 2010 were 4.0 percent and 3.4 percent on the Company's Canadian prime rate loan and Bankers' Acceptances, respectively. For information related to interest rate levels and material covenants please refer to the discussion under Interest Expense.

On October 4, 2010, the Company borrowed $15,000,000 from a private investor. In exchange Bonterra has issued a Subordinated Promissory Note for $15,000,000. The terms of the Subordinated Promissory Note are that it bears interest at three percent, is not callable by the investor prior to January 4, 2012 at which time it will be a demand note until its maturity of April 4, 2012, and can be repaid at the option of the Company at any time. Security consists of a floating demand debenture totaling $15,000,000 over all of the Company's assets and is subordinated to any and all claims in favor of the syndicate of senior lenders providing credit facilities to the Company.

Financial Reporting Update

INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS)

In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to apply IFRS, in full and without modification, for all financial periods beginning January 1, 2011. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by Bonterra for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.

The Company commenced the process to transition its financial statements from current Canadian GAAP to IFRS in 2008. The Company's project consists of three key phases: the scoping and diagnostic phase, the impact analysis and evaluation phase and the implementation phase.

- Scoping and diagnostic phase - this phase involves performing a high level impact analysis to identify areas that may be affected by the transition to IFRS. The results of this analysis were given a priority ranking according to their complexity and the amount of time required to assess the impact of changes in transitioning to IFRS. The Company identified the following high impact and medium impact areas:

High impact areas:

- IFRS 1 - First time adoption of IFRS

- IFRS 3 - Business combinations

- IAS 16 - Property and equipment

- IAS 36 - Impairment of assets

Medium impact areas include:

- IFRS 6 - Exploration and evaluation of mineral resources

- IFRS 2 - Share-based payments

- IAS 1 - Presentation of financial statements

- IAS 10 - Events after the balance sheet date

- IAS 12 - Income Taxes

- IAS 18 - Revenues

- IAS 23 - Borrowing costs

- IAS 39 - Financial instruments, recognition and measurement

- IAS 37 - Provisions, contingent liabilities and contingent assets

- Impact analysis and evaluation phase - during this phase, items identified in the diagnostic were addressed according to the priority ranking assigned to them. The Company conducted analysis of policy choices allowed under IFRS and their impact to the financial statements. Additionally, certain potential differences were further investigated to assess if there was any broader impact to the Company's net earnings, debt agreements, compensation arrangements or management reporting systems. The impact analysis and evaluation phase was concluded by management pending the Audit Committee of the Board of Directors approval on all accounting policies chosen by management. Since Bonterra uses successful efforts method of accounting on its petroleum and natural gas properties under Canadian GAAP, the audit committee of the Board of Directors gave management the directive to chose policies that will retain as much comparability to the accounting policies chosen under Canadian GAAP.

- Implementation phase - involved implementation of all changes approved in the impact analysis and evaluation phase, which included minor changes to existing information systems, the creation of new business processes and the modification of training staff impacted by the conversion.

Since its inception, the project has been led by the financial reporting group with sponsorship from the executive team. The Company has effectively completed all phases of its IFRS transition project and continues to review its draft IFRS financial statements and disclosures for completeness and quality assurance. The Audit Committee will review and approve the Company's IFRS accounting policy selections and adjustments prior to the release of the first quarter of 2011 financial statements and MD&A.

First Time Adoption of IFRS

Most adjustments required on transition to IFRS will be made retrospectively against opening retained earnings as of the date of the first comparative balance sheet presented, based on standards applicable at that time. IFRS 1 provides entities adopting IFRS for the first time with certain optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS. Management has analyzed the various accounting policy choices available under IFRS 1 and has implemented those determined to be the most appropriate for Bonterra. Accordingly, it has applied the following IFRS 1 exemptions in its IFRS opening balance sheet:

- Business combinations (IFRS 1) - provides the option to apply IFRS 3, Business Combinations, retrospectively or prospectively from the Transition Date. The retrospective basis would require restatement of all business combinations that occurred prior to the Transition Date. The Company elected not to retrospectively apply IFRS 3 to business combinations that occurred prior to its Transition Date and such business combinations have not been restated. Any goodwill arising on such business combinations before the Transition Date has not been adjusted from the carrying value previously determined under Canadian GAAP as a result of applying these exemptions.

- Share-based payments (IFRS 2) - encourages the application of its provisions to equity instruments granted on or before November 7, 2002, but permits the application only to equity instruments granted after November 7, 2002 that had not vested by the Transition Date. The Company elected to avail itself of the exemption provided under IFRS 1 and applied IFRS 2 for all equity instruments granted after November 7, 2002 that had not vested by its Transition Date. Further, the Company applied IFRS 2 for all liabilities arising from share-based payment transactions that existed at its Transition Date. This election has no material effect on the Company.

- Borrowing Costs (IAS 23) - requires an entity to capitalize the borrowing costs related to all qualifying assets for which the commencement date for capitalization is on or after January 1, 2010. Due to the short time frame to drill a well and place it on production this election has no material effect on the Company.

- Leases (IAS 17) - requires an entity to assess arrangements outstanding at the Transition Date. It also requires a determination of the appropriate lease classification in accordance with IAS 17, should an arrangement containing a lease be identified as part of the International Financial Reporting Interpretations Committee (IFRIC) 4, Determining Whether an Arrangement Contains a Lease, application. This election has no effect on the Company.

- Decommissioning Liabilities Included in the Cost of Property, Plant and Equipment (IAS 37) - Provisions, Contingent Assets and Contingent Liabilities requires an entity to estimate the statutory and constructive liabilities that existed at the Transition Date, discounted at the risk free rate. The Company has revalued its asset retirement obligation under GAAP to IFRS. The Company also determined it had no unrecorded statutory or constructive obligations.

The following is a listing of key areas where accounting policies differ and where accounting policy decisions are necessary that will significantly impact our reported financial position and results of operations:

- Deferred credit - On November 12, 2008, Bonterra Energy Income Trust (the "Trust") was acquired by Bonterra Oil & Gas Ltd. through a reverse takeover by the Trust of SRX Post Holdings Inc. (SRX). This transaction gave the Company additional tax pools in excess of the purchase price. Under Canadian GAAP this purchase was considered an acquisition of an asset and not a business combination and therefore resulting gain on acquisition had to be deferred and charged to net earnings on the same basis as the acquired assets. Under IFRS the deferred gain does not meet the definition of a liability and the deferred credit of $55,131,000 ($7,363,000 of the deferred credit being a current liability) is recorded as a decrease to deficit.

- Asset exchange revaluation - In 2007, the Company exchanged certain oil and gas assets in Alberta for oil and gas assets in Saskatchewan that were recorded at book value under Canadian GAAP. Under IFRS the values of the assets received are to be recorded at fair value, this resulted in $14,310,000 increase in the cost of the property and equipment and a $2,553,000 increase in the accumulated depletion and amortization of the property and equipment on the January 1, 2010 opening balance sheet. As a result of this change, the Company's deferred tax asset decreased by $3,446,000 million and the net offset is recorded as a decrease to deficit.

- Asset retirement obligation (ARO) - Under IFRS, the Company is required to revalue its entire liability for asset retirement costs at each balance sheet date using a current liability-specific discount rate, which can generally be interpreted to mean the current risk-free rate of interest. Under Canadian GAAP, obligations are discounted using a credit-adjusted risk-free rate and, once recorded, the asset retirement obligation is not adjusted for future changes in discount rates. At January 1, 2010 Bonterra's total of its asset retirement obligations will increase from $17,790,000 to $21,282,000 or $3,492,000, as the liability is revalued to reflect the estimated risk free rate of interest at that time of 4.1%. The offsetting ARO asset's cost will be adjusted by $3,540,000 due to the changes in the ARO liability. The ARO asset would also incur $1,804,000 more accumulated depletion. As a result of these changes, Bonterra's deferred tax asset is increased by $442,000 and the net offset is recorded as an increase to deficit.

- Future income tax asset (liability) - Under Canadian GAAP, Bonterra separates future income tax assets (liabilities) between current, which as of January 1, 2010 was a $11,889,000 asset and long-term, which as of January 1, 2010 was $58,265,000. Under IFRS, future income tax asset (liability) (which will be renamed "deferred tax") will all be classified as long-term.

- Impairment of property and equipment (P&E) assets - Canadian GAAP generally uses a two-step approach to impairment testing; first comparing asset carrying values with undiscounted future cash flows to determine whether an impairment exists, and then measuring impairment by comparing asset carrying values to their fair value (which is calculated using discounted cash flows). IFRS uses a one-step approach for testing and measuring impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use down to a cash generating unit (CGU) level. A cash generating unit is the smallest group of assets that generates cash flows largely independent of other assets or group of assets. The impairment test categories of CGUs under IFRS is materially similar to the impairment groupings already chosen under Canadian GAAP, since the Company is using the successful efforts method of accounting for its P&E assets. The discount rate however, to determine fair value could materially differ under IFRS versus Canadian GAAP. As of January 1, 2010 and December 31, 2010, the Company does not anticipate an impairment of P&E assets under IFRS.

The table below summarizes the Company's January 1, 2010 balance sheet under Canadian GAAP and the transitional entries required to present the opening balance sheet under IFRS. Bonterra has not yet prepared a full set of annual financial statements under IFRS, therefore, amounts disclosed are unaudited.



----------------------------------------------------------------------------
($ 000s) Canadian GAAP IFRS Adjustments IFRS
----------------------------------------------------------------------------
Current assets 39,569 (11,889) 27,680
Long-term assets 254,418 21,919 276,337
----------------------------------------------------------------------------
Total assets 293,987 10,030 304,017
----------------------------------------------------------------------------
Current liabilities 49,731 (7,363) 42,368
Long-term liabilities 125,382 (44,277) 81,105
Equity 118,874 61,670 180,544
----------------------------------------------------------------------------
Total liabilities and equity 293,987 10,030 304,017
----------------------------------------------------------------------------


In addition to accounting policy differences, the Company's transition to IFRS is expected to impact its internal control over financial reporting, disclosure controls and procedures, certain of Bonterra's business activities and IT systems as follows:

- Internal control over financial reporting (ICFR) - Bonterra is currently in the process of reviewing its ICFR documentation and is identifying instances where controls must be amended or added in order to address the accounting policy changes required under IFRS. No material changes in control procedures are expected as a result of transition to IFRS.

- Disclosure controls and procedures - Bonterra has assessed the impact of transition to IFRS on its disclosure controls and procedures and has not identified any material changes required in its control environment. It is expected that there will be increased note disclosure around certain financial statement items than what is currently required under Canadian GAAP. Management is currently drafting its IFRS note disclosure in accordance with current IFRS standards and continues to monitor requirements put forth by the International Accounting Standards Board (IASB) in discussion papers and exposure drafts for future disclosure requirements. Throughout the transition process, Bonterra has carefully considered its stakeholders' information requirements and will continue to ensure that adequate and timely information is provided to meet these needs.

- Business activities - Management has been cognizant of the upcoming transition to IFRS, and as such, has worked with its counterparties and lenders to ensure that any agreements that contain references to Canadian GAAP financial statements are modified to allow for IFRS statements. Based on the changes to the Company's accounting policies, no issues are expected to arise with the existing wording of debt covenants and related agreements as a result of the conversion to IFRS.

- IT systems - Bonterra has completed the accounting system updates required in order to prepare for IFRS reporting. Since the Company has been using successful efforts method to account for its petroleum and natural gas assets, no significant modifications were deemed critical in order to allow for reporting of both Canadian GAAP and IFRS statements in 2010.

Sensitivity Analysis

Sensitivity analysis, as estimated for 2011:



Cash Flow Cash Flow Per Share(1)
----------------------------------------------------------------------------
U.S. $1.00 per barrel $ 1,376,000 $ 0.072
Canadian $0.10 per MCF $ 349,000 $ 0.018
Change of Canadian $0.01/U.S.
$ exchange rate $ 1,161,000 $ 0.060
----------------------------------------------------------------------------
(1) Based on year end outstanding common shares of 19,219,541


Additional Information

Additional information relating to the Company may be found on www.sedar.com as well as on the Company's website at www.bonterraenergy.com.

The following consolidated financial statements and notes to the consolidated financial statements have been provided for further details.



Bonterra Energy Corp.
Consolidated Balance Sheets

As at December 31
($ 000s) 2010 2009
----------------------------------------------------------------------------
Assets
Current
Accounts receivable (Note 14) 17,345 14,713
Crude oil inventory 487 431
Prepaid expenses 1,631 3,247
Future income tax asset (Note 10) 22,889 11,889
Investments (Note 5 and 6) 11,471 4,462
Investment in related party (Note 5) - 4,827
----------------------------------------------------------------------------
53,823 39,569
----------------------------------------------------------------------------
Investment in related party (Note 5) 814 -
Restricted cash - 812
Investment tax credit receivable (Note 10) 27,670 27,670
Future income tax asset (Note 10) 30,011 58,265
Property and Equipment (Note 6)
Petroleum and natural gas properties and related
equipment 332,141 255,840
Accumulated depletion and depreciation (109,315) (88,169)
----------------------------------------------------------------------------
Net Property and Equipment 222,826 167,671
----------------------------------------------------------------------------
335,144 293,987
----------------------------------------------------------------------------
Liabilities
Current
Accounts payable and accrued liabilities 16,839 18,868
Due to related parties (Note 7) 32,000 23,500
Deferred credit (Note 10) 19,586 7,363
----------------------------------------------------------------------------
68,425 49,731
Subordinated promissory note (Note 8) 15,000 -
Bank debt (Note 9) 70,386 59,823
Deferred credit (Note 10) 25,850 47,769
Asset retirement obligations (Note 11) 17,070 17,790
----------------------------------------------------------------------------
196,731 175,113
----------------------------------------------------------------------------
Commitments, Contingencies and Guarantees (Note 16)
Shareholders' Equity (Note 12)
Share capital 135,030 121,955
Contributed surplus 3,135 3,350
----------------------------------------------------------------------------
138,165 125,305
----------------------------------------------------------------------------
Deficit (5,454) (8,451)
Accumulated other comprehensive income (Note 13) 5,702 2,020
----------------------------------------------------------------------------
248 (6,431)
----------------------------------------------------------------------------
Total Shareholders' Equity 138,413 118,874
----------------------------------------------------------------------------
335,144 293,987
----------------------------------------------------------------------------

See the accompanying notes to the consolidated financial statements


Bonterra Energy Corp.
Consolidated Statements of Shareholders' Equity

For the Years Ended December 31
($ 000s) 2010 2009
----------------------------------------------------------------------------
Shareholders' equity, beginning of year 118,874 56,777
Comprehensive income for the year 53,546 69,163
Common Shares issued pursuant to private placement - 17,217
Common Shares issued on acquisition - 3,207
Common Shares issued pursuant to Company share
option plan 12,377 1,898
Stock-based compensation expense 483 911
Dividends declared (46,867) (30,299)
----------------------------------------------------------------------------
Shareholders' Equity, End of Year 138,413 118,874
----------------------------------------------------------------------------

Bonterra Energy Corp.
Consolidated Statements of Operations and Deficit

For the Years Ended December 31
($ 000s except $ per share) 2010 2009
----------------------------------------------------------------------------
Revenue and Other Income
Oil and gas sales 118,980 85,712
Royalties (11,437) (7,414)
Investment tax credit recovery - 27,670
Gain on sale of property (Note 6) 6,485 24,198
Gain on sale of investments 4,335 -
Interest and other 36 158
----------------------------------------------------------------------------
118,399 130,324
----------------------------------------------------------------------------
Expenses
Production costs 30,451 27,848
General and administrative 5,406 4,458
Interest on long-term debt (Notes 8 and 9) 2,244 2,833
Other interest (Note 7) 555 461
Stock-based compensation 483 911
Depletion, depreciation and accretion 22,278 19,277
----------------------------------------------------------------------------
61,417 55,788
----------------------------------------------------------------------------
Earnings Before Taxes 56,982 74,536
----------------------------------------------------------------------------
Taxes (Note 10)
Current 141 551
Future 6,977 5,422
----------------------------------------------------------------------------
7,118 5,973
----------------------------------------------------------------------------
Net Earnings for the Year 49,864 68,563
Deficit, beginning of year (8,451) (46,715)
Dividends declared and paid (46,867) (30,299)
----------------------------------------------------------------------------
Deficit, end of year (5,454) (8,451)
----------------------------------------------------------------------------
Net Earnings Per Share - Basic (Note 12) 2.65 3.81
----------------------------------------------------------------------------
Net Earnings Per Share - Diluted (Note 12) 2.58 3.78
----------------------------------------------------------------------------

See the accompanying notes to the consolidated financial statements

Bonterra Energy Corp.
Consolidated Statements of Comprehensive Income

For the Years Ended December 31
($ 000s except $ per share) 2010 2009
----------------------------------------------------------------------------
Net Earnings for the Year 49,864 68,563
----------------------------------------------------------------------------
Other comprehensive income net of income tax
Unrealized gains on investments (net of income
taxes of 1,192, (2009 - 97)) 7,410 600
Realized gains on investments transferred to net
earnings (net of income taxes of 607 (2009 - Nil)) (3,728) -
----------------------------------------------------------------------------
Other Comprehensive Income 3,682 600
----------------------------------------------------------------------------
Comprehensive Income 53,546 69,163
----------------------------------------------------------------------------
Comprehensive Income Per Share - Basic (Note 12) 2.85 3.84
----------------------------------------------------------------------------
Comprehensive Income Per Share - Diluted (Note 12) 2.77 3.81
----------------------------------------------------------------------------

See the accompanying notes to the consolidated financial statements


Bonterra Energy Corp.
Consolidated Statements of Cash Flow

For the Years Ended December 31
($ 000s) 2010 2009
----------------------------------------------------------------------------
Operating Activities
Net earnings for the year 49,864 68,563
Items not affecting cash
Stock-based compensation 483 911
Depletion, depreciation and accretion 22,278 19,277
Gain on sale of property (6,485) (24,198)
Gain on sale of investments (4,335) -
Future income taxes 6,977 5,422
----------------------------------------------------------------------------
68,782 69,975
----------------------------------------------------------------------------
Change in non-cash working capital
Accounts receivable (2,590) (47)
Crude oil inventory (39) 365
Prepaid expenses 1,616 1,057
Accounts payable and accrued liabilities (1,313) (4,654)
Restricted cash 812 440
Investment tax credit receivable - (27,670)
Asset retirement obligations settled (Note 11) (1,006) (573)
----------------------------------------------------------------------------
(2,520) (31,082)
----------------------------------------------------------------------------
Cash Provided by Operating Activities 66,262 38,893
----------------------------------------------------------------------------
Financing Activities
Increase (decrease) in debt 10,563 (35,613)
Due to related parties 8,500 17,500
Subordinated promissory note 15,000 -
Issue of shares pursuant to private placement - 17,996
Share issue costs - (1,046)
Stock option proceeds 12,377 1,898
Dividends (46,867) (30,299)
----------------------------------------------------------------------------
Cash Used in Financing Activities (427) (29,564)
----------------------------------------------------------------------------
Investing Activities
Property and equipment expenditures (76,914) (28,726)
Proceeds on sale of properties 6,234 23,729
Proceeds on sale of investments 5,603 -
Restricted term deposit - 20
Change in non-cash working capital
Accounts receivable (42) (3,613)
Accounts payable and accrued liabilities (716) (739)
----------------------------------------------------------------------------
Cash Used in Investing Activities (65,835) (9,329)
----------------------------------------------------------------------------
Net cash inflow - -
Cash, beginning of year - -
----------------------------------------------------------------------------
Cash, End of Year - -
----------------------------------------------------------------------------
Cash Interest Paid 2,799 3,294
Cash Taxes Paid 152 616
----------------------------------------------------------------------------

See the accompanying notes to the consolidated financial statements


Bonterra Energy Corp.

Notes to the Consolidated Financial Statements

For the Years Ended December 31, 2010 and 2009

1. CHANGE OF ORGANIZATION

Effective January 1, 2010, Bonterra Energy Income Trust, a wholly owned Trust of Bonterra Oil & Gas Ltd., was wound up into its parent and was amalgamated with Bonterra Energy Corp., a former subsidiary of the Trust. The continuing entity officially changed its name to Bonterra Energy Corp. ("Bonterra" or the
"Company") subsequent to finalizing the reorganization.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Consolidation

These consolidated financial statements include the accounts of the Company, the Trust (wholly owned by the Company as of December 31, 2009 and wound up on January 1, 2010) and its wholly owned subsidiary Bonterra Energy Corp. (amalgamated with the Company on January 1, 2010). Inter-company transactions and balances are eliminated upon consolidation.

Measurement Uncertainty

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the balance sheets as well as the reported amounts of revenues, expenses, and cash flows during the periods presented. Such estimates relate primarily to unsettled transactions and events as of the date of the financial statements. Actual results could differ materially from estimated amounts.

Amounts recorded for depletion, depreciation, accretion and amounts used for impairment calculations are based on estimates of crude oil and natural gas reserves and future costs required to develop those reserves. Stock-based compensation is based upon expected volatility and option life estimates. Asset retirement obligations are based on estimates of abandonment costs, timing of abandonment, inflation and interest rates. The provision for income taxes is based on judgements in applying income tax law and estimates on the timing, likelihood and reversal of temporary differences between the accounting and tax basis of assets and liabilities. These estimates are subject to measurement uncertainty and changes in these estimates could materially impact the financial statements of future periods.

Revenue Recognition

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

Joint Interest Operations

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

Inventories

Inventories consist of crude oil. Crude oil stored in the Company's tanks are valued on a first in first out basis at the lower of cost or net realizable value. Inventory cost for crude oil is determined based on combined average per barrel operating costs, royalties and depletion and depreciation for the year and net realizable value is determined based on estimated sales price less transportation costs.

Investments

Investments are carried at fair value. Fair value is determined by multiplying the year end trading price of the investments by the number of common shares held at period end.

Property and Equipment

Petroleum and Natural Gas Properties and Related Equipment

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

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

Costs related to undeveloped properties are excluded from the depletion base until it is determined whether or not proved reserves exist or if impairment of such costs has occurred. These properties are assessed at least annually to determine whether impairment has occurred.

Depreciation and depletion of capitalized costs of oil and gas producing properties are calculated using the unit-of-production method. Development and exploration drilling costs are depleted over the remaining proved reserves.

On January 1, 2010, the Company prospectively began depreciating petroleum and natural gas plant and equipment using the declining balance method at 10 percent per year, a change from the straight-line method. The change of estimate was due to declining balance depreciation providing a better reflection of the estimated service life of the related assets. During 2010, the Company incurred $2,000,000 less depreciation under the declining balance method, than under the straight-line method.

Furniture, Equipment and Other

On January 1, 2010, the Company prospectively began depreciating these assets using the declining balance method at rates of 10 percent to 30 percent per year, a change from the straight-line method. The change of estimate was due to declining balance depreciation providing a better reflection of the estimated service life of the related assets. During 2010, the Company incurred $141,000 less depreciation under the declining balance method, than under the straight-line method.

Income Taxes

The Company accounts for income taxes using the liability method. Under this method, the Company records a future income tax asset or liability to reflect any difference between the accounting and tax basis of assets and liabilities, using substantively enacted income tax rates. The effect on future tax assets and liabilities of a change in tax rates is recognized in net earnings in the period in which the change occurs. Future income tax assets are only recognized to the extent it is more likely than not that sufficient future taxable income will be available to allow the future income tax asset to be realized.

Asset Retirement Obligations

The Company recognizes an Asset Retirement Obligation (ARO) in the period in which it is incurred when a reasonable estimate of the fair value can be made. On a periodic basis, management will review these estimates and changes, if any, will be applied prospectively. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the obligations are charged against the ARO to the extent of the liability recorded.

Stock-Based Compensation

The Company accounts for stock based compensation using the fair-value method of accounting for stock options granted to directors, officers, employees and other service providers using the Black-Scholes option pricing model. Stock-based compensation expense is recorded over the vesting period with a corresponding amount reflected in contributed surplus. Stock-based compensation expense is calculated as the estimated fair value of the options at the time of grant, amortized over their vesting period. When stock options are exercised, the associated amounts previously recorded as contributed surplus are reclassified to common share capital. The Company has not incorporated an estimated forfeiture rate for stock options that will not vest, rather, the Company accounts for actual forfeitures as they occur.

Financial Instruments

Financial instruments are measured at fair value on initial recognition of the instrument and are classified into one of the following five categories: held-for trading, loans and receivables, held-to-maturity investments, available-for-sale financial assets or other financial liabilities.

Subsequent measurement of financial instruments is based on their initial classification. Held-for-trading financial instruments are measured at fair value and changes in fair value are recognized in net earnings. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive income until the instrument is derecognized or impaired. The remaining categories of financial instruments are recognized at amortized cost using the effective interest rate method.

All risk management contracts are recorded in the balance sheet at fair value unless they qualify for the normal sale and normal purchase exemption. All changes in their fair value are recorded in net earnings unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income until the underlying hedged transaction is recognized in net earnings. Any hedge ineffectiveness is immediately recognized in net earnings. The Company has elected not to use cash flow hedge accounting on its risk management contracts with financial counterparties resulting in all changes in fair value being recorded in net earnings.

Accounts receivable are classified as loans and receivables which are measured at amortized cost. Investments and investments in related party are classified as available-for-sale which are measured at fair value and any gains or losses are recognized in other comprehensive income in the period they occur. Accounts payable and accrued liabilities, bank debt, subordinated promissory note and amounts due to related parties are classified as other financial liabilities, which are measured at amortized cost.

Risk Management Contracts

The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign currency exchange rates and interest rates in the normal course of its business. The Company may use a variety of instruments to manage these exposures. For transactions where hedge accounting is not applied, the Company accounts for such instruments using the fair value method by initially recording an asset or liability, and recognizing changes in the fair value of the instruments in earnings as unrealized gains or losses on risk management contracts. Fair values of financial instruments are based on third party quotes or valuations provided by independent third parties. Any realized gains or losses on risk management contracts are recognized in earnings in the period they occur.

The Company may elect to use hedge accounting when there is a high degree of correlation between the price movements in the financial instruments and the items designated as being hedged and the Company has documented the relationship between the instruments and the hedged item as well as its risk management objective and strategy for undertaking hedge transactions. During the years ended December 31, 2010 and December 31, 2009, the Company did not designate any of its financial instruments as hedges. There are no risk management contracts outstanding at December 31, 2010 and December 31, 2009.

Basic and Diluted per Share Calculations

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

3. RECENT ACCOUNTING PRONOUNCEMENTS

The Canadian Accounting Standards Board has confirmed that IFRS will replace Canadian GAAP effective January 1, 2011, including comparatives for 2010, for Canadian publicly accountable enterprises.

4. BUSINESS COMBINATIONS

On July 2, 2009, the Company acquired all of the issued common shares of Cobalt Energy Ltd. (Cobalt) for consideration of 201,438 common shares at a value of $15.92 per common share plus the assumption of $2,856,000 of negative working capital for total consideration of $6,063,000. Results of Cobalt's operations have been included in the consolidated financial statements commencing from that date.

The acquisition was accounted for using the purchase method and the purchase price was allocated to the fair value of the assets acquired and the liabilities assumed as follows:



($ 000s)
Cost of acquisition
Value of common stock 3,207
Acquisition costs 170
----------------------------------------------------------------------------
3,377
----------------------------------------------------------------------------
Allocation of purchase price:
Property and equipment 7,105
Future income tax liability (748)
Working capital deficiency (2,856)
Asset retirement obligations (124)
----------------------------------------------------------------------------
3,377
----------------------------------------------------------------------------


5. INVESTMENT IN RELATED PARTY

The investment consists of 689,682 common shares in Geomark Exploration Ltd. (Geomark), a company having common directors and management with the Company. The investment is recorded at fair market value.

Effective July 6, 2010, Comaplex Minerals Corp. (Comaplex) (a company having common management and directors) was acquired by Agnico-Eagle Mines Limited (Agnico-Eagle). In exchange for Bonterra's 689,682 common shares in Comaplex, the Company received 689,682 shares in Geomark and 108,693 common shares in Agnico-Eagle (value included in Investments on the balance sheet). The investment in Geomark represents 1.3 percent ownership in the outstanding common shares of Geomark.

6. PROPERTY AND EQUIPMENT



2010 2009
----------------------------------------------------------------------------
Accumulated Accumulated
Depletion and Depletion and
($ 000s) Cost Depreciation Cost Depreciation
----------------------------------------------------------------------------
Undeveloped land 4,595 - 7,992 -
Petroleum and natural
gas properties and
related equipment 326,072 108,217 246,387 87,153
Furniture, equipment and
other 1,474 1,098 1,461 1,016
----------------------------------------------------------------------------
332,141 109,315 255,840 88,169
----------------------------------------------------------------------------


On November 6, 2009, the Company divested of a portion of its Shaunavon oil production to Eagle Rock Exploration Ltd. (Eagle Rock). The proceeds of disposition consisted of $23,729,000 cash and 30,769,200 common shares in Eagle Rock (representing approximately 4.2 percent of the outstanding common shares of that company at that time). The Eagle Rock common shares were trading for $0.21 cents per share on November 6, 2009. The Company had a net book value (after effects of asset retirement obligations) of $5,993,000 attributable to the assets disposed of resulting in a gain on sale of the property of $24,198,000.

Eagle Rock has since changed its name to Wild Stream Exploration Inc. (Wild Stream) and consolidated its common shares on a 30:1 basis resulting in Bonterra holding 1,025,640 common shares (value included in Investments on the balance sheet).

In February 2010, the Company disposed of its Southeast Saskatchewan Pinto property. The proceeds of disposition were $5,534,000 cash. At the time of disposition, the Company had a net book value of $120,000 for the property. It also had an asset retirement obligation related to the property of $371,000 that was transferred resulting in a gain on sale of property of $5,785,000.

In July 2010, the Company disposed of non-producing land rights for proceeds of $700,000. The Company has never had any capital costs associated with these land rights.

During the year the Company capitalized $Nil (2009 - $460,000) of general and administrative costs.

7. DUE TO RELATED PARTIES

As of December 31, 2010, the Company's CEO and major shareholder has loaned the Company $12,000,000 (December 31, 2009 - $11,500,000). The loan is unsecured, bears interest at a Canadian chartered bank prime less 5/8th of a percent and has no set repayment terms but is payable on demand. Interest paid on this loan during 2010 was $242,000 (2009 - $209,000).

As a result of the acquisition by Agnico-Eagle of Comaplex on July 6, 2010, the $12,000,000 loan previously held by Comaplex was transferred to Geomark and is repayable by the Company under the same terms. As of December 31, 2010, Geomark has loaned the Company $20,000,000. The loan is unsecured, bears interest at a Canadian chartered bank prime less 5/8th of a percent and has no set repayment terms but is payable on demand. Interest paid on this loan during 2010 was $313,000 (including interest paid to Comaplex) (2009 - $194,000 paid to Comaplex).

The Company's bank agreement requires that the above loans can only be repaid should the Company have sufficient available borrowing limits under the Company's credit facility. As of December 31, 2010, the Company has sufficient room to repay all balances.

Please refer to Note 14 for additional related party transactions.

8. SUBORDINATED PROMISSORY NOTE

On October 4, 2010 the Company borrowed $15,000,000 from a private investor. In exchange Bonterra has issued a Subordinated Promissory Note for $15,000,000. The terms of the Subordinated Promissory Note are that it bears interest at three percent, is not callable by the investor prior to January 4, 2012 at which time it will be a demand note until its maturity of April 4, 2012, and can be repaid at the option of the Company at any time. Security consists of a floating demand debenture totaling $15,000,000 over all of the Company's assets and is subordinated to any and all claims in favor of the syndicate of senior lenders providing credit facilities to the Company. Interest paid on the subordinated promissory note during 2010 was $110,000.

The Company's bank agreement requires that the above loan can only be repaid should the Company have sufficient available borrowing limits under the Company's credit facility. As of December 31, 2010 the Company has sufficient room to repay the subordinated promissory note.

9. BANK DEBT

As of December 31, 2010, the Company has a bank facility consisting of a $100,000,000 syndicated and $20,000,000 non-syndicated revolving credit facility (December 31, 2009 - $100,000,000 syndicated and $20,000,000 non-syndicated revolving credit facility). The interest rates on the outstanding debt as of December 31, 2010 were 4.0 percent and 3.4 percent on the Company's Canadian prime rate loan and Bankers' Acceptances, respectively. The terms of the syndicated revolving credit facility provided that the loan is revolving to April 27, 2012 and is subject to annual review. The revolving credit facility has no fixed payment requirements. The Company at December 31, 2010 was in level I (see below) in respect of its various borrowing charges.

The amount available for borrowing under the credit facility is reduced by outstanding letters of credit. Letters of credit totaling $285,000 were issued at December 31, 2010 (December 31, 2009 - $285,000). Security for the credit facilities consists of various fixed and floating demand debentures totaling $200,000,000 over all of the Company's assets, and a general security agreement with first ranking over all personal and real property.

The interest rate on the credit facility is calculated as follows:



----------------------------------------------------------------------------
Level I Level II Level III Level IV Level V
----------------------------------------------------------------------------
Consolidated Total
Funded Debt (1) to
Consolidated Cash Under Over 1.0:1 Over 1.5:1 Over 2.0:1 Over
flow Ratio 1.0:1 to 1.5:1 to 2.0:1 to 2.5:1 2.5:1
----------------------------------------------------------------------------
Canadian Prime Rate
Plus (2) 100 150 175 200 250
----------------------------------------------------------------------------
Bankers'
Acceptances Rate
Plus (2) 225 275 300 325 375
----------------------------------------------------------------------------


(1) Consolidated total funded debt excludes related party amounts and subordinated debenture but includes working capital. Consolidated cash flow is calculated as cash flow according to GAAP excluding adjustments for non-cash working capital items.
(2) Numbers in table represent basis points.

Consolidated total funded debt to consolidated cash flow ratio shall be calculated each fiscal quarter and the interest rates adjusted effective as of the first day of the fiscal quarter commencing immediately after the fiscal quarter in which Bonterra files a compliance certificate containing the ratio, with each such adjustment to be effective until the next such adjustment.

The following is a list of the material covenants:



-- The Company is required to not exceed $120,000,000 in consolidated total
funded debt (includes working capital but excludes due to related
parties and subordinated debt).
-- The total of the dividends paid in the current quarter and the three
previous quarters shall not exceed 80 percent of the previous four
quarters' cash flow as defined under GAAP excluding adjustments for non-
cash working capital items.


At December 31, 2010, the Company is in compliance with all covenants.

10. INCOME TAXES

The Company has recorded a future income tax asset related to assets and liabilities and related tax amounts:



($ 000s) 2010 2009
----------------------------------------------------------------------------
Future tax liability related to investments (832) (824)
Future tax liability related to property and
equipment (12,347) (5,855)
Future tax asset related to asset retirement
obligations 4,274 4,474
Future tax asset related to finance costs 367 802
Future tax asset related to corporate tax losses and
SR&ED claims 37,717 59,668
Future tax asset related to corporate capital tax
losses 17,705 17,883
Valuation adjustment (16,873) (17,883)
----------------------------------------------------------------------------
Future Tax Asset - Long-Term 30,011 58,265
----------------------------------------------------------------------------

Current portion of future income tax asset related to
corporate tax
losses and SR&ED claims: 22,889 11,889
----------------------------------------------------------------------------
Future Tax Asset - Current 22,889 11,889
----------------------------------------------------------------------------


A reconciliation of the deferred credit is as follows:



($ 000s)
----------------------------------------------------------------------------
Amount recorded on reorganization 71,303
Amortized in 2008 (4,240)
Amortized in 2009 (12,356)
Rate adjustment 2009 425
----------------------------------------------------------------------------
Balance as of December 31, 2009 55,132
Amortized in 2010 (9,408)
Rate adjustment 2010 (288)
----------------------------------------------------------------------------
Balance as of December 31, 2010 45,436
----------------------------------------------------------------------------

Current portion 19,586
Long-term portion 25,850
----------------------------------------------------------------------------
45,436
----------------------------------------------------------------------------


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



($ 000s) 2010 2009
----------------------------------------------------------------------------
Earnings before income taxes 56,982 74,536
Combined federal and provincial income tax rates 28.06% 29.15%
----------------------------------------------------------------------------
Income tax provision calculated using statutory tax 15,989 21,727
rates
Increase (decrease) in taxes resulting from:
Saskatchewan resource surcharge 141 282
Quebec tax - 269
Stock-based compensation 136 266
Deferred credit amortization (9,696) (11,931)
Non-taxable portion of gains (461) -
Change in valuation allowance (1,010) -
Change in effective tax rate 2,071 (4,708)
Other (52) 68
----------------------------------------------------------------------------
Income tax expense 7,118 5,973
----------------------------------------------------------------------------


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



($ 000s) Rate of
Utilization (%) Amount
----------------------------------------------------------------------------
Undepreciated capital costs 20-100 25,441
Eligible capital expenditures 7 6,849
Share issue costs 20 1,424
Canadian oil and gas property expenditures 10 19,074
Canadian development expenditures 30 109,642
Canadian exploration expenditures 100 11,140
SR&ED expenditures 100 39,985
Income tax losses carried forward (1) 100 222,596
----------------------------------------------------------------------------
436,151
----------------------------------------------------------------------------


(1) Federal income tax losses carried forward expire in the following years; 2024 - $3,347,000, 2025 - $7,532,000, 2026 - $46,671,000, 2027 - $117,189,000, 2028 - $34,726,000, 2029 - $13,131,000.

The Company has $27,670,000 (2009 - $27,670,000) remaining of investment tax credits that expire in the following years; 2019 - $3,469,000, 2020 - $3,059,000, 2021 - $4,667,000, 2022 - $3,909,000, 2023 - $3,155,000, 2024 - $1,995,000, 2025 - $2,257,000, 2026 - $2,405,000, 2027 - $2,009,000, 2028 - $745,000.

The Company also has $141,417,000 (December 31, 2009 - $143,061,000) of capital loss carry forwards which can only be claimed against taxable capital gains.

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

11. ASSET RETIREMENT OBLIGATIONS

At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $62,579,000 (2009 - $64,482,000). Costs for asset retirement have been calculated assuming a 1.5 percent inflation rate. These obligations will be settled based on the useful lives of the underlying assets, which extend up to 50 years into the future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent (2009 - five percent).

Changes to asset retirement obligations were as follows:



($ 000s) 2010 2009
----------------------------------------------------------------------------
Asset retirement obligations, January 1 17,790 18,338
Adjustment to asset retirement obligations (220) (138)
Adjustment related to asset disposals (368) (750)
Liabilities settled during the year (1,006) (573)
Accretion 874 913
----------------------------------------------------------------------------
Asset retirement obligations, December 31 17,070 17,790
----------------------------------------------------------------------------


12. SHAREHOLDERS' EQUITY

Authorized

The Company is authorized to issue an unlimited number of common shares without nominal or par value. The Company is also authorized to issue an unlimited number of Class "A" redeemable Preferred Shares and an unlimited number of Class "B" Preferred Shares. There are currently no outstanding Class "A" redeemable preferred shares or Class "B" preferred shares.

Issued



2010 2009
----------------------------------------------------------------------------
Amount Amount ($
Number ($ 000s) Number 000s)
----------------------------------------------------------------------------
Common Shares
Balance, beginning of
year 18,619,641 121,955 17,257,603 99,530
Issued pursuant to
private placement - - 1,068,000 17,996
Issued on acquisition of
Cobalt (Note 4) - - 201,438 3,207
Issued pursuant to
Company share option
plan 599,900 12,377 92,600 1,898
Transfer of contributed
surplus to share capital - 698 - 103
Issue costs for private
placement - - - (1,046)
Future tax effect of
share issue costs - - - 267
----------------------------------------------------------------------------
Balance, end of year 19,219,541 135,030 18,619,641 121,955
----------------------------------------------------------------------------


On May 27, 2009, the Company completed a private placement for 1,068,000 common shares at a price of $16.85 per common share for aggregate proceeds of $17,996,000. The Company incurred issue costs of $1,046,000 in respect of the offering.

The number of common shares used to calculate diluted net earnings per share for the year ended December 31, 2010 of 19,348,991 shares (2009 - 18,131,085) included the basic weighted average number of common shares outstanding of 18,810,355 shares (2009 - 18,006,320) plus 538,636 shares (2009 - 124,765) related to the dilutive effect of common share options.

A summary of the changes to the Company's contributed surplus is presented below:



Contributed Surplus
($ 000s) 2010 2009
----------------------------------------------------------------------------
Balance, beginning of year 3,350 2,542
Stock-based compensation expensed (non-cash) 483 911
Stock-based options exercised (non-cash) (698) (103)
----------------------------------------------------------------------------
Balance, end of year 3,135 3,350
----------------------------------------------------------------------------


The deficit balance is composed of the following items:



($ 000s) 2010 2009
----------------------------------------------------------------------------
Accumulated earnings 326,609 276,745
Accumulated cash dividends (332,063) (285,196)
----------------------------------------------------------------------------
Deficit (5,454) (8,451)
----------------------------------------------------------------------------


The Company provides a stock option plan for its directors, officers, employees and consultants. Under the plan, the Company may grant options for up to 1,921,954 common shares (2009 - 1,861,964). The exercise price of each option granted equals the market price of the common shares on the date of grant and the option's maximum term is five years.

A summary of the status of the Company's stock option plan as of December 31, 2010 and 2009, and changes during the years ended on those dates is presented below:



December 31, 2010 December 31, 2009
----------------------------------------------------------------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Options Price Options Price
----------------------------------------------------------------------------
Outstanding at beginning
of period 1,330,900 $ 20.36 1,390,500 $ 20.50
Options granted 36,000 36.98 33,000 14.90
Options cancelled (20,000) 34.66 - -
Options exercised (599,900) 20.63 (92,600) 20.50
----------------------------------------------------------------------------
Outstanding at end of
period 747,000 $ 20.56 1,330,900 $ 20.36
----------------------------------------------------------------------------
Options exercisable at end
of period 255,500 $ 20.50 370,900 $ 20.50
----------------------------------------------------------------------------


The following table summarizes information about options outstanding at December 31, 2010:



Options Outstanding Options Exercisable
----------------------------------------------------------------------------
Range of Number Weighted- Weighted- Number Weighted-
Exercise Outstanding Average Average Exercisable Average
Prices At 12/31/10 Remaining Exercise at 12/31/10 Exercise
Contractual Price Price
Life
----------------------------------------------------------------------------
$ 14.90 22,000 2.1 years $ 14.90 - $ -
20.50 719,000 1.9 years 20.50 255,500 20.50
48.60 6,000 2.5 years 48.60 - -
----------------------------------------------------------------------------
$ 14.90- 747,000 1.9 years $ 20.56 255,500 $ 20.50
48.60
----------------------------------------------------------------------------


The Company records compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. In 2010, the Company granted 36,000 stock options with an estimated fair value of $204,000 ($5.67 per option) using the Black-Scholes option pricing model with the following key assumptions:



2010 2009
----------------------------------------------------------------------------
Weighted-average risk free interest
rate (%) 1.87 1.4
Expected life (years) 2.8 3.0
Weighted-average volatility (%) 33.1 33.0
Dividend yield 2010 and 2009 based on the percentage of dividends
paid during the period granted
----------------------------------------------------------------------------


13. ACCUMULATED OTHER COMPREHENSIVE INCOME



Other
Comprehensive December 31,
($ 000s) January 1, 2010 Income 2010
----------------------------------------------------------------------------
Unrealized gains on
available
for sale financial assets 2,020 3,682 5,702
----------------------------------------------------------------------------

Other
Comprehensive December 31,
($ 000s) January 1, 2009 Income 2009
----------------------------------------------------------------------------
Unrealized gains on
available
for sale financial assets 1,420 600 2,020
----------------------------------------------------------------------------


14. RELATED PARTY TRANSACTIONS

The Company received a management fee from Geomark and Comaplex of $316,500 (Comaplex 2009 - $330,000) for management services and office administration. This fee has been included as a recovery in general and administrative expenses. At December 31, 2010, the Company had an account receivable from Geomark of $35,000 (Comaplex December 31, 2009 - $105,000). Effective July 6, 2010, the Company cancelled its management agreement with Comaplex due to its takeover by Agnico-Eagle.

A new management agreement was entered into with Geomark effective July 6, 2010, under the same terms and conditions as those of the Comaplex agreement except that the monthly fee is $22,500 compared to Comaplex's monthly fee of $30,000.

The Company received a management fee from Pine Cliff Energy Ltd. (Pine Cliff), a company having common directors and management with Bonterra, of $90,000 (2009 - $120,000) for management services and office administration. This fee has been included as a recovery in general and administrative expenses. At December 31, 2010 the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2009 - $1,000).

These transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

15. FINANCIAL AND CAPITAL RISK MANAGEMENT

Financial Risk Factors

The Company undertakes transactions in a range of financial instruments including:



-- Receivables
-- Payables and accrued liabilities
-- Common share investments
-- Due to related parties
-- Bank debt
-- Subordinated Promissory Note


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

The Company's overall risk management program seeks to mitigate these risks and reduce the volatility on the Company's financial performance. Financial risk management is carried out by senior management under the direction of the Directors of the Company.

The Company may enter into various risk management contracts in accordance with Board approval to manage the Company's exposure to commodity price fluctuations. Currently no risk management agreements are in place. The Company does not speculatively trade in risk management contracts. The Company's risk management contracts are entered into to manage the risks relating to commodity prices from its business activities.

Capital Risk Management

The Company's objectives when managing capital, which the Company defines to include shareholders' equity, debt, due to related parties, subordinated promissory note and working capital balances, are to safeguard the Company's ability to continue as a going concern, so that it can continue to provide returns to its shareholders 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 Company may adjust the amount of dividends, debt facilities or issue new shares.

The Company monitors capital on the basis of the ratio of debt to cash flow. This ratio is calculated using each quarter end net debt (total debt adjusted for working capital) and divided by the preceding twelve months cash flow. The Company believes that a debt level of approximately one and a half year's cash flow is an appropriate level to allow it to take advantage in the future of either acquisition opportunities or to provide flexibility to develop its undeveloped resources by horizontal or vertical drill programs.

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

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

The following section (c) provides details of the Company'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 Company's financial assets and liabilities are shown in Table 1.

Table 1



As at December 31, 2010
($ 000s) Carrying Value Fair Value Face Value
----------------------------------------------------------------------------

Financial assets
Accounts receivable 17,345 17,345 17,445
Investments 11,471 11,471 N/A
Investments in related party 814 814 N/A

Financial liabilities
Accounts payable and accrued 16,839 16,839 16,839
liabilities
Due to related parties 32,000 32,000 32,000
Subordinated promissory note 15,000 15,000 15,000
Bank debt 70,386 70,386 70,386
----------------------------------------------------------------------------

As at December 31, 2009
($ 000s) Carrying Value Fair Value Face Value
----------------------------------------------------------------------------

Financial assets
Accounts receivable 14,713 14,713 14,873
Investments 4,462 4,462 N/A
Investments in related party 4,827 4,827 N/A
Restricted cash 812 812 812

Financial liabilities
Accounts payable and accrued 18,868 18,868 18,868
liabilities
Due to related parties 23,500 23,500 23,500
Bank debt 59,823 59,823 59,823
----------------------------------------------------------------------------


Financial instruments consisting of accounts receivable, accounts payable and accrued liabilities, due to related parties, subordinated promissory note and bank debt on the consolidated balance sheet are carried at amortized cost. Investments and investments in related party are carried at fair value. All of the fair value items are transacted in active markets. Bonterra classifies the fair value of these transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

Bonterra's investments and investments in related party have been assessed on the fair value hierarchy described above and are all considered Level 1.

The net debt and cash flow from operations figures are presented in Table 2.

Table 2



($ 000s) December 31, 2010
----------------------------------------------------------------------------
Bank debt 70,386
Due to related parties 32,000
Subordinated promissory note 15,000
Accounts payable and accrued liabilities 16,839
Current assets(1) (30,934)
----------------------------------------------------------------------------
Net Debt 103,291
----------------------------------------------------------------------------
Cash flow from operations(2) 66,262
----------------------------------------------------------------------------
Net debt to cash flow from operations 1.56
----------------------------------------------------------------------------


(1) Current assets include accounts receivable, crude oil inventory, prepaid expenses, and investments.
(2) Cash flow from operations includes annual net earnings less adjustment for, stock-based compensation, depletion, depreciation and accretion, gain on sale of property, gain on sale of investments, future income taxes, changes in non-cash working capital items, and asset retirement obligations settled.

b) Risks and mitigations

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

Commodity price risk

The Company'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 Company's performance and ability to continue with its dividends.

The Company has used various risk management contracts to set price parameters for a portion of its production. Management, in agreement with the Board of Directors, decided that at least in the near term it will discontinue the use of commodity price agreements. The Company will assume full risk in respect of commodity prices.

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 the Company uses. The principal exposure of the Company is on its borrowings which have a variable interest rate which gives rise to a cash flow interest rate risk.

The Company's debt facilities consist of a $100,000,000 revolving operating line, $20,000,000 demand operating line, a $15,000,000 subordinated promissory note and $32,000,000 due to related parties. The borrowings under these facilities are at bank prime plus or minus various percentages as well as by means of bankers' acceptances (BA's) within the Company's credit facility. The Company 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.

Sensitivity Analysis

Based on historic movements and volatilities in the interest rate markets and management's current assessment of the financial markets, the Company believes that a one percent variation in the Canadian prime interest rate is reasonably possible over a 12-month period.

A one percent increase (decrease) in the Canadian prime rate would decrease (increase) net earnings and comprehensive income by $758,000, respectively.

Foreign exchange risk

The Company has no foreign operations and currently sells all its product sales in Canadian currency. The Company however is exposed to currency risk in that crude oil is priced in U.S. currency then converted to Canadian currency. The Company currently has no outstanding risk management agreements. Management, in agreement with the Board of Directors, decided that at least in the near term it will discontinue the use of commodity price agreements. The Company 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 Company to incur a financial loss. The Company is exposed to credit risk on all financial assets included on the balance sheet. To help mitigate this risk:



-- The Company only enters into material agreements with credit worthy
counterparties. These include major oil and gas companies or major
Canadian chartered banks; and
-- Agreements for product sales are primarily on 30 day renewal terms.


Of the accounts receivable balance of December 31, 2010 ($17,345,000) and December 31, 2009 ($14,713,000) over 88 (2009 - 87) percent relates to product sales with international oil and gas companies and drilling credits receivable from the province of Alberta.

The Company assesses quarterly, if there has been any impairment of the financial assets of the Company. During the year ended December 31, 2010, there was no impairment provision required on any of the financial assets of the Company due to historical success of realizing financial assets. The Company does have a credit risk exposure as the majority of the Company's accounts receivables are with counterparties having similar characteristics. However, payments from the Company's largest accounts receivable counterparties have consistently been received within 30 days and the sales agreements with these parties are cancellable with 30 days notice if payments are not received.

At December 31, 2010, approximately $231,000 or 1.3 percent of the Company's total accounts receivable are aged over 120 days and considered past due. The majority of these accounts are due from various joint venture partners. The Company actively monitors past due accounts and takes the necessary actions to expedite collection, which can include withholding production or netting payables when the accounts are with joint venture partners. Should the Company determine that the ultimate collection of a receivable is in doubt, it will provide the necessary provision in its allowance for doubtful accounts with a corresponding charge to earnings. If the Company subsequently determines an account is uncollectable, the account is written off with a corresponding charge to the allowance account. The Company's allowance for doubtful accounts balance at December 31, 2010 is $100,000 (December 31, 2009 - $160,000) with the difference being included in general and administrative expenses. There were no accounts written off during the year.

The maximum exposure to credit risk is represented by the carrying amount on the balance sheet. There are no material financial assets that the Company considers past due.

Liquidity risk

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



-- The Company will not have sufficient funds to settle a transaction on
the due date;
-- The Company will not have sufficient funds to continue with its
dividends;
-- The Company will be forced to sell assets at a value which is less than
what they are worth; or
-- The Company may be unable to settle or recover a financial asset at all.


To help reduce these risks the Company:



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


The Company has the following maturity schedule for its financial liabilities:



Payments Due By Period
Recognized on
Financial
($ 000s) Statements Less than 1 year 1-3 years 4-5 years
----------------------------------------------------------------------------
Accounts
payable and
accrued
liabilities Yes - Liability 16,839 - -
Due to related
parties Yes - Liability 32,000 - -
Subordinated
promissory
note Yes - Liability - 15,000 -
Bank debt Yes - Liability - 70,386 -
Office leases No 967 1,411 -
----------------------------------------------------------------------------
Total 49,806 86,797 -
----------------------------------------------------------------------------


c) Risk management contracts

The Company has no outstanding risk management contracts.

16. COMMITMENTS, CONTINGENCIES AND GUARANTEES

The Company has no contractual obligations that last more than a year other than its office lease agreements which are as follows:



($ 000s)
Lease Obligations
----------------------------------------------------------------------------
Year 1 967
Year 2 874
Year 3 537
Year 4 -
Year 5 -
----------------------------------------------------------------------------
Total 2,378
----------------------------------------------------------------------------


17. SUBSEQUENT EVENTS - DIVIDENDS

Subsequent to December 31, 2010, the Company has declared the following dividends:



Date declared Record date $ per share Date payable
----------------------------------------------------------------------------
January 5, 2011 January 14, 2011 $0.24 January 31, 2011
February 2, 2011 February 15, 2011 $0.24 February 28, 2011
March 2, 2011 March 15, 2011 $0.24 March 31, 2011


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

Contact Information

  • Bonterra Energy Corp.
    George F. Fink
    CEO and Chairman
    (403) 262-5307
    (403) 265-7488 (FAX)
    or
    Bonterra Energy Corp.
    Randy M. Jarock
    President and COO
    (403) 262-5307
    (403) 265-7488 (FAX)
    or
    Bonterra Energy Corp.
    Robb D. Thompson
    Vice President, Finance
    (403) 262-5307
    (403) 265-7488 (FAX)
    or
    Bonterra Energy Corp.
    Kirsten Lankester
    Manager, Investor Relations
    (403) 262-5307
    (403) 265-7488 (FAX)
    info@bonterraenergy.com
    www.bonterraenergy.com