Bonterra Energy Corp.
Annual Report 2008

Plain-text annual report

Suite 901, 1015 – 4th Street SW | Calgary, Alberta T2R 1J4 Annual Report 2008 BONTERRA OIL & GAS 1 Sustainability. Competitive Advantage. 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 F r o n t - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 6 5 3 C P A N T O N E 4 1 0 C Bonterra Oil & Gas Ltd. is a high-yield, dividend paying oil and gas company headquartered in Calgary, Alberta with a proven history of growth and long-term returns for investors. It recently converted to a corporation from an income trust and intends to continue with a cash dividend policy similar to the distribution policy previously followed by the Trust. The monthly dividend amount will continue to be determined by commodity prices and production volumes. Bonterra’s asset base consists of stable, producing properties located mainly in the Pembina field in central Alberta and are characterized by a long reserve life and low risk, predictable returns. Bonterra’s proven track record of success is due to its experienced management team, conservative capital structure and sustainable pace of development, resulting in above-average results and returns for investors. Bonterra’s common shares trade on the Toronto Stock Exchange under the symbol BNE. Notice of Annual Meeting The Annual Meeting of Shareholders will be held on Thursday, May 21, 2009, in the Marquis Room at the Fairmont Palliser, 133 Ninth Avenue SW, Calgary, Alberta at 11:00 AM (Mountain Time). Annual Highlights .....................................................2 Quarterly Highlights ..................................................3 Report to Shareholders ..............................................4 Review of Operations ................................................8 Property Discussions ................................................ 10 Statistical Review ..................................................... 12 BO NTER RA OIL & GAS LTD. 1 Experience. CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG Annual Highlights Annual Highlights Financial ($000, except $ per share/unit) Revenue – realized oil and gas Cash payments per share/unit (1) Cash flow from operations Per Share/Unit Basic Per Share/Unit Fully Diluted Payout Ratio (1) Net Earnings Per Share/Unit Basic Per Share/Unit Fully Diluted Capital Expenditures and Acquisitions Working Capital Deficiency Long-term Debt Shareholders’/Unitholders’ Equity Shares / Units Outstanding Operations Oil and Liquids (barrels per day) Average Price ($ per barrel) Natural Gas (MCF per day) Average Price ($ per MCF) Total BOE per day (2) Reserves Oil and Liquids (barrels in 000s) Proved Developed Producing (Gross) (3) Proved (Gross) Proved plus Probable (Gross) Natural Gas (MCF in 000s) Proved Developed Producing (Gross) Proved (Gross) Proved plus Probable (Gross) Reserve Life Index (4) (oil, liquids and natural gas at 6:1) (years) Proved Developed Producing (Gross) Proved (Gross) Proved plus Probable (Gross) Reserves per Weighted Average Outstanding Share / Unit (BOE) Proved Developed Producing (Gross) Proved (Gross) Proved plus Probable (Gross) 2008 2007 2006 121,730 3.12 69,570 4.07 4.06 77% 55,426 3.25 3.23 45,407 23,878 79,910 56,777 17,258 3,073 87.54 7,637 8.21 4,346 15,534 17,991 22,867 32,108 36,571 50,245 12.5 14.4 18.7 1.22 1.41 1.83 96,431 2.64 51,433 3.04 3.04 87% 30,350 1.79 1.79 19,300 58,766 - 44,376 16,928 3,113 70.31 6,627 6.75 4,218 14,468 17,472 21,910 19,863 24,125 32,465 11.3 13.7 17.4 1.05 1.27 1.62 88,734 2.82 51,944 3.10 3.08 91% 37,250 2.23 2.21 38,348 50,187 - 53,359 16,875 3,040 64.69 6,014 7.55 4,042 13,688 16,758 21,526 17,011 22,562 29,700 11.0 13.6 17.6 0.98 1.22 1.57 2 BON TERRA OIL & GAS LTD. 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 B a c k - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 4 1 0 C P A N T O N E 6 5 3 C CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 B a c k - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 4 1 0 C P A N T O N E 6 5 3 C Quarterly Highlights 2008 Financial ($000, except $ per share/unit) Revenue – realized oil and gas sales Cash flow from operations Per Share/Unit Basic Per Share/Unit Fully Diluted Cash payments per share/unit (1) Payout Ratio (1) Net Earnings Per Share/Unit Basic Per Share/Unit Fully Diluted Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Long-term debt Shareholders’/Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Total BOE per day 4th 3rd 2nd 1st 22,613 10,336 0.59 0.59 0.62 105% 10,585 0.62 0.62 30,405 265,301 23,878 79,910 56,777 3,105 8,892 4,587 34,226 22,492 1.31 1.30 0.96 73% 21,125 1.23 1.22 6,038 150,120 47,499 - 57,623 3,013 7,233 4,219 34,398 20,530 1.21 1.20 0.84 69% 12,912 0.76 0.75 2,543 153,247 57,148 - 46,612 3,024 7,272 4,236 30,493 16,212 0.96 0.96 0.70 73% 10,804 0.64 0.64 6,421 150,169 57,810 - 48,136 3,153 7,139 4,343 (1) Cash payments per share/unit are based on payments made in respect of production months within the quarter. (2) 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 convervsion 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. (3) Gross reserves relate to the Company’s ownership of reserves before deducting any royalties. (4) The reserve life index is calculated by dividing the reserves (BOE) by the annualized fourth quarter average production rate (2008 - 4,587 BOE per day; 2007 - 4,295 BOE per day; 2006 - 4,119). BO NTER RA OI L & GAS LTD. 3 CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG Report to Shareholders Bonterra Oil & Gas Ltd. (“Bonterra” or the “Company”) is pleased to report its operational, financial and reorganization results for the year ending December 31, 2008. In assessing the year, the Company realized many positive events and results and a few negative results that developed during the last four months of the year. These are generally attributable to severe changes in the world economy; events that cannot be influenced by individual companies. Highlights • Net earnings increased substantially to $55.4 million or $3.25 per share as compared to $30.4 million or $1.79 per unit in 2007; • Cash flow from operations totaled $69.6 million ($4.07 per share) in 2008, an increase of 35 percent year over year; • Cash payment per share/unit to investors totaled $3.12, a substantial increase from the 2007 level of $2.64; • The payout ratio of cash flow was 77 percent, within the Company’s annual target of 75 to 80 percent and a decrease from the 2007 level of 87 percent; • Production increased to an all time high of 4,346 barrels of oil equivalent (BOE) per day as a result of the Company’s internal development program and an acquisition during the year. Fourth quarter production totaled 4,587 BOE per day, an increase of nine percent over the same period last year and the 2008 exit rate was 4,950 BOE per day; • Reserves increased to 24.1 million BOE and 31.2 million BOE on a proved and a proved plus probable (P+P) basis, respectively. This represents an increase of 12.1 percent to the Company’s proved reserves and a 14.4 percent increase to proved plus probable reserves; • Reserves per share on a P+P basis increased 13.0 percent to 1.83 BOE per share; • Bonterra’s finding and development costs (F&D costs) including acquisitions in 2008 continue to be among the lowest in the Canadian oil and gas industry. F&D three-year average costs were $12.30 per boe on a proved basis and $9.45 per BOE on a P+P basis compared with the previous three year average (2005-2007) of $14.37 per boe on a proved basis and $11.07 per boe on a P+P basis. New Corporate Structure Bonterra’s most notable achievement during the year was the successful conversion to a corporation from an income trust in November, 2008. The conversion provides investors with enhanced certainty in regard to Bonterra’s ability to remain a high-income generating investment while negating the overhang associated with the Canadian federal government’s legislation to tax trusts beginning in 2011. Cash Dividends/ Distributions to Investors ($ per unit/share) 90% 87% 91% 87% 100 77% 5 4 3 2 1 0 2004* 2005* 2006 2007 2008 Cash flow from operations Dividends/ distributions Payout ratio * previously funds flow from operations Reserves per Share/Unit (BOE) 2.0 1.5 1.0 0.5 0.0 2004 2005 2006 2007 2008 80 60 40 20 0.0 Cash Flow Growth ($ thousands) 80,000 60,000 40,000 20,000 0 2004* 2005* 2006 2007 2008 * previously funds flow from operations 4 BON TERRA OIL & GAS LTD. 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 F r o n t - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 6 5 3 C P A N T O N E 4 1 0 C CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY B C X Z CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG C 0 1 4 E N O T N A P C 3 5 6 E N O T N A P k c a l B w o l l e Y a t n e g a M n a y C s e r i h k o o B _ F D P _ g o d n u S i r e k - - t n o r F 1 8 0 : 7 2 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S y g r e n E a r r e t n o B _ 5 8 4 0 2 0 9 2 Select benefits of the new corporate structure include: • The ability to continue to provide income oriented investors with a substantial cash yield. Bonterra intends to continue with a cash dividend policy similar to that followed by the Trust; • Substantial tax pools of approximately $465 million which will currently allow Bonterra to extend its taxable horizon beyond 2018, subject to commodity prices; • Higher after-tax earnings for investors as dividends are taxed at lower rates than distributions; • Removal of the growth limitations which currently exists under the “normal growth” guidelines; and • The flexibility to increase capital investment over the next several years with a view to providing enhanced returns to investors. Maximizing Investor Returns in an Uncertain Environment As a corporation, Bonterra is well-positioned to be valued as a growth-oriented, high-dividend paying corporation with a proven history of growth and long-term returns for investors. It is a long-term focus that has defined Bonterra’s ongoing business strategy. Bonterra has continued to focus on paying dividends to its investors, maintaining a strong balance sheet and exhibiting spending discipline across all business cycles while the efficient management of its high-quality, low-risk asset base provides sustainability to the Company. With this approach, Bonterra has been successful in offering above average results and returns to its investors. During the majority of 2008, the energy industry continued to operate within a high commodity price environment. However, during the last four months of 2008, the worldwide economic downturn considerably impacted crude oil and natural gas prices with substantial declines throughout the third and fourth quarters of the year. As a result, Bonterra’s share price experienced a significant devaluation, a common occurrence for share prices for all publicly traded companies. Additionally, the low commodity prices made it necessary to substantially reduce Bonterra’s monthly distribution/dividends. As always, the Company still maintains that the best assessment for an entity is its return to investors. On a one-year basis, Bonterra’s total return to shareholders in 2008 was -11 percent. This was a disappointment as 2008 represents the only year in which a negative return was recorded since inception in 1998. However, this does compare well to both its peers and the major indices. As well, for long-term holders of the Company, Bonterra has continued to outperform both over longer periods of time. Preserving Financial Strength A conservative approach to the Company’s capital structure has been a key factor in building financial strength and flexibility. A keen focus is placed on managing operating and administrative costs to maximize returns and position the Company for future growth. The Company ended 2008 with a bank debt to cash flow ratio of 2.25 times (based on bank debt of $93.2 million and annualized 2008 fourth quarter cash flow from operations). This is substantially higher than usual, even though it is in a range that is normal among its peers at the present time. The main reason for the higher debt level is that Production per Share/Unit (BOE) Bonterra vs. the Indices 0.10 0.08 0.06 0.04 0.02 0.00 2004 2005 2006 2007 2008 $250 $200 $150 $100 2003 2004 2005 2006 2007 2008 BNE TSX Composite Index TSX Energy Index BO NTER RA OI L & GAS LTD. 5 when the company announced its reorganization and acquisition, it had various types of options outstanding that were in the money for approximately $35 million. At closing of the reorganization on November 12, 2008, the world economy had changed substantially, resulting in a large reduction in share prices. As a result, the majority of the outstanding Bonterra options were not exercised. As well, the Company experienced a decrease in cash flow due to the significant drop in commodity prices during the latter half of the year. Although the bank debt level is still very manageable, Bonterra is focusing on attempting to reduce the bank debt to cash flow ratio from anticipated increases in production levels and future commodity prices or by issuing additional equity. This should allow the Company to fund its upcoming capital development program and take advantage of any acquisition opportunities as they become available. Organic Growth Bonterra’s strategic capital development program is designed to maximize asset development through infill drilling, workovers and field optimization strategies. In 2008, Bonterra spent approximately $45.4 million, including acquisitions, on its capital development program, compared to $19.3 million the previous year. The capital development program was successful in fully replacing 2008 annual production and substantially increasing overall reserves and daily production. Key attributes of the 2008 program included: • The continued success of its Pembina Cardium infill drilling program and successful expansion of its Edmonton shallow gas play; • Economic development of the Upper and Lower Shaunavon formation in southwest Saskatchewan; and • Continued improvement throughout all aspects of the Company’s operations. As a result of the Company’s efficient use of capital and disciplined operations focus, Bonterra has been able to further increase its reserve life index to approximately 14.4 and 18.7 years on a total proved and P+P basis, respectively, from 13.7 and 17.4 years in 2007. To ensure sustainability, Bonterra continues to look at developing new long-term and low-risk opportunities. The Company has successfully drilled, completed and placed on production its first operated Cardium well using horizontal, multi-stage frac technology. This well is still under evaluation but if successful, the Company intends to continue to pursue additional opportunities in 2009. With low commodity prices and uncertainty in the industry, Bonterra has been able to acquire significant additional lands in this play at low costs. 2009 Capital Spending Bonterra is planning to carry out a conservative capital development program in 2009. With lower commodity prices and continuing global economic uncertainty, the Company intends to remain focused on its core business strategies. Bonterra currently has plans to spend approximately $15 million on its 2009 capital development program. The majority of 2009 drilling is anticipated to occur during the second half of the year due in part to surface land negotiations but mainly due to the Company’s determination to wait for the Alberta provincial government to disclose its incentive programs and potential modifications to its high royalty rates that currently make the province uncompetitive for certain types of wells. Bonterra has a drilling inventory in excess of ten years with a wide range of opportunities located in all As a result of the Company’s efficient use of capital and disciplined operations focus, Bonterra has been able to further increase its reserve life index to approximately 14.4 and 18.7 years on a total proved and P+P basis, respectively, from 13.7 and 17.4 years in 2007. 20 15 10 5 0 Reserves Life Index (Years) 2004 2005 2006 2007 2008 * Proved plus Probable basis 6 B ON TERRA OIL & GAS LTD. CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY B C X Z CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG C 3 5 6 E N O T N A P C 0 1 4 E N O T N A P k c a l B w o l l e Y a t n e g a M n a y C s e r i h k o o B _ F D P _ g o d n u S i r e k - - k c a B 1 8 0 : 7 2 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S y g r e n E a r r e t n o B _ 5 8 4 0 2 0 9 2 Bonterra is committed to being successful in 2009 by maintaining a consistent and disciplined approach. The Company will; • Maintain a long-term focus; • Continue to concentrate on finding additional operational efficiencies by taking advantage of low cost optimization and development opportunities in all its core areas; • Take advantage of opportunities that are available in a low price environment including lower land costs, lower project costs and acquisition opportunities; • Maintain a conservative capital structure. Taking this approach will allow Bonterra to maintain its strong dividend policy and ensure the long-term sustainability of its business into the future. Acknowledgements The Board of Directors and management wish to thank all shareholders for their continued support during these trying times and its dedicated staff for their positive efforts and contributions this past year. George F. Fink Chief Executive Officer and Director Randy M. Jarock President and Chief Operating Officer three western provinces. This provides the Company with a high degree of flexibility in executing its 2009 program as Bonterra can respond and revise plans if changes to commodity prices, costs and royalties occur. Value-Adding Acquisitions Bonterra’s ongoing business strategy remains focused on the development of its long-life, high quality reserves to maximize returns to investors. In addition, Bonterra has sought out value adding acquisitions to further grow its asset base. During 2008, the Company acquired properties in northeast British Columbia through the closing of a corporate transaction in which Bonterra acquired Silverwing Energy Inc. Production from this area is approximately 650 BOE per day. In addition, Bonterra also received 10,000 net acres of undeveloped land in British Columbia with the right to earn an additional 38,000 acres of non-producing lands in Alberta providing the Company with significant potential for further development. By year-end, Bonterra had successfully integrated the properties into its operations, increased production through drilling and identified additional optimization opportunities to further increase cash flow. Outlook The year 2009 brings new challenges with lower commodity prices, the worldwide economic problems and credit crisis. It is impossible to predict when the economy and commodity prices may experience a turnaround and the Company’s expectation is that these unmanageable influences will continue to have an impact on Bonterra’s results. However from an operational and financial perspective, Bonterra will continue to prosper. The Company has many competitive advantages that will allow it to continue to pay a high dividend; so that all shareholders will continue to be rewarded on a monthly basis. These include: • a large drilling inventory; • premium quality production which generally results in higher netbacks and cashflow; • • large tax pools that should assist in reducing taxes for many years into the future; and experienced, loyal and capable employees dedicated to maximizing value for shareholders. In addition, Bonterra is continually seeking new ways to strengthen its financial position including cost-reduction initiatives, project reviews throughout the year and exploring and implementing operational efficiencies across the company. BO NTER RA OI L & G AS LTD. 7 CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY B C X Z CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG C 0 1 4 E N O T N A P C 3 5 6 E N O T N A P k c a l B w o l l e Y a t n e g a M n a y C s e r i h k o o B _ F D P _ g o d n u S i r e k - - t n o r F 1 8 0 : 7 2 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S y g r e n E a r r e t n o B _ 5 8 4 0 2 0 9 2 Operations Operations Overview In 2008, Bonterra’s team executed a capital development program which continued to build upon its strong track record of delivering sustainable growth. Operational focus and discipline have again led to reserves growth on a per share basis. The Company’s high-quality asset base consists of concentrated, stable and under-developed properties with large amounts of remaining oil in place, a long reserve life and low-risk, predictable returns. In addition to this strong asset base, which contains over 10 years of identified drilling opportunities; our highly skilled and experienced team is dedicated to maximizing returns from existing properties and adding value and sustainability through the development of new long-term growth opportunities. Production Bonterra’s production volumes averaged 4,346 BOE per day in 2008. The majority of the 2008 capital development program was executed in the fourth quarter of the year and as such production came on late in the year and did not contribute significantly to the year’s average production rate. The corporate acquisition of Silverwing Energy Inc. (Silverwing) was completed late in the year and also had little impact on the annual average. However, the Company’s exit rate for the year was a strong 4,950 BOE per day and Bonterra expects production levels to increase on a total and per share basis in 2009 based on current development plans. Capital Expenditures Our team’s ability to optimize recovery from our high-quality asset base is paramount to the Company’s success. In 2008, approximately $30.1 million was spent on the capital development program which recorded a drilling success rate of 100 percent. The 2008 program consisted of drilling 44 gross (30.9 net) oil and natural gas wells. At year-end, all but four oil wells were on production. These wells have subsequently been placed on production at a capital cost of less than $1 million being spent in 2009. Proved Plus Probable Reserves (MBOE) 40000 30000 20000 10000 0 2004 2005 2006 2007 2008 Average Daily Production (BOE per day) 5000 4000 3000 2000 1000 0 2004 2005 2006 2007 2008 NORTHEAST BC Alberta Fort St. John Saskatchewan Manitoba Quebec British Columbia PEMBINA Calgary SHAUNAVON Regina Ontario 8 B ON TERRA OIL & GAS LTD. CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY B C X Z CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG C 0 1 4 E N O T N A P C 3 5 6 E N O T N A P k c a l B w o l l e Y a t n e g a M n a y C s e r i h k o o B _ F D P _ g o d n u S i r e k - - t n o r F 1 8 0 : 7 2 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S y g r e n E a r r e t n o B _ 5 8 4 0 2 0 9 2 A key component of our operations strategy includes acquiring land for long-term growth projects at low prices in core areas. In 2008, Bonterra purchased 4,800 acres (3,520 net) of undeveloped land for approximately $376,440 or approximately $107 per acre. Bonterra’s undeveloped land base now totals 71,232 gross acres (29,798 net acres). These lands represent both future development opportunities for the company as well as opportunities for farmout transactions. In 2008, Bonterra completed three farmout transactions totaling 1,136 net acres in the Shaunavon area of Saskatchewan resulting in three lower Shaunavon multi-stage frac horizontal wells and one vertical upper Shaunavon oil well drilled in 2008. The Company also completed three farm-in transactions totaling 600 net acres during the year. These transactions resulted in one gross (0.25 net) operated multi-stage frac horizontal well being drilled in the Pembina field. In addition, the Company has commitments for the drilling of one additional well in 2009. For 2009, the capital development program will sustain our focus on the continued development of Bonterra’s light oil properties in the Pembina field as well as in the Shaunavon area of Saskatchewan and our new core area in northeast British Columbia. Bonterra currently has plans to drill approximately 30 gross (18 net) oil and gas wells with an estimated capital development budget of $15 million. This plan includes 18 gross (14 net) Cardium vertical oil wells, two gross (0.65 net) Cardium horizontal oil wells and the balance of the drilling to consist of wells in both British Columbia and Saskatchewan. The majority of the program is expected to be executed in the latter half of 2009 due to both land conditions and the possibility that the Alberta government may make potential modifications to its high royalty rates that make Alberta uncompetitive for drilling certain types of wells. Operational Excellence Bonterra’s operating strategy is aimed at enhancing cash flow over the long-term to create sustainability in the dividends paid to investors. Bonterra’s commitment to operational, technical and administrative excellence helps to reduce development risks and lower operating costs, thus allowing the Company to maximize netbacks. Bonterra operates approximately 84 percent of its total production, thereby allowing the Company to better manage costs and efficiently invest capital. Bonterra is able to strategically schedule development programs, well workovers and facility upgrades to control the nature, pace and risk level of development. As an operator, Bonterra is able to balance production and recovery of reserves with a risk profile suitable to a high-income generating company. Finding, Development and Acquisition Costs (FD&A) Results from Bonterra’s ongoing operations, active capital development program and the Company’s drilling program continue to meet or exceed expectations resulting in increases in the third party engineering evaluation’s estimated recoverable reserves from existing wells and as well from future development. Continued low decline rates have also resulted in increased reserves due to technical revisions. Both these factors contributed to an overall FD&A cost in 2008 of $7.47 per BOE on a proved plus probable basis. Recycle Ratio A recycle ratio is an indication of the value created for each dollar a company invests. Bonterra has a strong track record of creating value through its capital expenditures and this year was not an exception. Indeed, the Company is proud to report that the proved plus probable recycle ratio in 2008 was 6.1 times. 2008 Reserves by Commodity Netbacks ($ per BOE) 4% 27% 69% Light & Medium Oil Natural Gas Natural Gas Liquids 80 70 60 50 40 30 20 10 0 2004* 2005* 2006 2007 2008 Cash Netbacks Royalties Field Operating G&A Interest & Taxes 30 20 10 0 Finding, Development and Acquisition Costs ($ per BOE) 2006 2007 2008 2007 3-year Average 2008 3-year Average * based on proved plus probable reserves * After realized gain (loss) on risk management contracts Proved Proved Plus Probable BO NTER RA OIL & GAS LTD. 9 Alberta Fort St. John Saskatchewan Manitoba Quebec NORTHEAST BC British Columbia PEMBINA Calgary SHAUNAVON Regina Ontario CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY B C X Z CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG C 3 5 6 E N O T N A P C 0 1 4 E N O T N A P k c a l B w o l l e Y a t n e g a M n a y C s e r i h k o o B _ F D P _ g o d n u S i r e k - - k c a B 1 8 0 : 7 2 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S y g r e n E a r r e t n o B _ 5 8 4 0 2 0 9 2 10 BONTERRA OIL & GAS LTD.Key PropertiesPembinaPembina is Bonterra’s main property. It is the Company’s largest producing asset and represents 83.7 percent of total reserves. Production in Pembina is primarily oil and solution gas from the Cardium formation and to a lesser extent natural gas from the Edmonton Sands with the remainder coming from the Belly River, Paskapoo and the Ardley Coals. The Pembina Cardium field is the largest conventional oil field in Canada with estimated original oil in place of 7.8 billion barrels with an average recovery to date of just 17 percent. This mature field has proved to be a significant area for multi-zone oil and natural gas exploration with predictable results. Bonterra is the third largest Cardium reserve holder in the area after acquiring the properties throughout the 1990s. After a period of lower commodity prices and beginning in 2003, Bonterra pursued a targeted infill drilling program, low-cost optimization, recompletions and key acquisitions which have resulted in not only increased reserves and maximized income from the properties but a reduction of the base decline. This clearly illustrates Bonterra’s ability to provide sustainability and performance for shareholders. Bonterra has significant potential upside in the Pembina Cardium field which could potentially increase recovery of the original oil in place. New frac technology, re-fracs and frac optimization has served to enhance recovery in older wells. As well, Bonterra drilled and completed its first operated Cardium horizontal multi-stage frac well during 2008. The well was placed on production in 2009 and is currently being evaluated.In addition, the implementation of two CO2 pilot projects by other industry operators in the areas points to the vast upside of these enhanced oil recovery projects in the Pembina field. Details of the pilot projects are proprietary, however public information released thus far has been very encouraging. Environmental concerns over CO2 emissions, location of a low cost source of CO2, development of infrastructure and supportive environmental regulations would be required to improve feasibility. Bonterra intends to continue to investigate its potential as a long-term business strategy. A significant portion of Bonterra’s Pembina production in natural gas is derived primarily from the shallow Edmonton sands that consist of a large number of varied quality reservoir sands. These numerous channel sands are distributed throughout the Company’s lands and multiple sands can be completed in a single well bore. These wells are drilled to depths shallower than 750 meters and make use of existing and owned infrastructure that reduced development and operating costs. Wells from the Edmonton sands generally have lower productivity that benefit from the new royalty framework in Alberta. 2008 Pembina Production Crude Oil and Liquids (Bbls per day) Pembina oil (operated) 2,179Pembina oil (non-operated) 341Current average daily production 2,520Natural Gas (BOE per day)Solution gas 511Shallow gas 544Coalbed methane 8Current average daily production 1,063Pembina CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY B C X Z CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG C 3 5 6 E N O T N A P C 0 1 4 E N O T N A P k c a l B w o l l e Y a t n e g a M n a y C s e r i h k o o B _ F D P _ g o d n u S i r e k - - k c a B 1 8 0 : 7 2 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S y g r e n E a r r e t n o B _ 5 8 4 0 2 0 9 2 BONTERRA OIL & GAS LTD. 11Shaunavon Bonterra’s Shaunavon properties are located in the Whitemud and Chambery fields and produce medium density crude oil from the lower Shaunavon formation. A portion of the property is being produced under waterflood with the majority of the properties still on primary production. The wells in this area are generally long-life with stable, low-decline production profiles and Bonterra continues to evaluate whether additional water flooding or optimization programs should be initiated to further increase profitability from the existing properties. In 2008, the company drilled three gross (2.9 net) successful upper Shaunavon oil wells which were placed on production in 2009. Bonterra has several follow-up locations identified that will be drilled once commodity prices improve. Bonterra’s lands in the area are located on the edge of the rewarding lower Shaunavon resource play where there has been significant industry activity in 2008. A farmout of expiring lands resulted in three lower Shaunavon wells and one vertical upper Shaunavon well being drilled that performed to the Company’s expectation. With the information obtained from the evaluation of the farmout wells and other industry activity in the area, Bonterra is evaluating future development strategies for the lower Shaunavon. Bonterra has identified potential drilling opportunities that can take advantage of Saskatchewan’s favourable royalty regime for horizontal wells once commodity prices improve. Bonterra’s 2009 plans for further development in the Shaunavon area will depend largely on commodity prices as Saskatchewan does have a relatively more favourable royalty regime for certain types of wells.Northeast British Columbia The corporate acquisition of Silverwing in late 2008 created a new core area in the Prespatou area of northeast British Columbia with significant potential for further development. The properties consist almost entirely of natural gas and associated natural gas liquids with production of approximately 650 BOE per day.The acquisition of this property occurred late in the year and the Company focused on integrating the properties into its asset base. However, Bonterra was still able to increase production in the area by participating in the drilling of three gross (0.675 net) gas wells in December of 2008. Bonterra is currently conducting a thorough review of the property to maximize cashflow by reducing operating costs and optimizing well productivity and throughput. The Company is re-evaluating the geology of the entire area to access potential opportunities and identify new ones. The magnitude of 2009 development plans will depend on the outcome of the evaluations and commodity prices. ShaunavonNortheast British Columbia CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY B C X Z CMY B 70 slurB X Z CMY B C M Y X Z CMY C 70 CM CY X Z CMY B C M Y X Z CMY M 70 slurC X Z CMY B C M Y X Z CMY Y 70 X 70 X Z CMY B C M Y X Z CMY B 70 slurM X Z CMY B C M Y X Z CMY C 70 MY CMY X Z CMY B C M Y X Z CMY M 70 slurY X Z CMY Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG C 0 1 4 E N O T N A P C 3 5 6 E N O T N A P k c a l B w o l l e Y a t n e g a M n a y C s e r i h k o o B _ F D P _ g o d n u S i r e k - - t n o r F 1 8 0 : 7 2 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S y g r e n E a r r e t n o B _ 5 8 4 0 2 0 9 2 Statistical Review Reserves Bonterra engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an effective date of December 31, 2008. The reserves are located in the provinces of Alberta, British Columbia (BC) and Saskatchewan. Bonterra’s main oil producing areas are located in the Pembina area of Alberta, northeast BC and the Shaunavon area of Saskatchewan. The gross reserve figures for the following tables represent Bonterra’s ownership interest before royalties and before consideration of the company’s royalty interests. Tables may not add due to rounding. Summary of Oil and Gas Reserves as of December 31, 2008 Reserve Category: Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable Light and Medium Oil Gross (Mbbl) Natural Gas Gross (MMcf) Natural Gas Liquids Gross (Mbbl) 14,650 75 2,258 16,983 4,575 21,559 32,108 870 3,593 36,571 13,675 50,245 884 11 112 1,008 301 1,308 BOE Gross (Mboe) 20,885 232 2,969 24,086 7,155 31,241 Reconciliation of Company Gross Reserves by Principal Product Type as of December 31, 2008 Light and Medium Oil and Natural Gas Liquids Natural Gas BOE Gross Proved Plus Probable (Mbbl) 21,910 337 – 1,716 90 66 – (128) (1,125) Gross Proved (Mmcf) 24,125 1,949 – 5,651 12 6,878 – 751 (2,795) 22,867 36,571 Gross Proved Plus Probable (Mmcf) 32,465 2,516 – 6,824 109 9,946 – 1,180 (2,795) 50,246 Gross Proved (Mboe) 21,493 588 – 2,238 12 1,198 – 148 (1,591) 24,086 Gross Proved Plus Probable (Mboe) 27,321 756 – 2,853 108 1,724 – 69 (1,591) 31,241 Gross Proved (Mbbl) 17,472 263 – 1,296 10 52 – 23 (1,125) 17,991 December 31, 2007 Extension Improved recovery Technical revisions Discoveries Acquisitions Dispositions Economic factors Production December 31, 2008 Summary of Net Present Values of Future Net Revenue as of December 31, 2008 Net Present Values of Future Net Revenue Before Income Taxes Discounted at (% per Year) ($ Millions) Reserve Category: Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable 12 BON TERRA OIL & GAS LTD. 0% 1,004.2 6.5 85.1 1,095.8 460.0 1,555.8 5% 569.2 5.3 64.5 639.1 175.6 814.6 10% 399.5 4.4 49.4 453.4 94.8 548.2 15% 20% 311.2 3.8 38.1 353.1 61.0 414.0 256.7 3.3 29.5 289.5 42.9 332.4 Net Present Values of Future Net Revenue After Income Taxes Discounted at (% per Year) ($ Millions) Reserve Category: Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable 0% 903.7 3.1 49.8 956.6 339.6 1,296.2 5% 541.0 3.6 44.3 588.8 129.5 718.4 10% 389.8 3.6 37.4 430.7 70.9 501.6 15% 20% 307.3 3.4 30.7 341.4 46.6 388.0 255.1 3.1 24.9 283.0 33.6 316.6 Commodity prices used in the above calculations of reserves are as follows: Year 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Alberta Gas Edmonton Reference Price Plantgate (Cdn $ per bbl) (Cdn $ per MCF) Par Price Propane (Cdn $ per bbl) Butane (Cdn $ per bbl) Pentane (Cdn $ per bbl) 65.35 72.78 79.95 86.57 94.97 96.89 98.85 100.84 102.88 104.96 107.08 6.47 7.24 7.56 8.15 9.00 9.21 9.42 9.63 9.85 10.17 10.30 40.70 43.16 47.42 51.34 56.33 57.46 58.62 59.81 61.02 62.25 63.50 51.15 54.25 59.59 64.53 70.79 72.22 73.68 75.16 76.68 78.23 79.81 66.93 74.54 81.88 88.66 97.27 99.23 101.23 103.28 105.36 107.49 109.66 Crude oil, natural gas and liquid prices escalate at two percent per year thereafter The following cautionary statements are specifically required by NI 51-101. 1) It should not be assumed that the estimates of future net revenue presented in the above tables represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. 2) Disclosure provided herein in respect of barrels of oil equivalent (BOE) may be misleading, particularly in used in isolation. A BOE conversion ratio of 6 MCF: 1 BOE has been used in all cases of this disclosure. This BOE conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 3) Estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenues for all properties due to the effects of aggregation. BON TER RA OI L & GAS LTD. 13 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 F r o n t - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 6 5 3 C P A N T O N E 4 1 0 C CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG Production The following table provides a summary of production volumes from the Company’s main producing areas: Pembina area, AB Shaunavon area, SK Northeast BC (1) Other 2,520 313 3 237 3,073 6,376 – 526 735 7,637 2008 Oils and NGLs (Bbls per day) Natural Gas (MCF per day) Oils and NGLs 2007 (Bbls per day) 2,346 310 – 457 3,113 Natural Gas (MCF per day) 5,555 – – 1,072 6,627 (1) The northeast BC properties were acquired in the Silverwing acquisition which closed on November 12, 2008 and thus made little impact on 2008 production volumes. Land Holdings Bonterra’s holding of petroleum and natural gas leases and rights are as follows: Alberta Saskatchewan British Columbia 2008 2007 Gross Acres Net Acres Gross Acres Net Acres 152,917 31,182 73,910 258,009 92,438 28,000 30,373 150,811 133,216 33,778 – 166,994 83,609 30,409 – 114,018 Petroleum and Natural Gas Capital Expenditures The following table summarizes petroleum and natural gas capital expenditures incurred by Bonterra on acquisitions, land, seismic, exploration and development drilling and production facilities for the years ended December 31: Acquisitions Disposals Exploration and development costs Net petroleum and natural gas capital expenditures Drilling History 2008 2007 $ 15,347,000 $ – 30,060,000 18,369,000 (17,664,000) 18,595,000 $ 45,407,000 $ 19,300,001 The following table summarizes the Company’s gross and net drilling activity and success: 2008 Crude oil Natural gas Dry Total Success rate Development Gross 35.0 8.0 – 43.0 100% Net 25.5 5.9 – 30.6 Exploratory Gross 1 – – 1 Net 0.3 – – 0.3 Total Gross 36.0 8.0 – 44.0 Net 25.8 5.1 – 30.9 100% 100% 100% 100% 100% 14 BON TERRA OIL & GAS LTD. CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 B a c k - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 4 1 0 C P A N T O N E 6 5 3 C 2007 Crude oil Natural gas Dry Total Success rate 2006 Crude oil Natural gas Dry Total Success rate Tax Pools Development Gross 22.0 2.0 – 24.0 100% Development Gross 43.0 9.0 9.0 61.0 85% Net 15.3 0.7 – 16.0 100% Net 30.3 6.5 8.8 45.6 81% Exploratory Total Gross Net Gross – – – – – – – – – – 22.0 2.0 – 24.0 Net 15.3 0.7 – 16.0 100% 100% Exploratory Total Gross Net Gross – – – – – – – – – – 43.0 9.0 9.0 61.0 85% Net 30.3 6.5 8.8 45.6 81% 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: Rate of Utilization ($000) Undepreciated capital costs Eligible capital expenditures Share issue costs Canadian oil and gas property expenditures Canadian development expenditures Canadian exploration expenditures SR&ED expenditures Income tax losses carried forward (1) % Amount 20-100 $ 7 20 10 30 100 100 100 $ 23,696 1,870 4,581 25,072 50,743 10,530 80,357 271,029 467,878 (1) Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000, 2027 - $116,787,000, 2028 - $40,750,000. Share/Trust Unit Trading Statistics (based on daily closing price) High Low Close Daily Average Trading Volume $ $ $ 2008 39.50 $ 15.50 $ 17.27 $ 23,031 2007 30.80 22.19 23.99 17,867 BON TER RA OI L & GAS LTD. 15 CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 B a c k - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 4 1 0 C P A N T O N E 6 5 3 C 1 B ON TERRA OIL & GAS LTD. Financial Report 2008 w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 1 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S a r r e t n o B _ 2 9 4 0 2 0 9 2 G A n e n i h c s a m k c u r D r e g r e b l e d i e H 7 0 0 2 © ) f d p ( e 0 . 3 o c p i D 5 0 1 / 2 0 1 t a m r o F i S G 4 t c e n i r P B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M C B Y M C 0 7 M Y M C B Y M C Y M C B Y M C 0 7 C Y M C B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M 2 9 0 2 0 4 9 2 _ B o n t e r r a S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 1 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B C M Y C 7 0 C M Y B C M Y C M Y B C M Y M 7 0 C M Y B C M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B P r i n e c t 4 G S i F o r m a t 1 0 2 / 1 0 5 D i p c o 3 . 0 e ( p d f ) © 2 0 0 7 H e i d e l b e r g e r D r u c k m a s c h i n e n A G 2 BONTERRA OIL & GAS LTD.Bonterra Oil & Gas Ltd. is a high-yield, dividend paying oil and gas company headquartered in Calgary, Alberta with a proven history of growth and long term returns for investors. It recently converted to a corporation from an income trust and intends to continue with a cash dividend policy similar to the distribution policy previously followed by the trust. The monthly dividend amount will continue to be determined by commodity prices and production volumes.Bonterra’s asset base consists of stable, producing properties located mainly in the Pembina field in central Alberta and are characterized by a long reserve life and low risk, predictable returns. Bonterra’s proven track record of success is due to its experienced management team, conservative capital structure and sustainable pace of development, resulting in above-average results and returns for investors.Management’s Discussion & Analysis .....................1Consolidated Financial Statements ........................21Notes to the Consolidated Financial Statements ..26Bonterra’s common shares trade on the Toronto Stock Exchange under the symbol BNE. of $3,085,000. as follows: Contract Obligations ($000) Office leases (1) c) Risk management contracts The Company currently has no outstanding risk management contracts: As of December 31, 2007, the fair value of the outstanding commodity risk management contracts was a net liability 17. COMMITMENTS, CONTINGENCIES AND GUArANTEES The Company has no contractual obligations that last more than a year other than its office lease agreements which are Total Less than 1 year 1 – 3 years $ 2,907 $ 589 $ 1,238 $ 4 – 5 years 1,080 (1) Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds received on the sublease have not been offset against the contractual liability. 18. SUBSEQUENT EvENTS - DIvIDENDS Subsequent to December 31, 2008, the Company has declared the following dividends: Date declared January 6, 2009 February 9, 2009 March 5, 2009 Record date January 15, 2009 February 18, 2009 March 16, 2009 $ per share $0.16 $0.12 $0.12 Date payable January 30, 2009 February 27, 2009 March 31, 2009 G A n e n i h c s a m k c u r D r e g r e b l e d i e H 7 0 0 2 © ) f d p ( e 0 . 3 o c p i D 5 0 1 / 2 0 1 t a m r o F i S G 4 t c e n i r P B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M C B Y M C 0 7 M Y M C B Y M C Y M C B Y M C 0 7 C Y M C B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M 40 BONTE R RA OIL & GAS LTD. w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 1 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S a r r e t n o B _ 2 9 4 0 2 0 9 2 BONTERRA OIL & GAS LTD. 1MANAGEMENT’S DISCUSSION AND ANALYSISThis report dated March 18, 2009 is a review of the operations, current financial position, and outlook for Bonterra Oil & Gas Ltd. (“Bonterra” or the “Company”) and should be read in conjunction with the audited financial statements for the year ended December 31, 2008, together with the notes related thereto.FOrwArD-LOOkING INFOrMATIONCertain statements contained in this Management’s Discussion and Analysis (MD&A) 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 MD&A 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. ANNUAL COMpArISONS Financial ($000, except $ per unit) Revenue – realized oil and gas Cash flow from operations Per Share/Unit Basic Per Share/Unit Fully Diluted Cash payments per share/unit (1) Payout Ratio (1) Net Earnings Per Share/Unit Basic Per Share/Unit Fully Diluted Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Long-term Debt Shareholders’/Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Total BOE per day QUArTErLY COMpArISONS Financial ($000, except $ per unit) Revenue – realized oil and gas sales Cash flow from operations Per Share/Unit Basic Per Share/Unit Fully Diluted Cash payments per share/unit (1) Payout Ratio (1) Net Earnings Per Share/Unit Basic Per Share/Unit Fully Diluted Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Long-term debt Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Total BOE per day 2008 2007 2006 • Investments are generally only with companies that have common management with the Company. • Agreements for product sales are primarily on 30 day renewal terms; and 121,730 69,570 4.07 4.06 3.12 77% 55,426 3.25 3.23 45,407 265,301 23,878 79,910 56,777 3,073 7,637 4,346 96,431 51,433 3.04 3.04 2.64 87% 30,350 1.79 1.79 19,300 142,326 58,766 – 44,376 3,113 6,627 4,218 88,734 51,944 3.10 3.08 2.82 91% 37,250 2.23 2.21 38,348 134,942 50,187 – 53,359 3,040 6,014 4,042 4th 3rd 2nd 1st Liquidity risk 2008 22,613 10,336 0.59 0.59 0.62 105% 10,585 0.62 0.62 30,405 265,301 23,878 79,910 56,777 3,105 8,892 4,587 34,226 22,492 1.31 1.30 0.96 73% 21,125 1.23 1.22 6,038 150,120 47,499 – 57,623 3,013 7,233 4,219 34,398 20,530 1.21 1.20 0.84 69% 12,912 0.76 0.75 2,543 153,247 57,148 – 46,612 3,024 7,272 4,236 30,493 16,212 0.96 0.96 0.70 73% 10,804 0.64 0.64 6,421 150,169 57,810 – 48,136 3,153 7,139 4,343 Of the accounts receivable balance of December 31, 2008 ($11,753,000) and December 31, 2007 ($10,575,000) over 82 (2007 – 90) percent relates to product sales with international oil and gas companies, tax receivables from the Canadian Government or risk contract payments from the Company’s principal banker. The Company assesses quarterly, if there has been any impairment of the financial assets of the Company. During the year ended December 31, 2008, there was no impairment provision required on any of the financial assets of the Company due to historical success of collecting receivables. The Company does have a credit risk exposure as the majority of the Company’s accounts receivable are with counterparties having similar characteristics. However, payments from the Company’s largest accounts receivable counter parties 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, 2008 approximately $99,000 or 0.8 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 net paying 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, 2008 is $85,000. There were no accounts written off during the year. The carrying value of accounts receivable approximates their fair value due to the relatively short periods to maturity on this instrument. The maximum exposure to credit risk is represented by the carrying amount on the balance sheet. There are no material financial assets that the Company considers past due. Liquidity risk includes the risk that, as a result of 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: Accounts payable and accrued liabilities ($000) Due to related party Short-term bank debt Long-term bank debt Office leases Total Recognized on Financial Statements Less Than One Year 1-3 Years 4-5 Years Payments Due By Period Yes – Liability Yes – Liability Yes – Liability Yes – Liability No 23,888 6,000 13,325 – 589 43,802 – – – 79,910 1,238 81,148 – – – – 1,080 1,080 2 B ON TERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 39 M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B C M Y C 7 0 C M Y B C M Y C M Y B C M Y M 7 0 C M Y B C M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B P r i n e c t 4 G S i F o r m a t 1 0 2 / 1 0 5 D i p c o 3 . 0 e ( p d f ) © 2 0 0 7 H e i d e l b e r g e r D r u c k m a s c h i n e n A G 2 9 0 2 0 4 9 2 _ B o n t e r r a S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 1 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 1 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S a r r e t n o B _ 2 9 4 0 2 0 9 2 G A n e n i h c s a m k c u r D r e g r e b l e d i e H 7 0 0 2 © ) f d p ( e 0 . 3 o c p i D 5 0 1 / 2 0 1 t a m r o F i S G 4 t c e n i r P B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M C B Y M C 0 7 M Y M C B Y M C Y M C B Y M C 0 7 C Y M C B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M b) Risks and mitigations Commodity price risk 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. 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, recently 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. Sensitivity Analysis Commodity prices have fluctuated significantly over the recent past. The following table updates the cash flow sensitivity for movements in the commodity prices of $1 U.S. per barrel WTI for crude oil, $0.10 per MCF AECO for natural gas and $0.01 fluctuation in exchange rates. ($000) U.S. $1.00 per barrel Canadian $0.10 per MCF Change of Canadian $0.01/U.S. $ exchange rate Interest rate risk Cash Flow 870,000 289,000 593,000 $ $ $ 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 bank borrowings which have a variable interest rate which gives rise to a cash flow interest rate risk. The Company’s debt consists of an $80,000,000 revolving operating line, $20,000,000 demand operating line and $6,000,000 due to the Company’s CEO and major shareholder. The borrowings under these facilities are at bank prime plus or minor various percentages as well as by means of banker acceptances (BA’s). 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 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. No income tax effect has been calculated as the Company has sufficient tax pools such that it will not be taxable in the near future. A one percent increase (decrease) in the Canadian prime rate would decrease cash flow by $992,000 (increase by six months. Sensitivity analysis $992,000). 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, recently 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 sheet. To help mitigate this 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 • The Company only enters into material agreements with credit worthy counterparties. These include major oil and gas companies or major Canadian chartered banks; Financial ($000, except $ per unit) Revenue – realized oil and gas sales Cash flow from operations Per Unit Basic Per Unit Fully Diluted Cash payments per share/unit (1) Payout Ratio (1) Net Earnings Per Unit Basic Per Unit Fully Diluted Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Long-term debt Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Total BOE per day 4th 3rd 2nd 1st 2007 26,573 13,369 0.79 0.79 0.66 84% 7,920 0.47 0.47 7,213 142,329 58,766 – 44,218 3,098 7,176 4,295 23,794 11,886 0.70 0.70 0.66 94% 9,086 0.54 0.53 2,763 138,140 50,041 – 50,820 3,054 6,196 4,086 23,462 13,413 0.79 0.79 0.66 84% 4,440 0.26 0.26 1,699 139,432 49,595 – 51,920 3,074 6,663 4,184 22,602 12,765 0.76 0.76 0.66 87% 8,904 0.53 0.53 7,625 140,926 49,288 – 57,646 3,227 6,470 4,305 (1) Cash payments per share/unit are based on payments made in respect of production months within the quarter. Disclosure Controls and procedures Disclosure controls and procedures (DC&P) are defined under National Instrument 52-109 – Certification of Disclosure Controls in Issuers’ Annual and Interim Filings (NI 52-109) as “…controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its certifying officers as appropriate to allow timely decisions regarding required disclosure.” The Company has conducted a review and evaluation of its DC&P, with the conclusion that as at December 31, 2008 the Company has an effective system of DC&P as defined under NI 52-109. In reaching this conclusion, the Company recognizes that two key factors must be and are present: 1. the Company is very dependent upon its advisors and consultants (principally its legal counsels) to assist in recognizing, interpreting, understanding and complying with the various securities regulations disclosure requirements; and 2. the Company has an active Board and management with open lines of communications. Bonterra has a small staff with varying degrees of knowledge concerning the various regulatory disclosure requirements. In many circumstances, the various regulatory requirements are relatively new, subject to interpretation, and complex. The Company is not of sufficient size to justify a separate department or one or more staff member specialists in this area. Therefore the Company must rely upon its advisors/consultants to assist it and as such they form part of the disclosure controls and procedures. Proper disclosure necessitates that a person not only be aware of the pertinent disclosure requirements, but must also be sufficiently involved in the affairs of the Company and/or receives the communication of information to assess any necessary disclosure requirements. Accordingly, it is essential that there be proper communication among those people who manage and govern the affairs of the Company, this being the Board of Directors and senior management. The Company believes this communication exists. 38 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 3 2 9 0 2 0 4 9 2 _ B o n t e r r a S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 1 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B C M Y C 7 0 C M Y B C M Y C M Y B C M Y M 7 0 C M Y B C M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B P r i n e c t 4 G S i F o r m a t 1 0 2 / 1 0 5 D i p c o 3 . 0 e ( p d f ) © 2 0 0 7 H e i d e l b e r g e r D r u c k m a s c h i n e n A G While Bonterra believes it has adequate DC&P in place, lapses in the disclosure controls and procedures could occur and/or mistakes could happen. Should such occur, the Company intends to take whatever steps it deems necessary to minimize the consequences thereof. Internal Controls Over Financial reporting Internal controls over financial reporting (ICFR) are defined in NI 52-109 as “… a process designed by, or under the supervision of, an issuer’s certifying officers and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s Generally Accepted Accounting Practices (GAAP) and includes those policies and procedures that: 1. pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer; 2. are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the issuer’s GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and 3. are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material effect on the annual financial statements or interim financial statements.” The Company has conducted a review and evaluation of its ICFR, with the conclusion that as of December 31, 2008 the Company’s system of ICFR as defined under NI 52-109 is adequately designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. The control framework the Company used to design and evaluate its ICFR was COSO. In its evaluation, the Company identified certain material weaknesses in internal controls over financial reporting: 1. due to the limited number of staff at the Company, it is not feasible to achieve the complete segregation of incompatible duties; and 2. due to the limited number of staff, the Company relies upon third parties as participants in the Company’s internal The net debt and cash flow from operations figures are presented in Table 2. controls over financial reporting. The Company believes these weaknesses are mitigated by: the active involvement of senior management and the board of directors in the affairs of the Company; open lines of communication within the Company; the present levels of activities and transactions within the Company being readily transparent; the thorough review of the Company’s financial statements by management, the board of directors and by the Company’s auditors (annual statements only); and the establishment of a whistle-blower policy. However, these mitigating factors will not necessarily prevent a material misstatement occurring as a result of the aforesaid weaknesses in the Company’s internal controls over financial reporting. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. The Company has no plans for remediating the above weaknesses. Limitation on Scope of Design of DC&p and ICFr The above design of DC&P and ICRF has been limited to exclude controls, policies and procedures of both Silverwing Energy Inc. (Silverwing) and operations of SRX Post Holdings (SRX) prior to the reorganization of Bonterra Energy Income Trust into the Company. The following tables summarize the information that has been included in the consolidated financial statements of the Company. 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 ($000) Financial assets Restricted term deposit Accounts receivable Investment in related party Financial liabilities Accounts payable and accrued liabilities Due to related party Short-term debt Long-term debt Table 2 ($000) Short-term debt Long-term debt Due to related party Current assets (1) Net Debt Accounts payable and accrued liabilities Cash flow from operations (2) Net debt to cash flow from operations As at December 31, 2008 Carrying value Fair value Face value 20 11,753 2,131 20 11,753 2,131 20 11,838 N/A 23,888 6,000 13,325 79,910 23,888 6,000 13,325 79,910 23,888 6,000 13,325 79,910 December 31, 2008 13,325 79,910 6,000 23,888 (18,971) 104,152 69,570 1.50 (1) Current assets include restricted term deposit, accounts receivable, crude oil inventory, prepaid expenses and investment in related party. (2) Cash flow from operations includes annual net earnings less adjustment for non-cash (gain) loss on risk management contracts, stock- based compensation, depletion, depreciation and accretion, future income taxes, changes in non-cash working capital items and asset retirement obligations settled. 4 B ON TERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 37 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 2 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 15. rELATED pArTY TrANSACTIONS The Company received a management fee from Comaplex of $330,000 (2007 - $300,000) for management services and office administration. This fee has been included as a recovery in general and administrative expenses and represents the fair value of the services rendered. In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total interest paid on the loan was $21,000. As at December 31, 2008, the Company had an account receivable from Comaplex of $56,000 (December 31, 2007 - $63,000). The Company received a management fee from Pine Cliff Energy Ltd., a company with common directors and management with the Company and its subsidiaries, of $238,000 (2007 - $216,000) for management services and office administration. This fee has been included in general and administrative expenses as a recovery and represents the fair value of the services rendered. As at December 31, 2008 the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2007 - $4,000). ($000) Restricted cash Future income tax benefit Property and equipment Working capital deficiency Asset retirement obligations ($000) Accounts receivable Prepaids Accounts payable 16. FINANCIAL AND CApITAL rISk MANAGEMENT INTErNAL CONTrOL ChANGES Silverwing 1,252 18,325 15,347 (14,979) (5,929) 14,016 SRX 2,158 1,701 3,859 Nil $ $ $ $ The Company undertakes transactions in a range of financial instruments including: Financial risk Factors • Receivables • Payables • Bank loans • Derivatives • Common share investments The Company’s activities result in exposure to a number of financial risks including market risk (commodity price risk, interest rate risk, foreign exchange risk, credit risk, and liquidity risk). 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 enters 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 in respect of interest rate risk. 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 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, the percentage of return of capital or issue new shares. The Company monitors capital on the basis of the ratio of debt to cash flow. During the year the Company acquired Silverwing, a public oil and gas producer for cash consideration including negative working capital of $28,795,000. In addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000 plus reorganization costs of $2,121,000. The Company has also experienced a decrease in cash flow due to the rather significant drop in commodity prices during the final four months of 2008. The Company is required to comply with Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”, otherwise referred to as Canadian SOX (C-Sox). The 2008 certificate requires that the Company disclose in the MD&A any changes in the Company’s internal control over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect the Company’s internal control over financial reporting. The Company confirms that no such changes were made to the internal controls over financial reporting during 2008. prODUCTION Crude oil and NGLs (barrels per day) Natural gas (MCF per day) Average BOE per day Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 3,105 8,892 4,587 3,013 7,233 4,219 3,098 7,176 4,295 3,073 7,637 4,346 3,113 6,627 4,218 Bonterra’s 2008 average production increased three percent on a per BOE basis. Crude oil production decreased by approximately 1.3 percent while gas production increased by approximately 15.2 percent. The decreased crude oil production was due to the timing of Bonterra’s 2008 development program in which production came on late in the year and therefore contributed little to 2008 and the 2007 property swap where the Company exchanged its predominantly Saskatchewan oil property for additional production in the Pembina area which had higher natural gas production. The natural gas increase was due to a combination of the successful 2008 development program, the acquisition of Silverwing on November 12, 2008 and the above mentioned property swap. The Company’s fourth quarter production in 2008 saw increases in crude oil (92 barrels per day) and natural gas (1,659 MCF per day) production over Q308 production due to the commencement of production from new wells drilled as well as the completion of the Silverwing acquisition. The Silverwing acquisition, which closed on November 12, 2008 added approximately 650 BOE per day, mainly natural gas. The Company’s average production volume for December was approximately 4,950 BOE per day. Bonterra’s overall annual decline rate for 2008 was approximately 8.5 percent. The Company was able to more than offset this decline with its 2008 drill program. Bonterra, along with its partners, drilled 33 gross (22.9 net) Cardium oil wells. This includes 26 gross and 21.9 net Cardium wells drilled directly by the Company. Also the Company drilled 7 gross (5 net) shallow gas wells in 2008 in the Pembina field and 3 gross (2.9 net) Shaunavon oil wells. The Company also participated in one (0.1 net) Cardium natural gas well drilled by one of its partners. Bonterra recorded a 100 percent success rate with its 2008 drilling program. The majority of the wells were drilled in the fourth quarter; 14 (10.2 net) Cardium oil wells, 7 gross (5 net) shallow Pembina gas wells and all three (2.9 net) of the Shaunavon oil wells. The closing date for the Silverwing acquisition was November 12, 2008 and therefore contributed little to production rates for the full year. 36 BONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 5 As at December 31, 2008, Bonterra had only one gross (0.25 net) Cardium oil well, no natural gas wells, three gross (2.5 net) coalbed methane (CBM) wells with assigned reserves and three gross (2.9 net) Shaunavon oil wells drilled but not on production. Subsequent to December 31, 2008 and up to the date of this report, the Company has put all of its oil wells on production. The timing for the tie-in of the CBM wells has not yet been determined. rEvENUE (Cdn $) Revenue – oil and gas sales (000’s) - cash Average Realized Prices: Crude oil and NGLs (per barrel) Natural gas (per MCF) Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 22,613 34,226 26,573 121,730 96,431 58.91 7.00 103.36 8.20 77.60 6.70 87.54 8.21 70.31 6.75 Revenue from petroleum and natural gas sales increased 26 percent in 2008 compared to 2007 due to increased production volumes and an increase in the average price received for crude oil, natural gas liquids and natural gas. The fourth quarter of 2008 saw a substantial decrease in realized revenues over the third quarter of 2008 due to the significant decrease in commodity prices. Included in revenue is a risk management loss of $7,353,000 (2007 – gain of $621,000) due to lower prices received as a result of commodity risk management agreements. The Company may continue to hedge future production to assist in managing its cash flow. As at December 31, 2008, the Company had no outstanding risk management agreements. The value of the outstanding commodity hedging contracts as of December 31, 2007 was a net liability of $3,085,000. rOYALTIES ($ 000) Crown royalties Freehold royalties, gross overriding royalties and net carried interests Total royalty expense Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 2,337 3,523 2,634 13,736 9,209 558 2,895 1,134 4,657 682 3,316 3,479 17,215 3,235 12,444 Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta, Saskatchewan and British Columbia. The majority of the Company’s wells are low productivity wells and therefore have low Crown royalty rates. The Company’s average Crown royalty rate was approximately 10.6 percent (2007 – 10 percent) and approximately 2.7 percent (2007 – 3 percent) for other royalties before hedging adjustments. During 2007, the Company was advised by the owner of a gross overriding royalty that a production limit was attained that resulted in an additional gross overriding royalty in respect of certain of its Cardium oil wells. The production limit was triggered by a calculation on a multitude of Cardium wells including many that were not owned by the Company. In addition the exact wells that the production limit was applicable to was not readily known by the Company nor easily determined. In discussions with the payee it was determined that the production limit was reached in late 2005. The royalty was calculated based on this agreed date and the affected wells for the Company and other operators in the area were identified. The approximate amount of the adjustment, net to the Company was $570,000 for periods prior to January 1, 2007. This amount has been included in the 2007 royalty numbers. Also in 2007 the Company was informed by the operator of its former Dodsland property that it had not been charged a net profit royalty for the years 2004, 2005 and 2006. In reviewing the agreements it was confirmed the claim was accurate and an amount of approximately $150,000 was paid by the Company in 2007 for the net profit royalty. This was also expensed in 2007. The following table summarizes information about stock options outstanding at December 31, 2008: Options Outstanding Options Exercisable Range of Exercise Prices $20.50 Number Weighted-Average Number Oustanding At 12/31/08 1,390,500 Remaining Weighted-Average Exercisable Weighted-Average Contractual Life Exercise Price At 12/31/08 Exercise Price 3.9 years $ 20.50 – $ – A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is presented below: 2008 weighted- Average 2007 Weighted- Average Options Exercise price Options Exercise Price Outstanding at beginning of year Options granted Options exercised Options cancelled Outstanding at end of year Options exercisable at end of year 1,177,000 $ 29,000 (321,700) (884,300) – $ – $ 27.59 39.09 24.66 29.03 – – 721,500 $ 553,000 (53,500) (44,000) 1,177,000 $ 530,000 $ The Company records compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. The Company granted 1,390,500 stock options with an estimated fair value of $1,548,000 ($1.11 per option) using the Black-Scholes option pricing model with the following key assumptions: Weighted-average risk free interest rate (%) Expected life (years) Weighted-average volatility (%) Dividend yield 2008 and 2007 14. ACCUMULATED OThEr COMprEhENSIvE INCOME based on the percentage of dividends or distributions paid during the year 26.55 28.11 18.56 27.92 27.59 26.63 2007 4.7 2.3 27.2 2008 2.2 3.5 31.3 Other Other January 1, Comprehensive December 31, 2008 Income (Loss) 2008 $ 3,031 $ (1,611) $ 1,420 January 1, Comprehensive December 31, 2007 Income (Loss) 2007 $ 1,566 $ 1,465 $ 814 $ 2,380 $ (814) 651 $ 3,031 – 3,031 Unrealized gains (losses) on available for sale financial assets ($000) ($000) Unrealized gains on available for sale financial assets Unrealized gains and losses on derivatives designated as cash flow hedges 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 2 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 6 B ON TERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 35 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 2 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 ($000) Issued Trust Units Number Amount Number Amount Balance, beginning of year 16,928,158 $ 16,874,658 $ 89,488 Transfer of contributed surplus to unit capital Issued pursuant to Trust unit option plan Issued on acquisition of Silverwing – 321,700 7,745 Cancelled on conversion to a corporation (17,257,603) (99,530) 53,500 – – – 109 993 – – 90,590 805 7,935 200 Balance, end of year – $ – 16,928,158 $ 90,590 The Company is 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. The number of common shares (formerly trust units) used to calculate diluted net earnings per share (formerly per unit) for the year ended December 31, 2008 of 17,119,517 shares (2007 – 16,942,036 Units) included the basic weighted average number of common shares outstanding of 17,075,647 shares (2007 – 16,908,266 Units) plus 43,870 shares (2007 – 33,770 Units) related to the dilutive effect of common share options. A summary of the changes of the Company’s contributed surplus is presented below: Contributed surplus ($000) Balance, beginning of year Stock-based compensation expensed (non-cash) Stock-based options exercised (non-cash) Balance, end of year The deficit balance is composed of the following items: ($000) Deficit Accumulated earnings Accumulated cash dividends and distributions Outstanding at beginning of year Options granted Outstanding at end of year Options exercisable at end of year 2008 2,140 $ 1,207 (805) 2,542 $ 2007 1,116 1,133 (109) 2,140 2008 208,182 $ (254,897) (46,715) $ 2007 152,756 (204,299) (51,543) $ $ $ $ 2008 weighted- Average Options Exercise price – $ 1,390,500 1,390,500 $ – $ 20.50 20.50 – – The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). 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 A summary of the status of the Company’s stock option plan as of December 31, 2008 and changes during the year is five years. presented below: 2008 2007 New Alberta Crown royalty Framework (NrF) Royalty rates in the fourth quarter averaged approximately 13.4 percent; slightly higher than preceding quarters. The NRF rates vary by prices as well as productivity levels. With the current low prices the new royalty rates should result in a significant reduction in the amount the Company will pay to the Province of Alberta. This combined with the Silvering acquisition (mostly BC production with lower Crown royalty rates) should result in a lower average Crown royalty rate for the Company in 2009. The effect of the NRF on the Company’s oil and liquid reserves was a reduction of 77,200 barrels for proved and a reduction of 132,800 barrels for proved plus probable reserves. For natural gas, the NRF accounted for a reduction of 56,500 MCF for proved and 128,800 MCF for proved plus probable reserves. On a BOE basis, this reduction represented approximately 0.6 percent of the Company gross reserves on a proved plus probable basis. prODUCTION COSTS ($ 000) Production costs $ per BOE Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 6,859 16.25 6,148 15.84 5,535 14.01 25,413 15.98 24,073 15.64 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. Operating costs on the Company’s newly acquired British Columbia (BC) properties as well as on the newly drilled wells are lower on a BOE basis than on its older low productivity wells and this may result in lower operating costs per BOE in the future. Operating costs increased slightly in the fourth quarter of 2008 compared to the prior quarter due primarily to the acquisition of Silverwing and from new wells put on production in the fourth quarter of 2008 and large industry wide increases for oilfield services especially for oil producing properties. Average production costs per BOE increased marginally in Q408 compared with the previous quarter due mainly to winterization programs performed on the Company’s wells and facilities. As discussed above, Bonterra’s production comes primarily from low productivity wells. These wells generally result in higher operating costs on a per unit-of-production basis as costs such as municipal taxes, surface leases, power and personnel costs are not variable with production volumes. The Company is continually examining ways to reduce operating costs. With the acquisition of Silverwing and the Company’s recent drilling success and expected declines in oilfield service costs, the Company anticipates operating costs in the $14 to $15 per BOE range for 2009. The higher operating costs for the Company are substantially offset by lower royalty rates and results in higher cash net backs on a combined basis despite higher than average operating costs. GENErAL AND ADMINISTrATIvE ExpENSE ($ 000) G&A Expense $ per BOE Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 824 1.95 845 2.18 739 1.69 3,401 2.14 2,603 1.69 General and administrative (G&A) expenses increased 31 percent in 2008 compared to 2007. The Company provides administrative services to Comaplex Minerals Corp. (Comaplex) and Pine Cliff Energy Ltd. (Pine Cliff), companies that share common directors and management. Please refer to discussion under Related Party Transactions for details. 34 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 7 The Company’s only significant general and administrative costs are employee compensation and professional services such as legal, engineering and accounting. Employee compensation expense increased by approximately 29 percent ($856,000). The increase is due primarily to the Company’s bonus plan which resulted in additional employee compensation of $610,000 (20.7 percent) with the remainder due to increased staffing levels (3.8 percent) and 2008 salary increases (4.5 percent). The Company’s bonus plan consists of cash payments equal to three percent of before tax net earnings to be paid to employees and key consultants based on performance throughout the year. Costs associated with professional services increased by approximately $90,000. Increases in other general and administrative areas have been offset by increased administration recovery charges to capital programs. The quarter over quarter decrease was primarily due to a lower bonus accrual but was almost fully offset by increased professional fees related to the internal control review and costs related to managing the integration of the Silverwing acquisition and reorganization. ($000) Undepreciated capital costs Eligible capital expenditures Share issue costs Canadian oil and gas property expenditures Canadian development expenditures Canadian exploration expenditures SR&ED expenditures Income tax losses carried forward (1) The Company and its subsidiaries have the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization: INTErEST ExpENSE ($ 000) Interest Expense Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 (1) Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000, 2027 - $116,787,000, 2028 - $40,750,000. The Company has $27,670,000 of investment tax credits (ITC) that expire in the following years; 2009 - $3,469,000, 2010 - 746 545 878 2,740 3,028 $3,059,000, 2011 - $4,667,000, 2012 - $3,909,000, 2013 - $3,155,000, 2014 - $1,995,000, 2015 - $2,257,000, 2016 - $2,405,000, Utilization % Amount Rate of 20-100 $ 7 20 10 30 100 100 100 23,696 1,870 4,581 25,072 50,743 10,530 80,357 271,029 $ 467,878 The decrease in interest expense in 2008 as compared to 2007 was due to much lower borrowing costs, offset partially by increased loan balances resulting from the Company’s acquisition of Silverwing and its reorganization. Interest rates during the year on the outstanding debt averaged approximately 4.5 percent (2007 - 5.9 percent). The Company maintained an average outstanding debt balance of approximately $60,600,000 (2007 - $51,600,000). Total debt (including negative working capital) as of December 31, 2008 represents approximately 17.9 months of 2008 annual cash flow from operations or 30.1 months based on annualized 2008 fourth quarter cash flow from operations. The ratio of bank debt only as of December 31, 2008 based on the annualized 2008 Q4 base was 27.1 months. Also in the fourth quarter of 2008 the Company had one time reorganization costs of approximately $1,369,000 reducing cash flow to $10,336,000 from approximately $11,700,000. This one item has significant implications on the ratio of bank debt to cash flow and would reduce the Q4 numbers of 30.1 to 26.6 and 27.1 to 23.9 months. During the year the Company acquired Silverwing a public oil and gas producer for cash consideration including negative working capital of $28,995,000. In addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000 plus reorganization costs of $2,121,000. The Company also experienced a decrease in cash flow due to the rather significant drop in commodity prices during the final four months of 2008. The Company ended 2008 with a debt to cash flow ratio that is higher than usual even though it is in a range that is normal with its peers at the present time. The main reason for the higher debt level is that early in the third quarter of 2008, when the Company announced its reorganization and Silverwing acquisition, it had share options outstanding that were well in the money for approximately $25 million. At closing of the reorganization on November 12, 2008, the world economy had changed substantially resulting in large reductions in share prices, including Bonterra’s and the majority of the outstanding options not being exercised. The debt level is still very manageable for Bonterra but plans for 2009 are to reduce the debt to equity ratio that presently exceeds 2:1. 2017 - $2,009,000, 2018 - $745,000. 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, and distrubution policy. A significant change in any of the preceding assumptions could materially affect the Company’s estimate of the future income tax asset. 12. ASSET rETIrEMENT OBLIGATIONS At December 31, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was $58,903,000 (2007 - $54,622,000). Costs for asset retirement have been calculated assuming a two 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 (2007 – five percent). Changes to asset retirement obligations were as follows: ($000) Asset retirement obligations, January 1 Adjustment to asset retirement obligations Adjustment related to asset additions (net of disposals) Liabilities settled during the year Accretion $ 2008 14,904 $ (217) 5,929 (3,063) 785 2007 14,819 (399) 563 (820) 741 Asset retirement obligations, December 31 $ 18,338 $ 14,904 The Company is authorized to issue an unlimited number of common shares without nominal or par value. 13. ShArEhOLDErS’ EQUITY Authorized ($000) Issued Common Shares Balance, beginning of year Issued on reorganization to a corporation Balance, end of year 2008 2007 Number Amount Number Amount – $ 17,257,603 17,257,603 $ – 99,530 99,530 – $ – – $ – – – 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 2 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 8 B ON TERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 33 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 2 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 The following is a list of the material covenants: • The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes negative working capital but excludes debt to related parties). • Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as The Company has recorded a future income tax asset related to assets and liabilities and related tax amounts: defined under GAAP. 11. INCOME TAXES ($000) Future tax liability related to investments: Future tax liability related to property and equipment: Future tax asset related to asset retirement obiligations: Future tax asset related to finance costs: Future tax asset related to corporate tax losses and SR&ED claims Future tax asset (Liability) – Long-term Current portion of future income tax asset related to corporate tax losses and SR&ED claims: Future income tax asset related to current portion of derivative liability Future Tax Asset - Current As a result of the reorganization the Company recorded a deferred credit of $71,303,000 relating to the difference between the future income tax asset generated on the reorganization and the amount of the cash payment made to SRX immediately before the reorganization. This credit is being amortized (2008 - $4,240,000) on the same basis as the related future income tax asset (2008 - $4,909,000). A reconciliation of the deferred credit is as follows: Amount recorded on reorganization Amortized in current year Balance as of December 31, 2008 Current portion Long-term portion 2008 (212) $ (7,097) 4,593 1,134 $ 86,998 85,416 $ 2,669 $ – 2,669 $ 2007 (448) (14,828) 3,759 79 3,843 (7,595) – 913 913 $ 71,303,000 (4,240,000) $ 67,063,000 $ 2,305,000 64,758,000 $ 67,063,000 $ $ $ $ $ $ Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial income tax rates as follows: ($000) Earnings before income taxes Combined federal and provincial income tax rates Income tax provision calculated using statutory tax rates Increase (decrease) in taxes resulting from: Saskatchewan resource surcharge Stock-based compensation Change in effective tax rate Trust income allocated to Unitholders prior to conversion Others Income tax expense 2008 58,014 $ 29.62% 17,184 437 357 (4,739) (10,291) (360) 2007 33,434 32.27% 10,789 512 366 4,076 (13,176) 517 3,084 $ 2,588 $ Bank debt at December 31, 2008 was $93,235,000 (December 31, 2007 - $57,422,000). 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 interest rate on the credit facilities is calculated as follows: Level I Level II Level III Level IV Level V Level VI Consolidated Total Funded Debt (1) to Consolidated Cash flow ratio Below 0.50:1 Over 0.5:1 to 1.0:1 Over 1.0:1 to 1.5:1 Over 1.5:1 to 2.0:1 Over 2.0:1 to 2.5:1 Over 2.5:1 Canadian Prime Rate Plus Bankers’ Acceptances Rate Plus 50 150 75 175 85 185 100 200 125 225 150 250 (1) Consolidated total funded debt excludes related party amounts but includes working capital. Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to be effective until the next such adjustment. rEOrGANIzATION COSTS Based on current accounting rules, costs associated with the Trust’s reorganization into Bonterra Oil and Gas Ltd. must be expensed. The costs consist of a $1,000,000 finders fee paid to a company that facilitated the reorganization, $931,000 of professional fees, $150,000 stock exchange fees and $40,000 of costs associated with the distribution of the reorganization document. These costs are all one time costs and no further costs are anticipated by the Company in direct relation to the reorganization. Of these total costs of $2,121,000, the Company expensed $1,369,000 in the fourth quarter of 2008 and $752,000 was expensed in the third quarter of 2008. 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. Due to the reorganization, all existing employee unit options vested and were either exercised or were cancelled. This resulted in approximately an additional $195,000 of stock-based compensation being recorded in the fourth quarter on the automatic vesting of outstanding options. Also the Company issued 1,390,500 stock options during 2008 resulting in a further expense of $97,000. The 1,390,500 common share options were issued at the end of November 2008 with an exercise price of $20.50 per share and a fair value of $1.11 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 2.2 percent (2007 – 4.7 percent), expected weighted average volatility of 31 percent (2007 – 27 percent), expected weighted average life of 3.5 years (2007 – 2.3 years) and an annual dividend/distribution rate based on the dividends paid to the Shareholders/Unitholders during the year. The future stock-based compensation impact of these options is approximately $225,000 per quarter over the next four quarters. 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, a life span of ten years is estimated and the related tangible costs are depreciated at one tenth of original cost per year. The use of a ten year life span instead of calculating depreciation over the life of reserves was determined to be more representative of actual costs of tangible property. Given the Company’s long production life, wells generally require replacement of tangible assets more than once during their life time. Most of the Company’s wells have been producing since the 1960’s and are expected to continue to produce for at least another twenty years. 32 B ONTER R A O IL & GAS LTD. BON TERRA OI L & G AS LTD. 9 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 2 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 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, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was $58,903,000 (2007 - $54,622,000). Of the $4,281,000 increase, the majority is due to the Silverwing acquisition. 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 $2,706,000. While a one percent decrease in the risk adjusted rate would increase the asset retirement obligation by $3,639,000. 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, 2008, the Company expensed $14,749,000 (2007 - $16,675,000) for the above-described items including $Nil (2007 - $3,078,000) for dry hole costs. During 2007 the Company wrote off all costs related to eight wells which no reserves were attributed by the independent third party engineers. The Company continues to have relatively low finding and development costs (see discussion under Finding and Development Costs). Based on year end reserves, the Company’s average cost of proved reserves is $6.40 (2007 - $5.84) per BOE. The Company currently has an estimated reserve life for its proved developed producing reserves of 12.5 (2007 – 11.3) years calculated using the Company’s gross reserves (prior to allowance for royalties) based on the third party engineering report dated December 31, 2008 and using fourth quarter 2008 average production rates of 4,587 BOE per day (2007 – 4,295 BOE per day). Based on total proved reserves the Company has a 14.4 (2007 – 13.7) year reserve life and if proved and probable are used the reserve life increases to 18.7 (2007 – 17.4) years. These figures are some of the longest reserve life indexes (excluding oil sands) in the Canadian oil and gas industry. INCOME TAxES On November 12, 2008, Bonterra Energy Income Trust converted to a corporation. Due to the conversion and the acquisition of Silverwing, the Company increased its usable tax pools to approximately $468,000,000 (see below). As a result of the reorganization, the Company has recorded a future income tax asset and a corresponding deferred tax credit. These amounts will be amortized into future tax expense as the associated tax pools are consumed. The current tax provision relates to resource surcharge payable by the Company to the Province of Saskatchewan. The surcharge is calculated as a flat percent of revenues generated from the sale of petroleum products produced in Saskatchewan. The provincial government of Saskatchewan reduced the resource surcharge rate from 3.1 percent to 3.0 percent on July 1, 2008. 8. prOpErTY AND EQUIpMENT ($000) Undeveloped land Petroleum and natural gas properties and related equipment Furniture, equipment and other 9. DUE TO rELATED pArTY 2008 2007 Accumulated Depletion and Accumulated Depletion and Cost Depreciation Cost Depreciation $ 2,295 $ – $ 316 $ – 229,136 1,254 74,844 848 185,947 1,025 $ 232,685 $ 75,692 $ 187,288 $ 61,105 700 61,805 As of December 31, 2008, the Company’s CEO and major shareholder has loaned the Company $6,000,000. The loan is unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment terms. The loan can only be repaid should the Company have sufficient available borrowing limits under the Company’s credit facility. Interest paid on this loan during 2008 was $7,000. Please refer to note 15 for additional related party transactions. 10. BANk DEBT Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of an $80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December 31, 2007 - $69,900,000) (non-syndicated demand facility). Amounts drawn under these facilities at December 31, 2008 were $93,235,000 (December 31, 2007 - $57,422,000). The interest rates on the outstanding debt as of December 31, 2008 were 4.35 percent and 3.49 percent on the Company’s Canadian prime rate loan (short-term debt) and Bankers’ Acceptances (long-term debt), respectively. The terms of the syndicated revolving credit facility provide that the loan is revolving to May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment requirements. The terms of the non-syndicated demand credit facility provide that the loan is due on demand and is subject to annual review and has no fixed repayment terms. The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit totaling $525,000 were issued at December 31, 2008 (December 31, 2007 - $355,000). Of the letters of credit, $20,000 is secured by a restricted term deposit. 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 facilities is calculated as follows: Consolidated Total Funded Debt (1) to Consolidated Cash flow ratio Level I Level II Level III Level IV Level V Level VI Below Over 0.5:1 Over 1.0:1 Over 1.5:1 Over 2.0:1 0.50:1 to 1.0:1 to 1.5:1 to 2.0:1 to 2.5:1 Over 2.5:1 Canadian Prime Rate Plus (2) Bankers’ Acceptances Rate Plus (2) 50 150 75 175 85 185 100 200 125 225 150 250 (1) Consolidated total funded debt excludes related party amounts but includes working capital. (2) Numbers in table represent basis points. Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to be effective until the next such adjustment: 10 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 31 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 2 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 4. rEOrGANIzATION As part of the reorganization of the Trust, SRX acquired all the issued and outstanding trust units of Bonterra Energy Income Trust on a basis of one Trust Unit for one Common Share of SRX. Immediately preceding the reorganization, SRX was in receivership. Prior to the conversion, the Trust advanced $11,257,000 to SRX for settlement of claims pursuant to the CCAA proceedings. Upon completion of the CCAA procedures, SRX was owed $2,224,000 in outstanding tax and legal claims that will be used by the CCAA Monitor to settle secured creditor claims. This amount has been recorded as an outstanding account receivable by the Company. In addition, SRX paid an advance of $1,800,000 to the CCAA Monitor for costs and payment of the unsecured creditors. This amount has been recorded as a prepaid expense in the accounts of the Company. Included in accounts payable is $4,024,000 to account for the amount due to the secured and unsecured creditors. Of the tax claims, $66,000 had been received and repaid to the Monitor by December 31, 2008. In addition, $99,000 of expense claims had been paid by the Monitor and deducted from the advance. 5. BUSINESS COMBINATION On November 12, 2008, the Company acquired all the common shares of Silverwing for cash consideration of $13,816,000 (including acquisition costs of $334,000) plus the issuance of 7,745 common shares at a value of $25.85 per common share plus the assumption of $14,979,000 of negative working capital. The results of Silverwing’s operations have been included in the consolidated financial statements since that date. The acquisition was funded through the Company’s new bank 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: facility (see Note 10). Cost of acquisition (000’s) Cash paid Value of common stock Acquisition costs Allocation of purchase price: Restricted cash Future income tax benefit Property and equipment Working capital deficiency Asset retirement obligations $ 13,482 200 334 $ 14,016 $ $ 1,252 18,325 15,347 (14,979) (5,929) 14,016 6. INvESTMENT IN rELATED pArTY The investment consists of 689,682 (December 31, 2007 – 689,682) common shares in Comaplex Minerals Corp (Comaplex), a company with common directors and management with the Company and its subsidiaries. The investment is recorded at fair market value. The common shares trade on the Toronto Stock Exchange under the symbol CMF. The investment represents less than a one and a half percent ownership in the outstanding shares of Comaplex. 7. rESTrICTED CASh An escrow account was held by Silverwing prior to its acquisition by the Company. The escrow account was created to support eligible expenditures related to a farm-in agreement. The Company may access the funds upon completion and tie-in or abandonment and reclamation of 20 wells. The funds are administered by the farmors’ legal counsel. The funds in the escrow account are invested in interest bearing term deposits. 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: ($000) Undepreciated capital costs Eligible capital expenditures Share issue costs Canadian oil and gas property expenditures Canadian development expenditures Canadian exploration expenditures SR&ED expenditures Income tax losses carried forward (1) Rate of Utilization % 20-100 7 20 10 30 100 100 100 $ Amount 23,696 1,870 4,581 25,072 50,743 10,530 80,357 271,029 $ 467,878 (1) Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000, 2027 - $116,787,000, 2028 - $40,750,000. Prior to becoming a corporation, the Trust paid nine distributions for the 2008 tax year. The Canadian tax breakdown of those distributions is as follows: Taxable Income (Other Income) Return of Capital Percentage 85.16 14.84 100.00 With respect to cash distributions paid during the year to U.S. individual unitholders, 17.71 percent should be reported as a return of capital (to the extent of the Unitholder’s U.S. tax basis in their respective units) and 82.29 percent should be reported as qualified dividends. NET EArNINGS ($ 000) Net Earnings Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 10,585 21,125 8,372 55,426 30,350 Bonterra’s net earnings for the year ended December 31, 2008 represents an 82 percent increase over the Company’s 2007 net earnings. The Company recorded net earnings per share on a fully diluted basis in 2008 of $3.23 verses $1.79 in the 2007 year. This represents a return on Shareholders’ equity of approximately 97.6 percent (2007 – 68.6 percent) based on year end Shareholders’ equity. Strong crude oil and natural gas prices for most of 2008 along with a three percent increase in production volumes were driving factors behind the increased profit. However, during the fourth quarter and continuing into the first quarter and likely beyond, commodity prices have plunged to under $40 U.S. ($50 Cdn). This along with natural gas prices in the $4 to $5 dollar range will significantly reduce the Company’s future net earnings. The Company’s low capital costs combined with the Company’s low production decline rates should allow for continued positive earnings even in the above mentioned price environment. COMprEhENSIvE INCOME On January 1, 2007, Bonterra became obliged to adopt the new accounting standards regarding the accounting for financial instruments. On adoption, the Company increased its investment in related party by $1,836,000 for the fair value of this investment. On January 1, 2007, Bonterra further recognized a current asset of $1,189,000 for the fair value of its commodity derivative contracts. These adjustments resulted in a further increase in the future income tax liability and accumulated other comprehensive income of $645,000 and $2,380,000, respectively. 30 BONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 11 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 2 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 Other comprehensive income for 2008 consists of an unrealized loss on investment in a related party of $1,611,000 (2007 gain of $1,465,000) including a fourth quarter loss of $1,123,000 relating to a reduction in the related company’s fair value. Effective October 1, 2007, the Company discontinued the use of hedge accounting due to the difficulty in determining the effective portion of the commodity risk management contracts. CASh FLOw FrOM OpErATIONS ($ 000) Three months ended December September December 31, 2007 30, 2008 31, 2008 Twelve months ended December 31, 2008 December 31, 2007 3. NEw ACCOUNTING pOLICIES Cash flow from operations 10,336 22,492 13,369 69,570 51,433 Capital Disclosures Basic and Diluted per Share (formerly per Unit) 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. Cash flow from operations increased 35 percent year over year, mainly due to increased commodity prices received during the first nine months of 2008. The fourth quarter of 2008 saw significant price declines in all commodity categories. Although the Company was able to increase production in the fourth quarter of 2008 by almost nine percent over the previous quarter, cash flow from operations decreased approximately 54 percent. One time costs of $1,369,000 incurred in Q4 (Q3 - $752,000) related to the reorganization also contributed to the decline. With the continuing depressed crude oil and natural gas prices, cash flow for 2009 is expected to be significantly negatively affected. The price declines are expected to be partially offset by anticipated production volumes in excess of 5,000 BOE per day for 2009, and anticipated decreases in G&A costs (lower employee compensation) and in corporate resource surcharge (tax on revenues). Also, Bonterra does not expect any further costs associated with the acquisition of Silverwing or the reorganization. CASh NETBACkS The following table illustrates the Company’s cash netback: $ per Barrel of Oil Equivalent (BOE) Production volumes (BOE) Gross production revenue Realized gain (loss) on risk management contracts Royalties Field operating Field netback General and administrative Interest and taxes Cash netback 2008 2007 1,590,666 1,539,461 $ 81.15 $ (4.62) (10.82) (15.98) 49.73 (2.14) (2.00) $ 45.59 $ 62.24 0.40 (8.08) (15.64) 38.92 (1.69) (2.30) 34.93 The following table illustrates the Company’s cash netback for the three months ended: $ per Barrel of Oil Equivalent (BOE) Production volumes (BOE) Gross production revenue Realized gain (loss) on risk management contracts Royalties Field operating Field netback General and administrative Interest and taxes Cash netback December 31, 2008 September 30, 2008 422,008 395,962 $ 51.27 $ 2.31 (6.86) (16.25) 30.47 (1.95) (1.90) $ 26.62 $ 95.80 (7.60) (12.00) (15.84) 60.36 (2.18) (1.73) 56.45 Effective January 1, 2008, the Company prospectively adopted the Canadian Institute of Chartered Accountants (CICA) Section 1535, “Capital Disclosures” which establishes standards for disclosing information about the Company’s capital and how it is managed. It requires disclosures of the Company’s objectives, policies and processes for managing capital, the quantitative data about what the Company regards as capital, whether the Company has complied with any capital requirements and if it has not complied, the consequences of such non-compliance. The only effect of adopting this standard is disclosures about the Company’s capital and how it is managed (see Note 16). Financial Instruments Disclosures and presentation Effective January 1, 2008, the Company prospectively adopted Section 3862, “Financial Instruments – Disclosures” and Section 3863, “Financial Instruments – Presentation.” These new accounting standards replaced Section 3861, “Financial Instruments – Disclosure and Presentation.” Section 3862 requires additional information regarding the significance of financial instruments for the entity’s financial position and performance, and the nature, extent and management of risks arising from financial instruments to which the entity is exposed. The additional disclosures required under these standards are included in Note 16. recent Accounting pronouncements In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. The Company adopted these standards for its fiscal year beginning January 1, 2009 with no impact on its consolidated financial statements. In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the adoption of this statement to have a material impact on the Company’s results of operations or financial position. In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material impact on the results of operations or financial position. The Accounting Standards Board has confirmed the convergence of Canadian GAAP with International Financial Reporting Standards (IFRS) will be effective January 1, 2011. The Company has performed an initial scoping process in order to ensure successful implementation within the required timeframe. The impact on the Company’s consolidated financial statements is not reasonably determinable at this time. Key information will be disclosed as it becomes available during the transition period. 12 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 29 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 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 other financial liabilities. Financial instruments are measured at fair value on initial recognition of the instrument, into one of the following five categories: held-for trading, loans and receivables, held-to-maturity investments, available-for-sale financial assets or Subsequent measurement of financial instruments is based on their initial classification. Held-for-trading financial assets 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. Cash and restricted cash are classified as held-for-trading and are measured at fair value which equals the carrying value and any gains or losses are recognized in earnings in the period they occur. Accounts receivable are classified as loans and receivables which are measured at amortized costs. 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 and bank debt 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 determined from 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 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 year ended December 31, 2008, the Company did not designate any of its financial instruments as hedges. There are no risk management contracts outstanding as at December 31, 2008. Stock-Based Compensation FINDING AND DEvELOpMENT COSTS (F&D COSTS) The Company has been active in its capital development program over the past three years. Over this time period Bonterra has incurred the following F&D Costs: 2008 F&D 2007 F&D Costs per Costs per BOE (1)(2) BOE (1)(2) 2006 F&D Costs per BOE (1)(2) 2008 Three Year Average 2007 Three Year Average Proved Reserve Additions Proved plus Probable Reserve Additions $ $ 8.67 $ 7.47 $ 2.74 $ 2.68 $ 25.51 $ 18.21 $ 12.30 $ 9.45 $ 14.37 11.07 The above figures have been calculated in accordance with National Instrument 51-101 (NI 51-101) where the F&D Costs equate to the total exploration and development costs incurred by the Company during the year plus the yearly change in estimated future development costs as calculated by Sproule Associates Limited. The following precautionary notes have been provided as required by NI 51-101. (1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6MCF:1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. (2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. Results from the Company’s Cardium oil drilling program continue to be better than anticipated resulting in an increase in the third party engineering reports estimated recoverable reserves from existing wells but also from future development. Continued low decline rates have also resulted in increased reserves due to technical revisions. Both these factors contributed to an overall F&D cost in 2008 of $7.47 per BOE on a proved plus probable basis. rELATED pArTY TrANSACTIONS The Company holds 689,682 (2007 – 689,682) common shares in Comaplex which have a fair market value as of December 31, 2008 of $2,131,000 (2007 - $4,014,000). Comaplex is a publically traded mineral company on the Toronto Stock Exchange. The Company’s ownership in Comaplex represents approximately 1.3 percent of the issued and outstanding common shares of Comaplex. The Company has common directors and management with Comaplex. Comaplex paid a management fee to the Company of $330,000 (2007 - $300,000). Comaplex also shares office rental costs and reimburses the Company for costs related to employee benefits and office materials. In addition, Comaplex owns 204,633 (December 31, 2007 – 204,633) common shares in the Company. Services provided by the Company include executive services (president and vice president, finance duties), accounting services, oil and gas administration and office administration. All services performed are charged at estimated fair value. At December 31, 2008, Comaplex owed the Company $56,000 (December 31, 2007 - $63,000). In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total interest paid on the loan was $21,000. The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors and management with the Company. Pine Cliff trades on the TSX Venture Exchange. Pine Cliff paid a management fee to the Company of $238,000 (2007 - $216,000). Services provided by the Company include executive services (president and vice president, finance duties), accounting services, oil and gas administration and office administration. All services performed are charged at estimated fair value. The Company has no share ownership in Pine Cliff. As at December 31, 2008 the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2007 – $4,000). As of December 31, 2008, the Company’s CEO and major shareholder had loaned the Company $6,000,000. The loan is unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment terms. The loan can only be repaid should the Company have sufficient available borrowing limits within its bank debt. Interest paid on this loan during 2008 was $7,000. 28 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 13 COMMITMENTS Inventories The Company has no contractual obligations that last more than a year other than its office lease agreements which are as follows: Contract Obligations ($000) Office leases (1) Total Less than 1 year 1 – 3 years $ 2,907 $ 589 $ 1,238 $ 4 – 5 years 1,080 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 sales price (1) Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds Investments are carried at fair value. Fair value is determined by multiplying the year end trading price of the investments received on the sublease have not been offset against the contractual liability. by the number of common shares held as at period end. FINANCIAL rEpOrTING UpDATE During 2007, the Company completed the implementation of the new CICA Handbook Section 3855, Financial Instruments – Recognition and Measurement, Section 1530, Comprehensive Income and Section 3865, Hedges that deal with the recognition and measurement of financial instruments at fair value and comprehensive income. See Notes 2 and 14 in the Notes to the audited Consolidated Financial Statements for further details. Accounting Changes During 2008, the Company adopted Section 1535 “Capital Disclosures”, Section 3862, “Financial Instruments - Disclosures” and Section 3863, “Financial Instruments - Presentation”. All the above Sections were required to be adopted for fiscal years beginning on or after October 1, 2007. As a result, the Company has added Note 16 providing the required disclosures regarding the Company’s objectives, policies and processes for managing capital and the significance of financial instruments for the entity’s financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed. Future Accounting Changes In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. This standard establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company does not expect that the adoption of this new Section will have a material impact on its consolidated financial statements. In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the adoption of this statement to have a material impact on the Company’s results of operations or financial position. In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material impact on the results of operations or financial position. in the month preceding year end. Investments 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 and equipment costs are depleted over the remaining proved developed reserves. Depreciation of other plant and equipment is provided on the straight line method. Straight line depreciation is based on the estimated service lives of the related assets which is estimated to be ten years. Furniture, Fixtures and Office Equipment These assets are recorded at cost and depreciated over a three to ten year period representing their estimated useful lives. Income Taxes 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. 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 14 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 27 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 CONSOLIDATED FINANCIAL STATEMENTS NOTES TO ThE For the Years Ended December 31, 2008 and 2007 1. ChANGE OF OrGANIzATION On November 12, 2008, Bonterra Energy Income Trust (the “Trust”) converted to Bonterra Oil & Gas Ltd. (the “Company”) through a reverse takeover by the Trust of SRX Post Holdings Inc. (SRX). In conjunction with the reorganization, the Trust acquired all the issued and outstanding shares of Silverwing Energy Inc. (Silverwing). Concurrently, all of the Company’s subsidiaries, including Silverwing were amalgamated into Bonterra Energy Corp. Prior to the Arrangement on November 12, 2008, the consolidated financial statements included the accounts of the Trust and its subsidiaries. After giving effect to the Arrangement, the consolidated financial statements have been prepared on a continuity of interest basis, which recognizes Bonterra Oil & Gas Ltd. as the successor entity to the Trust. The continuity of interest basis requires that the 2007 comparative consolidated financial statement figures are those previously presented by the Trust. The continuity of interest basis requires that the 2007 comparative consolidated financial statement figures are those previously presented by the Trust. 2. SIGNIFICANT ACCOUNTING pOLICIES Basis of presentation Consolidation are eliminated upon consolidation. Measurement Uncertainty The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles (GAAP) as described below. These consolidated financial statements include the accounts of the “Company”, the Trust (wholly owned by the Company) and its wholly owned subsidiary Bonterra Energy Corp. (Bonterra). Inter-company transactions and balances The preparation of financial statements in conformity 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 and accretion costs and amounts used for ceiling test 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. Revenues associated with sales of petroleum and natural gas are recorded when title passes to the customer. revenue recognition 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. International Financial reporting Standards (IFrS) The Accounting Standards Board (AcSB) has announced that Canadian GAAP, as we currently know them, will cease to exist for all Publicly Accountable Entities (PAE’s) as of January 1, 2011. From that point onward the Company will be required to account for and report under IFRS. Although the International Accounting Standards Board (IASB) intends to revise several standards between now and 2011, IFRS will be adopted in Canada utilizing a “big bang” approach, with the exception of some Canadian GAAP changes that have occurred or will occur in periods leading up to the transition date. The IASB has undertaken a number of projects, many being joint projects with the Financial Accounting Standards Board in the U.S., that may significantly change existing international standards. This degree of activity currently being undertaken by the standard setters makes the convergence from Canadian GAAP to IFRS a moving target. Due to these likely changes, careful monitoring of developments will be required in order to understand fully the accounting and business implications of the new requirements. The Company in the fourth quarter of 2008 has commenced the process of conversion to IFRS by engaging its external auditors to perform a preliminary high-level scoping study to consider the potential impact of the implementation of IFRS on the Company. Based on the findings to date the following areas have been identified as 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 The impact of IFRS will be significant; however the Company has always maintained an accounting policy of successful efforts for property and equipment that will result in a major reduction in the level of conversion compared to most oil and gas companies who used the full cost accounting policy. Over the course of 2009, the Company will be completing a more detailed analysis of the above areas and making decisions in respect of accounting policies that will be followed in respect of the above identified areas, documenting those policies, and calculating the impact of those policies on existing financial statement items and presentations. The Company has recently implemented a new financial accounting system that provides for sufficient detail to comply with the IFRS requirements. As the Company has been using successful efforts since its inception, detail at a well level has been maintained under its past and current financial accounting systems as well as procedures are in place to capture this information at the operational level. 26 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 15 Implications to the Company’s controls for DC&P and ICFR are being reviewed; however the Company believes that the majority of the procedures in place will apply once IFRS is implemented. Training will be required and is ongoing. Individuals within the Company have been and will continue to attend courses, seminars and other training activities to ensure the Company is adequately prepared for IFRS. Use of external legal expertise will be used to ensure compliance is maintained with all contractual agreements. LIQUIDITY AND CApITAL rESOUrCES During 2008, Bonterra participated in drilling 44 gross wells (30.9 net) at a total cost of $29,466,000. Included in the above figure is approximately $1,200,000 of costs associated with the completion and tie-in of wells the Company drilled in 2007 and prior years. As discussed in the Production section, only four gross oil wells (3.2 net) were not on production by December 31, 2008. These wells have subsequently been placed on production at a capital cost of less than $1,000,000 being spent in 2009. The Company currently has plans to drill approximately 30 gross (18 net) oil and gas wells in 2009 at an estimated budget figure of $15,000,000. The current plan, if Alberta suitably adjusts its royalty structure, includes 18 gross (14 net) Cardium vertical oil wells and two gross (0.65 net) Cardium horizontal oil wells. The balance of the drilling is anticipated to consist of wells in BC and Saskatchewan. The majority of the drilling is anticipated to occur during the third and fourth quarters due in part to the Company’s position that it is prudent to wait for the Alberta government to disclose its incentive programs and potential modifications to its high royalty rates so that Alberta will be competitive for certain types of wells. Bonterra anticipates funding the 2009 capital program out of cash flow and if necessary an increase in the Company’s line of credit. Should the need arise, the Company is prepared to raise sufficient equity to complete its planned capital expenditures. However, the current capital budget is predicated on commodity prices recovering to above $50 U.S. for crude oil and $6 per MCF for natural gas and an $0.82 dollar for the last six months of 2009. Bonterra is continuing with its efforts to acquire producing and non producing properties through either property or entity acquisitions. Funding for any acquisition would depend on items such as the type of acquisition, quality of the assets, size of the purchase and Bonterra’s trading price at the time of the acquisition. Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of an $80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December 31, 2007 - $69,900,000) (non-syndicated demand facility). The terms of the syndicated revolving credit facility provide that the loan is revolving to May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment requirements. The terms of the non-syndicated demand credit facility provide that the loan is due on demand and is subject to annual review and has no fixed repayment terms. At December 31, 2008 the Company had bank debt of $93,235,000 (2007 – $57,422,000). For the interest rates charged on the facilities please refer to the Interest Expense section of this MD&A. The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit totaling $525,000 (December 31, 2007 - $355,000) were issued at December 31, 2008. Of the letters of credit, $20,000 is secured by a restricted term deposit. 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 facility contains few covenants due to the substantial asset value (see review of operations) of the Company’s assets and the long business relationship established by the Company with its principal banker. The following is a list of the material covenants: • The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes negative working capital but excludes debt to related parties). • Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as defined under GAAP. CONSOLIDATED STATEMENTS OF CASh FLOw For the Years Ended December 31 ($000) Operating Activities Net earnings for the year Items not affecting cash (Gain) loss on risk management contracts - non-cash Stock-based compensation Dry hole costs Depletion, depreciation and accretion Future income taxes Change in non-cash working capital Accounts receivable Crude oil inventory Prepaid expenses Accounts payable and accrued liabilities Asset retirement obligations settled Financing Activities Increase in debt Due to related party Stock option proceeds Unit distributions Dividends Investing Activities Property and equipment expenditures Acquisition (Note 5) Reorganization (Note 4) Restricted term deposit Change in non-cash working capital Accounts receivable Accounts payable and accrued liabilities Net cash inflow Cash, beginning of year Cash, End of Year Cash Interest Paid Cash Taxes Paid 2008 2007 $ 55,426 $ 30,350 (3,085) 1,207 – 14,749 2,151 70,448 2,642 (40) (360) (57) (3,063) (878) 69,570 20,698 6,000 7,935 (46,384) (7,938) (19,689) (30,060) (13,816) (11,257) 20 5,272 (49,881) – – – 3,085 1,133 3,078 13,597 2,572 53,815 (1,082) 51 (262) (269) (820) (2,382) 51,433 12,043 – 993 (44,974) (31,938) (19,300) 993 (1,188) (19,495) – – – – – – – 3,028 292 $ $ $ – $ 2,740 $ 582 $ 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 16 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 25 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 CONSOLIDATED STATEMENTS OF COMprEhENSIvE INCOME For the Years Ended December 31 ($000) Net Earnings for the period Other comprehensive income, net of income tax Unrealized (loss) gain on investments (net of income taxes of $(272), (2007 - $252)) Gains and losses on derivatives designated as cash flow hedges transferred to net earnings (net of income taxes of ($334)) Other Comprehensive Income (Loss) Comprehensive Income Comprehensive Income per Share – Basic (Note 13) Comprehensive Income per Share – Diluted (Note 13) 2008 $ 55,426 $ 2007 30,350 (1,611) 1,465 – (1,611) 53,815 $ 3.15 $ 3.14 $ (814) 651 31,001 1.83 1.83 $ $ $ The Company is authorized to issue an unlimited number of common shares without nominal or par value. ($000) Issued Common Shares Balance, beginning of year Issued on reorganization to a corporation Balance, end of year ($000) Issued Trust Units Balance, beginning of year Transfer of contributed surplus to unit capital Issued pursuant to Trust unit option plan Issued on acquisition of Silverwing Cancelled on conversion to a corporation Balance, end of year 2008 2007 Number Amount Number Amount – $ 17,257,603 – 99,530 17,257,603 $ 99,530 2008 – $ – – $ 2007 – – – Number Amount Number Amount 16,928,158 $ – 321,700 7,745 (17,257,603) 90,590 805 7,935 200 (99,530) 16,874,658 $ – 53,500 – – – $ – 16,928,158 $ 89,488 109 993 – – 90,590 The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). 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, 2008 and changes during the year is presented below: Outstanding at beginning of year Options granted Outstanding at end of year Options exercisable at end of year 2008 weighted- Average Options Exercise price – $ 1,390,500 1,390,500 $ – $ – 20.50 20.50 – The following table summarizes information about common stock options outstanding at December 31, 2008: Options Outstanding Options Exercisable Range of Exercise Prices $20.50 Oustanding At 12/31/08 1,390,500 Number Weighted-Average Remaining Weighted-Average Exercise Price Contractual Life Number Exercisable Weighted-Average At 12/31/08 Exercise Price 3.9 years $ 20.50 – $ – 24 BONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 17 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is presented below: Outstanding at beginning of year Options granted Options exercised Options cancelled Outstanding at end of year Options exercisable at end of year 2008 weighted- Average Exercise price Options 2007 Weighted- Average Options Exercise Price 1,177,000 $ 29,000 (321,700) (884,300) – $ – $ 27.59 39.09 24.66 29.03 – – 721,500 $ 553,000 (53,500) (44,000) 1,177,000 $ 530,000 $ 26.55 28.11 18.56 27.92 27.59 26.63 BUSINESS prOSpECTS, rISkS, AND OUTLOOkS The resource industry operates with a great deal of risk. The most significant risks may come from oil and natural gas price swings, the uncertainty of finding new reserves from drilling programs or acquisitions, competition within the industry and increasing environmental controls and regulations. The prices received for crude oil are established by world market forces and for natural gas by forces within North America. Fluctuations in pricing can have extremely positive or negative effects on the Company’s cash flow or in the value of its producing and non-producing oil and natural gas properties. The Company presently attempts to minimize these risks by pursuing both oil and natural gas activities and operates its oil and natural gas interests in areas which have long life reserves, where it has the technical expertise to enhance production, control operating costs and to increase margins of profit. SENSITIvITY ANALYSIS Sensitivity analysis, as estimated for 2009: U.S. $1.00 per barrel Canadian $0.10 per MCF Change of Canadian $0.01/U.S. $ exchange rate ADDITIONAL INFOrMATION Cash Flow 870,000 $ 289,000 $ 593,000 $ $ $ $ Cash Flow Per Share 0.050 0.017 0.034 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. CONSOLIDATED STATEMENTS OF OpErATIONS AND DEFICIT For the Years Ended December 31 ($000) revenue Oil and gas sales Gain (loss) on risk management contracts - cash Gain (loss) on risk management contracts - non-cash Royalties Interest and other Expenses Production costs General and administrative Interest on debt Reorganization costs (Note 4) Stock-based compensation Dry hole costs Depletion, depreciation and accretion Earnings Before Taxes Taxes (Note 11) Current Future Net Earnings for the Year Deficit, beginning of year Distributions declared Dividends declared Deficit, end of year Net Earnings per Share – Basic (Note 13) Net Earnings per Share – Diluted (Note 13) 2008 2007 $ 129,083 $ (7,353) 3,085 (17,215) 45 107,645 25,413 3,401 2,740 2,121 1,207 – 14,749 49,631 58,014 437 2,151 2,588 55,426 (51,543) (42,660) (7,938) 3.25 $ 3.23 $ 95,810 621 (3,085) (12,444) 44 80,946 24,073 2,603 3,028 – 1,133 3,078 13,597 47,512 33,434 512 2,572 3,084 30,350 (37,245) (44,648) – 1.79 1.79 (46,715) $ (51,543) $ $ $ 18 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 23 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 CONSOLIDATED STATEMENTS OF ShArEhOLDErS’ EQUITY MANAGEMENT’S rESpONSIBILITY FOr FINANCIAL STATEMENTS For the Years Ended December 31 ($000) Unitholders’ equity, beginning of year Comprehensive income for the year Adjustment of opening accumulated other comprehensive income Net capital contributions (Note 13) Stock-based compensation Distributions declared Conversion of the Trust to a Corporation (Note 4) Unitholders’ Equity Dividends declared $ 2008 44,218 $ 53,815 – 8,135 1,207 (42,660) 64,715 – (7,938) 2007 53,359 31,001 2,380 993 1,133 (44,648) 44,218 (44,218) – – Shareholders’ Equity, End of Year $ 56,777 $ The information provided in this report, including the financial statements, is the responsibility of management. In the preparation of the statements, estimates are sometimes necessary to make a determination of future values for certain assets or liabilities. Management believes such estimates have been based on careful judgements and have been properly reflected in the accompanying financial statements. Management maintains a system of internal controls to provide reasonable assurance that the Company’s assets are safeguarded and to facilitate the preparation of relevant and timely information. Deloitte & Touche LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They have examined the financial statements and provided their auditors’ report. The audit committee has reviewed these financial statements with management and the auditors, and has reported to the Board of Directors. The Board of Directors has approved the financial statements as presented in this annual report. GEOrGE F. FINk CEO March 11, 2009 GArTh E. SChULTz vice president, Finance and CFO March 11, 2009 22 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 19 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 AUDITOrS’ rEpOrT CONSOLIDATED BALANCE ShEETS To the Shareholders of Bonterra Oil & Gas Ltd. (formerly Bonterra Energy Income Trust): We have audited the consolidated balance sheets of Bonterra Oil & Gas Ltd. as at December 31, 2008 and 2007 and the consolidated statements of shareholders’ equity, operations and deficit, comprehensive income and cash flow for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2008 and 2007 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. As at December 31 ($000) ASSETS Current Restricted term deposit (Note 10) Accounts receivable (Notes 4 & 15) Crude oil inventory Prepaid expenses (Note 4) Future income tax asset (Note 11) Investment in related party (Note 6) Restricted cash (Note 7) Future income tax asset (Note 11) property and Equipment (Note 8) Chartered Accountants Calgary, Alberta March 11, 2009 2008 2007 $ 20 $ $ 265,301 $ $ – $ 11,753 845 4,222 2,669 2,131 21,640 1,252 85,416 232,685 (75,692) 156,993 23,888 – 6,000 2,305 13,325 45,518 79,910 – 64,758 18,338 208,524 99,530 – 2,542 102,072 (46,715) 1,420 (45,295) 56,777 – 10,575 792 1,462 913 4,014 17,756 – – 187,288 (61,805) 125,483 143,239 3,724 12,291 3,085 – – – – 57,422 76,522 7,595 14,904 99,021 – 90,590 2,140 92,730 (51,543) 3,031 (48,512) 44,218 143,239 $ 265,301 $ Petroleum and natural gas properties and related equipment Accumulated depletion and depreciation LIABILITIES Current Distribution payable Accounts payable and accrued liabilities (Note 4) Derivative liability (Note 16) Due to related party (Note 9) Deferred credit (Note 11) Short-term bank debt (Note 10) Long-term bank debt (Note 10) Future income tax liability (Note 11) Deferred credit (Note 11) Asset retirement obligations (Note 12) Commitments, Contingencies and Guarantees (Note 17) ShArEhOLDErS’ EQUITY (Note 13) Share capital Unit capital Contributed surplus Deficit Accumulated other comprehensive income (Note 14) Total Shareholders’ Equity On behalf of the Board: Director Director 20 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 21 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 AUDITOrS’ rEpOrT CONSOLIDATED BALANCE ShEETS To the Shareholders of Bonterra Oil & Gas Ltd. (formerly Bonterra Energy Income Trust): We have audited the consolidated balance sheets of Bonterra Oil & Gas Ltd. as at December 31, 2008 and 2007 and the consolidated statements of shareholders’ equity, operations and deficit, comprehensive income and cash flow for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2008 and 2007 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. Chartered Accountants Calgary, Alberta March 11, 2009 As at December 31 ($000) ASSETS Current Restricted term deposit (Note 10) Accounts receivable (Notes 4 & 15) Crude oil inventory Prepaid expenses (Note 4) Future income tax asset (Note 11) Investment in related party (Note 6) Restricted cash (Note 7) Future income tax asset (Note 11) property and Equipment (Note 8) Petroleum and natural gas properties and related equipment Accumulated depletion and depreciation LIABILITIES Current Distribution payable Accounts payable and accrued liabilities (Note 4) Derivative liability (Note 16) Due to related party (Note 9) Deferred credit (Note 11) Short-term bank debt (Note 10) Long-term bank debt (Note 10) Future income tax liability (Note 11) Deferred credit (Note 11) Asset retirement obligations (Note 12) Commitments, Contingencies and Guarantees (Note 17) ShArEhOLDErS’ EQUITY (Note 13) Share capital Unit capital Contributed surplus Deficit Accumulated other comprehensive income (Note 14) Total Shareholders’ Equity On behalf of the Board: Director Director 2008 2007 $ 20 $ 11,753 845 4,222 2,669 2,131 21,640 1,252 85,416 232,685 (75,692) 156,993 $ 265,301 $ $ – $ 23,888 – 6,000 2,305 13,325 45,518 79,910 – 64,758 18,338 208,524 99,530 – 2,542 102,072 (46,715) 1,420 (45,295) 56,777 $ 265,301 $ – 10,575 792 1,462 913 4,014 17,756 – – 187,288 (61,805) 125,483 143,239 3,724 12,291 3,085 – – 57,422 76,522 – 7,595 – 14,904 99,021 – 90,590 2,140 92,730 (51,543) 3,031 (48,512) 44,218 143,239 20 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 21 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 CONSOLIDATED STATEMENTS OF ShArEhOLDErS’ EQUITY MANAGEMENT’S rESpONSIBILITY FOr FINANCIAL STATEMENTS For the Years Ended December 31 ($000) Unitholders’ equity, beginning of year Comprehensive income for the year Adjustment of opening accumulated other comprehensive income Net capital contributions (Note 13) Stock-based compensation Distributions declared Unitholders’ Equity Conversion of the Trust to a Corporation (Note 4) Dividends declared Shareholders’ Equity, End of Year $ 2008 44,218 $ 53,815 – 8,135 1,207 (42,660) 64,715 – (7,938) $ 56,777 $ 2007 53,359 31,001 2,380 993 1,133 (44,648) 44,218 (44,218) – – The information provided in this report, including the financial statements, is the responsibility of management. In the preparation of the statements, estimates are sometimes necessary to make a determination of future values for certain assets or liabilities. Management believes such estimates have been based on careful judgements and have been properly reflected in the accompanying financial statements. Management maintains a system of internal controls to provide reasonable assurance that the Company’s assets are safeguarded and to facilitate the preparation of relevant and timely information. Deloitte & Touche LLP has been appointed by the Shareholders to serve as the Company’s external auditors. They have examined the financial statements and provided their auditors’ report. The audit committee has reviewed these financial statements with management and the auditors, and has reported to the Board of Directors. The Board of Directors has approved the financial statements as presented in this annual report. GEOrGE F. FINk CEO March 11, 2009 GArTh E. SChULTz vice president, Finance and CFO March 11, 2009 22 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 19 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is presented below: CONSOLIDATED STATEMENTS OF OpErATIONS AND DEFICIT For the Years Ended December 31 ($000) revenue Oil and gas sales Gain (loss) on risk management contracts - cash Gain (loss) on risk management contracts - non-cash Royalties Interest and other Expenses Production costs General and administrative Interest on debt Reorganization costs (Note 4) Stock-based compensation Dry hole costs Depletion, depreciation and accretion Earnings Before Taxes Taxes (Note 11) Current Future Net Earnings for the Year Deficit, beginning of year Distributions declared Dividends declared Deficit, end of year Net Earnings per Share – Basic (Note 13) Net Earnings per Share – Diluted (Note 13) 2008 2007 $ 129,083 $ (7,353) 3,085 (17,215) 45 107,645 25,413 3,401 2,740 2,121 1,207 – 14,749 49,631 58,014 437 2,151 2,588 55,426 (51,543) (42,660) (7,938) (46,715) $ 3.25 $ 3.23 $ $ $ $ 95,810 621 (3,085) (12,444) 44 80,946 24,073 2,603 3,028 – 1,133 3,078 13,597 47,512 33,434 512 2,572 3,084 30,350 (37,245) (44,648) – (51,543) 1.79 1.79 Outstanding at beginning of year Options granted Options exercised Options cancelled Outstanding at end of year Options exercisable at end of year 2008 weighted- Average 2007 Weighted- Average Options Exercise price Options Exercise Price 1,177,000 $ 29,000 (321,700) (884,300) – $ – $ 27.59 39.09 24.66 29.03 – – 721,500 $ 553,000 (53,500) (44,000) 1,177,000 $ 530,000 $ 26.55 28.11 18.56 27.92 27.59 26.63 BUSINESS prOSpECTS, rISkS, AND OUTLOOkS The resource industry operates with a great deal of risk. The most significant risks may come from oil and natural gas price swings, the uncertainty of finding new reserves from drilling programs or acquisitions, competition within the industry and increasing environmental controls and regulations. The prices received for crude oil are established by world market forces and for natural gas by forces within North America. Fluctuations in pricing can have extremely positive or negative effects on the Company’s cash flow or in the value of its producing and non-producing oil and natural gas properties. The Company presently attempts to minimize these risks by pursuing both oil and natural gas activities and operates its oil and natural gas interests in areas which have long life reserves, where it has the technical expertise to enhance production, control operating costs and to increase margins of profit. SENSITIvITY ANALYSIS Sensitivity analysis, as estimated for 2009: U.S. $1.00 per barrel Canadian $0.10 per MCF Change of Canadian $0.01/U.S. $ exchange rate ADDITIONAL INFOrMATION at www.bonterraenergy.com. Cash Flow 870,000 $ 289,000 $ 593,000 $ $ $ $ Cash Flow Per Share 0.050 0.017 0.034 Additional information relating to the Company may be found on www.sedar.com as well as on the Company’s website 18 BONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 23 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 3 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 CONSOLIDATED STATEMENTS OF COMprEhENSIvE INCOME The Company is authorized to issue an unlimited number of common shares without nominal or par value. 2008 2007 Number Amount Number Amount For the Years Ended December 31 ($000) Net Earnings for the period Other comprehensive income, net of income tax Unrealized (loss) gain on investments (net of income taxes of $(272), (2007 - $252)) Gains and losses on derivatives designated as cash flow hedges transferred to net earnings (net of income taxes of ($334)) Other Comprehensive Income (Loss) Comprehensive Income Comprehensive Income per Share – Basic (Note 13) Comprehensive Income per Share – Diluted (Note 13) 2008 $ 55,426 $ 2007 30,350 (1,611) 1,465 – (1,611) 53,815 $ 3.15 $ 3.14 $ (814) 651 31,001 1.83 1.83 $ $ $ ($000) Issued ($000) Issued Trust Units Common Shares Balance, beginning of year Issued on reorganization to a corporation 17,257,603 Balance, end of year 17,257,603 $ 99,530 – $ – 99,530 – $ – – $ 2007 2008 Number Amount Number Amount Balance, beginning of year Transfer of contributed surplus to unit capital Issued pursuant to Trust unit option plan Issued on acquisition of Silverwing 16,928,158 $ – 321,700 7,745 90,590 805 7,935 200 Cancelled on conversion to a corporation (17,257,603) (99,530) 53,500 – – – 16,874,658 $ 89,488 Balance, end of year – $ – 16,928,158 $ 90,590 The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). 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 A summary of the status of the Company’s stock option plan as of December 31, 2008 and changes during the year is five years. presented below: 2008 weighted- Average Options Exercise price – $ 1,390,500 1,390,500 $ – $ 20.50 20.50 Outstanding at beginning of year Options granted Outstanding at end of year Options exercisable at end of year The following table summarizes information about common stock options outstanding at December 31, 2008: Options Outstanding Options Exercisable Range of Exercise Prices $20.50 Number Weighted-Average Number Oustanding At 12/31/08 1,390,500 Remaining Weighted-Average Exercisable Weighted-Average Contractual Life Exercise Price At 12/31/08 Exercise Price 3.9 years $ 20.50 – $ – – – 109 993 – – – – – 24 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 17 Implications to the Company’s controls for DC&P and ICFR are being reviewed; however the Company believes that the majority of the procedures in place will apply once IFRS is implemented. Training will be required and is ongoing. Individuals within the Company have been and will continue to attend courses, seminars and other training activities to ensure the Company is adequately prepared for IFRS. Use of external legal expertise will be used to ensure compliance CONSOLIDATED STATEMENTS OF CASh FLOw is maintained with all contractual agreements. LIQUIDITY AND CApITAL rESOUrCES During 2008, Bonterra participated in drilling 44 gross wells (30.9 net) at a total cost of $29,466,000. Included in the above figure is approximately $1,200,000 of costs associated with the completion and tie-in of wells the Company drilled in 2007 and prior years. As discussed in the Production section, only four gross oil wells (3.2 net) were not on production by December 31, 2008. These wells have subsequently been placed on production at a capital cost of less than $1,000,000 being spent in 2009. The Company currently has plans to drill approximately 30 gross (18 net) oil and gas wells in 2009 at an estimated budget figure of $15,000,000. The current plan, if Alberta suitably adjusts its royalty structure, includes 18 gross (14 net) Cardium vertical oil wells and two gross (0.65 net) Cardium horizontal oil wells. The balance of the drilling is anticipated to consist of wells in BC and Saskatchewan. The majority of the drilling is anticipated to occur during the third and fourth quarters due in part to the Company’s position that it is prudent to wait for the Alberta government to disclose its incentive programs and potential modifications to its high royalty rates so that Alberta will be competitive for certain types of wells. Bonterra anticipates funding the 2009 capital program out of cash flow and if necessary an increase in the Company’s line of credit. Should the need arise, the Company is prepared to raise sufficient equity to complete its planned capital expenditures. However, the current capital budget is predicated on commodity prices recovering to above $50 U.S. for crude oil and $6 per MCF for natural gas and an $0.82 dollar for the last six months of 2009. Bonterra is continuing with its efforts to acquire producing and non producing properties through either property or entity acquisitions. Funding for any acquisition would depend on items such as the type of acquisition, quality of the assets, size of the purchase and Bonterra’s trading price at the time of the acquisition. Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of an $80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December 31, 2007 - $69,900,000) (non-syndicated demand facility). The terms of the syndicated revolving credit facility provide that the loan is revolving to May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment requirements. The terms of the non-syndicated demand credit facility provide that the loan is due on demand and is subject to annual review and has no fixed repayment terms. At December 31, 2008 the Company had bank debt of $93,235,000 (2007 – $57,422,000). For the interest rates charged on the facilities please refer to the Interest Expense section of this MD&A. The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit totaling $525,000 (December 31, 2007 - $355,000) were issued at December 31, 2008. Of the letters of credit, $20,000 is secured by a restricted term deposit. 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 facility contains few covenants due to the substantial asset value (see review of operations) of the Company’s assets and the long business relationship established by the Company with its principal banker. The following is a list of the material covenants: • The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes negative working capital but excludes debt to related parties). • Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as defined under GAAP. For the Years Ended December 31 ($000) Operating Activities Net earnings for the year Items not affecting cash (Gain) loss on risk management contracts - non-cash Stock-based compensation Dry hole costs Depletion, depreciation and accretion Future income taxes Change in non-cash working capital Accounts receivable Crude oil inventory Prepaid expenses Accounts payable and accrued liabilities Asset retirement obligations settled Financing Activities Increase in debt Due to related party Stock option proceeds Unit distributions Dividends Investing Activities Property and equipment expenditures Acquisition (Note 5) Reorganization (Note 4) Restricted term deposit Change in non-cash working capital Accounts receivable Accounts payable and accrued liabilities Net cash inflow Cash, beginning of year Cash, End of Year Cash Interest Paid Cash Taxes Paid 2008 2007 $ 55,426 $ 30,350 (3,085) 1,207 – 14,749 2,151 70,448 2,642 (40) (360) (57) (3,063) (878) 69,570 20,698 6,000 7,935 (46,384) (7,938) (19,689) (30,060) (13,816) (11,257) 20 – 5,272 (49,881) – – – $ 3,085 1,133 3,078 13,597 2,572 53,815 (1,082) 51 (262) (269) (820) (2,382) 51,433 12,043 – 993 (44,974) – (31,938) (19,300) – – – 993 (1,188) (19,495) – – – 2,740 $ 582 $ 3,028 292 $ $ $ 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 16 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 25 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 NOTES TO ThE CONSOLIDATED FINANCIAL STATEMENTS For the Years Ended December 31, 2008 and 2007 1. ChANGE OF OrGANIzATION On November 12, 2008, Bonterra Energy Income Trust (the “Trust”) converted to Bonterra Oil & Gas Ltd. (the “Company”) through a reverse takeover by the Trust of SRX Post Holdings Inc. (SRX). In conjunction with the reorganization, the Trust acquired all the issued and outstanding shares of Silverwing Energy Inc. (Silverwing). Concurrently, all of the Company’s subsidiaries, including Silverwing were amalgamated into Bonterra Energy Corp. Prior to the Arrangement on November 12, 2008, the consolidated financial statements included the accounts of the Trust and its subsidiaries. After giving effect to the Arrangement, the consolidated financial statements have been prepared on a continuity of interest basis, which recognizes Bonterra Oil & Gas Ltd. as the successor entity to the Trust. The continuity of interest basis requires that the 2007 comparative consolidated financial statement figures are those previously presented by the Trust. The continuity of interest basis requires that the 2007 comparative consolidated financial statement figures are those previously presented by the Trust. 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) and its wholly owned subsidiary Bonterra Energy Corp. (Bonterra). Inter-company transactions and balances are eliminated upon consolidation. Measurement Uncertainty The preparation of financial statements in conformity 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 and accretion costs and amounts used for ceiling test 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. International Financial reporting Standards (IFrS) The Accounting Standards Board (AcSB) has announced that Canadian GAAP, as we currently know them, will cease to exist for all Publicly Accountable Entities (PAE’s) as of January 1, 2011. From that point onward the Company will be required to account for and report under IFRS. Although the International Accounting Standards Board (IASB) intends to revise several standards between now and 2011, IFRS will be adopted in Canada utilizing a “big bang” approach, with the exception of some Canadian GAAP changes that have occurred or will occur in periods leading up to the transition date. The IASB has undertaken a number of projects, many being joint projects with the Financial Accounting Standards Board in the U.S., that may significantly change existing international standards. This degree of activity currently being undertaken by the standard setters makes the convergence from Canadian GAAP to IFRS a moving target. Due to these likely changes, careful monitoring of developments will be required in order to understand fully the accounting and business implications of the new requirements. The Company in the fourth quarter of 2008 has commenced the process of conversion to IFRS by engaging its external auditors to perform a preliminary high-level scoping study to consider the potential impact of the implementation of IFRS on the Company. Based on the findings to date the following areas have been identified as 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 The impact of IFRS will be significant; however the Company has always maintained an accounting policy of successful efforts for property and equipment that will result in a major reduction in the level of conversion compared to most oil and gas companies who used the full cost accounting policy. Over the course of 2009, the Company will be completing a more detailed analysis of the above areas and making decisions in respect of accounting policies that will be followed in respect of the above identified areas, documenting those policies, and calculating the impact of those policies on existing financial statement items and presentations. The Company has recently implemented a new financial accounting system that provides for sufficient detail to comply with the IFRS requirements. As the Company has been using successful efforts since its inception, detail at a well level has been maintained under its past and current financial accounting systems as well as procedures are in place to capture this information at the operational level. 26 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 15 COMMITMENTS as follows: Contract Obligations ($000) Office leases (1) The Company has no contractual obligations that last more than a year other than its office lease agreements which are Total Less than 1 year 1 – 3 years $ 2,907 $ 589 $ 1,238 $ 4 – 5 years 1,080 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 sales price in the month preceding year end. Investments (1) Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds received on the sublease have not been offset against the contractual liability. 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 as at period end. FINANCIAL rEpOrTING UpDATE property and Equipment During 2007, the Company completed the implementation of the new CICA Handbook Section 3855, Financial Instruments – Recognition and Measurement, Section 1530, Comprehensive Income and Section 3865, Hedges that deal with the recognition and measurement of financial instruments at fair value and comprehensive income. See Notes 2 and 14 in the Notes to the audited Consolidated Financial Statements for further details. Accounting Changes During 2008, the Company adopted Section 1535 “Capital Disclosures”, Section 3862, “Financial Instruments - Disclosures” and Section 3863, “Financial Instruments - Presentation”. All the above Sections were required to be adopted for fiscal years beginning on or after October 1, 2007. As a result, the Company has added Note 16 providing the required disclosures regarding the Company’s objectives, policies and processes for managing capital and the significance of financial instruments for the entity’s financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed. Future Accounting Changes In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. This standard establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company does not expect that the adoption of this new Section will have a material impact on its consolidated financial statements. In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the adoption of this statement to have a material impact on the Company’s results of operations or financial position. In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material impact on the results of operations or financial position. 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 and equipment costs are depleted over the remaining proved developed reserves. Depreciation of other plant and equipment is provided on the straight line method. Straight line depreciation is based on the estimated service lives of the related assets which is estimated to be ten years. Furniture, Fixtures and Office Equipment These assets are recorded at cost and depreciated over a three to ten year period representing their estimated useful lives. Income Taxes 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. 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 14 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 27 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 3 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 Stock-Based Compensation FINDING AND DEvELOpMENT COSTS (F&D COSTS) 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, 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 assets 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. Cash and restricted cash are classified as held-for-trading and are measured at fair value which equals the carrying value and any gains or losses are recognized in earnings in the period they occur. Accounts receivable are classified as loans and receivables which are measured at amortized costs. 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 and bank debt 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 determined from 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 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 year ended December 31, 2008, the Company did not designate any of its financial instruments as hedges. There are no risk management contracts outstanding as at December 31, 2008. The Company has been active in its capital development program over the past three years. Over this time period Bonterra has incurred the following F&D Costs: 2008 F&D 2007 F&D 2006 F&D 2008 2007 Costs per Costs per Costs per Three Year Three Year BOE (1)(2) BOE (1)(2) BOE (1)(2) Average Average Proved Reserve Additions Proved plus Probable Reserve Additions $ $ 8.67 $ 7.47 $ 2.74 $ 2.68 $ 25.51 $ 18.21 $ 12.30 $ 9.45 $ 14.37 11.07 The above figures have been calculated in accordance with National Instrument 51-101 (NI 51-101) where the F&D Costs equate to the total exploration and development costs incurred by the Company during the year plus the yearly change in estimated future development costs as calculated by Sproule Associates Limited. The following precautionary notes have been provided as required by NI 51-101. (1) Barrels of Oil Equivalent may be misleading, particularly if used in isolation. A BOE conversion ratio of 6MCF:1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. (2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. Results from the Company’s Cardium oil drilling program continue to be better than anticipated resulting in an increase in the third party engineering reports estimated recoverable reserves from existing wells but also from future development. Continued low decline rates have also resulted in increased reserves due to technical revisions. Both these factors contributed to an overall F&D cost in 2008 of $7.47 per BOE on a proved plus probable basis. rELATED pArTY TrANSACTIONS The Company holds 689,682 (2007 – 689,682) common shares in Comaplex which have a fair market value as of December 31, 2008 of $2,131,000 (2007 - $4,014,000). Comaplex is a publically traded mineral company on the Toronto Stock Exchange. The Company’s ownership in Comaplex represents approximately 1.3 percent of the issued and outstanding common shares of Comaplex. The Company has common directors and management with Comaplex. Comaplex paid a management fee to the Company of $330,000 (2007 - $300,000). Comaplex also shares office rental costs and reimburses the Company for costs related to employee benefits and office materials. In addition, Comaplex owns 204,633 (December 31, 2007 – 204,633) common shares in the Company. Services provided by the Company include executive services (president and vice president, finance duties), accounting services, oil and gas administration and office administration. All services performed are charged at estimated fair value. At December 31, 2008, Comaplex owed the Company $56,000 (December 31, 2007 - $63,000). In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total interest paid on the loan was $21,000. The Company also has a management agreement with Pine Cliff. Pine Cliff has common directors and management with the Company. Pine Cliff trades on the TSX Venture Exchange. Pine Cliff paid a management fee to the Company of $238,000 (2007 - $216,000). Services provided by the Company include executive services (president and vice president, finance duties), accounting services, oil and gas administration and office administration. All services performed are charged at estimated fair value. The Company has no share ownership in Pine Cliff. As at December 31, 2008 the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2007 – $4,000). As of December 31, 2008, the Company’s CEO and major shareholder had loaned the Company $6,000,000. The loan is unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment terms. The loan can only be repaid should the Company have sufficient available borrowing limits within its bank debt. Interest paid on this loan during 2008 was $7,000. 28 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 13 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 2 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 Other comprehensive income for 2008 consists of an unrealized loss on investment in a related party of $1,611,000 (2007 gain of $1,465,000) including a fourth quarter loss of $1,123,000 relating to a reduction in the related company’s fair value. Effective October 1, 2007, the Company discontinued the use of hedge accounting due to the difficulty in determining the effective portion of the commodity risk management contracts. Basic and Diluted per Share (formerly per Unit) Calculations Basic earnings per share are computed by dividing earnings by the weighted average number of shares outstanding during the year. Diluted per share amounts reflect the potential dilution that could occur if options to purchase shares were exercised. The treasury stock method is used to determine the dilutive effect of common share options, whereby proceeds from the exercise of common share options or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period. Cash flow from operations 10,336 22,492 13,369 69,570 51,433 Capital Disclosures Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 3. NEw ACCOUNTING pOLICIES CASh FLOw FrOM OpErATIONS ($ 000) Cash flow from operations increased 35 percent year over year, mainly due to increased commodity prices received during the first nine months of 2008. The fourth quarter of 2008 saw significant price declines in all commodity categories. Although the Company was able to increase production in the fourth quarter of 2008 by almost nine percent over the previous quarter, cash flow from operations decreased approximately 54 percent. One time costs of $1,369,000 incurred in Q4 (Q3 - $752,000) related to the reorganization also contributed to the decline. With the continuing depressed crude oil and natural gas prices, cash flow for 2009 is expected to be significantly negatively affected. The price declines are expected to be partially offset by anticipated production volumes in excess of 5,000 BOE per day for 2009, and anticipated decreases in G&A costs (lower employee compensation) and in corporate resource surcharge (tax on revenues). Also, Bonterra does not expect any further costs associated with the acquisition of Silverwing or the reorganization. CASh NETBACkS The following table illustrates the Company’s cash netback: $ per Barrel of Oil Equivalent (BOE) Production volumes (BOE) Gross production revenue Realized gain (loss) on risk management contracts Royalties Field operating Field netback General and administrative Interest and taxes Cash netback $ per Barrel of Oil Equivalent (BOE) Production volumes (BOE) Gross production revenue Realized gain (loss) on risk management contracts Royalties Field operating Field netback General and administrative Interest and taxes Cash netback The following table illustrates the Company’s cash netback for the three months ended: 2008 2007 1,590,666 1,539,461 $ 81.15 $ $ 45.59 $ December 31, September 30, 2008 422,008 2008 395,962 $ (4.62) (10.82) (15.98) 49.73 (2.14) (2.00) 51.27 $ 2.31 (6.86) (16.25) 30.47 (1.95) (1.90) 62.24 0.40 (8.08) (15.64) 38.92 (1.69) (2.30) 34.93 95.80 (7.60) (12.00) (15.84) 60.36 (2.18) (1.73) 56.45 $ 26.62 $ Effective January 1, 2008, the Company prospectively adopted the Canadian Institute of Chartered Accountants (CICA) Section 1535, “Capital Disclosures” which establishes standards for disclosing information about the Company’s capital and how it is managed. It requires disclosures of the Company’s objectives, policies and processes for managing capital, the quantitative data about what the Company regards as capital, whether the Company has complied with any capital requirements and if it has not complied, the consequences of such non-compliance. The only effect of adopting this standard is disclosures about the Company’s capital and how it is managed (see Note 16). Financial Instruments Disclosures and presentation Effective January 1, 2008, the Company prospectively adopted Section 3862, “Financial Instruments – Disclosures” and Section 3863, “Financial Instruments – Presentation.” These new accounting standards replaced Section 3861, “Financial Instruments – Disclosure and Presentation.” Section 3862 requires additional information regarding the significance of financial instruments for the entity’s financial position and performance, and the nature, extent and management of risks arising from financial instruments to which the entity is exposed. The additional disclosures required under these standards are included in Note 16. recent Accounting pronouncements In February 2008, the CICA issued Section 3064, “Goodwill and Intangible Assets”, replacing Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. The Company adopted these standards for its fiscal year beginning January 1, 2009 with no impact on its consolidated financial statements. In January 2009, the CICA issued Section 1582, “Business Combinations”, which replaces former guidance on business combinations. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier adoption permitted. The Company plans to adopt this standard prospectively effective January 1, 2009 and does not expect the adoption of this statement to have a material impact on the Company’s results of operations or financial position. In January 2009, the CICA issued Sections 1601, “Consolidated Financial Statements”, and 1602, “Non-controlling Interests”, which replaces existing guidance. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Company plans to adopt these standards effective January 1, 2009 and does not expect the adoption will have a material impact on the results of operations or financial position. The Accounting Standards Board has confirmed the convergence of Canadian GAAP with International Financial Reporting Standards (IFRS) will be effective January 1, 2011. The Company has performed an initial scoping process in order to ensure successful implementation within the required timeframe. The impact on the Company’s consolidated financial statements is not reasonably determinable at this time. Key information will be disclosed as it becomes available during the transition period. 12 BONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 29 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 2 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 4. rEOrGANIzATION The Company has the following tax pools, which may be used to reduce taxable income in future years, limited to the As part of the reorganization of the Trust, SRX acquired all the issued and outstanding trust units of Bonterra Energy Income Trust on a basis of one Trust Unit for one Common Share of SRX. Immediately preceding the reorganization, SRX was in receivership. Prior to the conversion, the Trust advanced $11,257,000 to SRX for settlement of claims pursuant to the CCAA proceedings. Upon completion of the CCAA procedures, SRX was owed $2,224,000 in outstanding tax and legal claims that will be used by the CCAA Monitor to settle secured creditor claims. This amount has been recorded as an outstanding account receivable by the Company. In addition, SRX paid an advance of $1,800,000 to the CCAA Monitor for costs and payment of the unsecured creditors. This amount has been recorded as a prepaid expense in the accounts of the Company. Included in accounts payable is $4,024,000 to account for the amount due to the secured and unsecured creditors. Of the tax claims, $66,000 had been received and repaid to the Monitor by December 31, 2008. In addition, $99,000 of expense claims had been paid by the Monitor and deducted from the advance. 5. BUSINESS COMBINATION On November 12, 2008, the Company acquired all the common shares of Silverwing for cash consideration of $13,816,000 (including acquisition costs of $334,000) plus the issuance of 7,745 common shares at a value of $25.85 per common share plus the assumption of $14,979,000 of negative working capital. The results of Silverwing’s operations have been included in the consolidated financial statements since that date. The acquisition was funded through the Company’s new bank facility (see Note 10). 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: Cost of acquisition (000’s) Cash paid Value of common stock Acquisition costs Allocation of purchase price: Restricted cash Future income tax benefit Property and equipment Working capital deficiency Asset retirement obligations $ $ $ $ 13,482 200 334 14,016 1,252 18,325 15,347 (14,979) (5,929) 14,016 6. INvESTMENT IN rELATED pArTY The investment consists of 689,682 (December 31, 2007 – 689,682) common shares in Comaplex Minerals Corp (Comaplex), a company with common directors and management with the Company and its subsidiaries. The investment is recorded at fair market value. The common shares trade on the Toronto Stock Exchange under the symbol CMF. The investment represents less than a one and a half percent ownership in the outstanding shares of Comaplex. 7. rESTrICTED CASh An escrow account was held by Silverwing prior to its acquisition by the Company. The escrow account was created to support eligible expenditures related to a farm-in agreement. The Company may access the funds upon completion and tie-in or abandonment and reclamation of 20 wells. The funds are administered by the farmors’ legal counsel. The funds in the escrow account are invested in interest bearing term deposits. Rate of Utilization % Amount 20-100 $ 7 20 10 30 100 100 100 23,696 1,870 4,581 25,072 50,743 10,530 80,357 271,029 $ 467,878 Percentage 85.16 14.84 100.00 applicable rates of utilization: ($000) Undepreciated capital costs Eligible capital expenditures Share issue costs Canadian oil and gas property expenditures Canadian development expenditures Canadian exploration expenditures SR&ED expenditures Income tax losses carried forward (1) those distributions is as follows: Taxable Income (Other Income) Return of Capital reported as qualified dividends. NET EArNINGS ($ 000) Net Earnings (1) Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000, 2027 - $116,787,000, 2028 - $40,750,000. Prior to becoming a corporation, the Trust paid nine distributions for the 2008 tax year. The Canadian tax breakdown of With respect to cash distributions paid during the year to U.S. individual unitholders, 17.71 percent should be reported as a return of capital (to the extent of the Unitholder’s U.S. tax basis in their respective units) and 82.29 percent should be Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 10,585 21,125 8,372 55,426 30,350 Bonterra’s net earnings for the year ended December 31, 2008 represents an 82 percent increase over the Company’s 2007 net earnings. The Company recorded net earnings per share on a fully diluted basis in 2008 of $3.23 verses $1.79 in the 2007 year. This represents a return on Shareholders’ equity of approximately 97.6 percent (2007 – 68.6 percent) based on year end Shareholders’ equity. Strong crude oil and natural gas prices for most of 2008 along with a three percent increase in production volumes were driving factors behind the increased profit. However, during the fourth quarter and continuing into the first quarter and likely beyond, commodity prices have plunged to under $40 U.S. ($50 Cdn). This along with natural gas prices in the $4 to $5 dollar range will significantly reduce the Company’s future net earnings. The Company’s low capital costs combined with the Company’s low production decline rates should allow for continued positive earnings even in the above mentioned price environment. COMprEhENSIvE INCOME On January 1, 2007, Bonterra became obliged to adopt the new accounting standards regarding the accounting for financial instruments. On adoption, the Company increased its investment in related party by $1,836,000 for the fair value of this investment. On January 1, 2007, Bonterra further recognized a current asset of $1,189,000 for the fair value of its commodity derivative contracts. These adjustments resulted in a further increase in the future income tax liability and accumulated other comprehensive income of $645,000 and $2,380,000, respectively. 30 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 11 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 2 9 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 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, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was $58,903,000 (2007 - $54,622,000). Of the $4,281,000 increase, the majority is due to the Silverwing acquisition. 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 $2,706,000. While a one percent decrease in the risk adjusted rate would increase the asset retirement obligation by $3,639,000. 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, 2008, the Company expensed $14,749,000 (2007 - $16,675,000) for the above-described items including $Nil (2007 - $3,078,000) for dry hole costs. During 2007 the Company wrote off all costs related to eight wells which no reserves were attributed by the independent third party engineers. The Company continues to have relatively low finding and development costs (see discussion under Finding and Development Costs). Based on year end reserves, the Company’s average cost of proved reserves is $6.40 (2007 - $5.84) per BOE. The Company currently has an estimated reserve life for its proved developed producing reserves of 12.5 (2007 – 11.3) years calculated using the Company’s gross reserves (prior to allowance for royalties) based on the third party engineering report dated December 31, 2008 and using fourth quarter 2008 average production rates of 4,587 BOE per day (2007 – 4,295 BOE per day). Based on total proved reserves the Company has a 14.4 (2007 – 13.7) year reserve life and if proved and probable are used the reserve life increases to 18.7 (2007 – 17.4) years. These figures are some of the longest reserve life indexes (excluding oil sands) in the Canadian oil and gas industry. INCOME TAxES On November 12, 2008, Bonterra Energy Income Trust converted to a corporation. Due to the conversion and the acquisition of Silverwing, the Company increased its usable tax pools to approximately $468,000,000 (see below). As a result of the reorganization, the Company has recorded a future income tax asset and a corresponding deferred tax credit. These amounts will be amortized into future tax expense as the associated tax pools are consumed. The current tax provision relates to resource surcharge payable by the Company to the Province of Saskatchewan. The surcharge is calculated as a flat percent of revenues generated from the sale of petroleum products produced in Saskatchewan. The provincial government of Saskatchewan reduced the resource surcharge rate from 3.1 percent to 3.0 percent on July 1, 2008. 8. prOpErTY AND EQUIpMENT ($000) Undeveloped land Petroleum and natural gas properties and related equipment Furniture, equipment and other 9. DUE TO rELATED pArTY 2008 2007 Accumulated Depletion and Depreciation Cost Accumulated Depletion and Depreciation Cost $ 2,295 $ – $ 316 $ – 229,136 1,254 74,844 848 185,947 1,025 $ 232,685 $ 75,692 $ 187,288 $ 61,105 700 61,805 As of December 31, 2008, the Company’s CEO and major shareholder has loaned the Company $6,000,000. The loan is unsecured, bears interest at Canadian chartered bank prime less one half of a percent and has no set repayment terms. The loan can only be repaid should the Company have sufficient available borrowing limits under the Company’s credit facility. Interest paid on this loan during 2008 was $7,000. Please refer to note 15 for additional related party transactions. 10. BANk DEBT Due to the corporate reorganization and acquisition of Silverwing, the Company amended its bank facility to consist of an $80,000,000 syndicated revolving credit facility and a $20,000,000 non-syndicated demand credit facility (December 31, 2007 - $69,900,000) (non-syndicated demand facility). Amounts drawn under these facilities at December 31, 2008 were $93,235,000 (December 31, 2007 - $57,422,000). The interest rates on the outstanding debt as of December 31, 2008 were 4.35 percent and 3.49 percent on the Company’s Canadian prime rate loan (short-term debt) and Bankers’ Acceptances (long-term debt), respectively. The terms of the syndicated revolving credit facility provide that the loan is revolving to May 30, 2010 and is subject to annual review. The revolving credit facility has no fixed payment requirements. The terms of the non-syndicated demand credit facility provide that the loan is due on demand and is subject to annual review and has no fixed repayment terms. The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit. Letters of credit totaling $525,000 were issued at December 31, 2008 (December 31, 2007 - $355,000). Of the letters of credit, $20,000 is secured by a restricted term deposit. 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 facilities is calculated as follows: Consolidated Total Funded Debt (1) to Consolidated Cash flow ratio Level I Level II Level III Level IV Level V Level VI Below 0.50:1 Over 0.5:1 to 1.0:1 Over 1.0:1 to 1.5:1 Over 1.5:1 to 2.0:1 Over 2.0:1 to 2.5:1 Over 2.5:1 Canadian Prime Rate Plus (2) Bankers’ Acceptances Rate Plus (2) 50 150 75 175 85 185 100 200 125 225 150 250 (1) Consolidated total funded debt excludes related party amounts but includes working capital. (2) Numbers in table represent basis points. Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to be effective until the next such adjustment: 10 BONTE R RA OIL & GAS LTD. BON TERRA OI L & G AS LTD. 31 1 I B S w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 2 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 r o t c e f r e P a r r e t n o B _ 2 9 4 0 2 0 9 2 The following is a list of the material covenants: • The Company as of December 31, 2008 is required to not exceed $100,000,000 in consolidated debt (includes negative working capital but excludes debt to related parties). • Dividends paid in any quarter shall not exceed 80 percent of the average previous four quarters cash flow as defined under GAAP. 11. INCOME TAXES The Company has recorded a future income tax asset related to assets and liabilities and related tax amounts: ($000) Future tax liability related to investments: Future tax liability related to property and equipment: Future tax asset related to asset retirement obiligations: Future tax asset related to finance costs: Future tax asset related to corporate tax losses and SR&ED claims Future tax asset (Liability) – Long-term Current portion of future income tax asset related to corporate tax losses and SR&ED claims: Future income tax asset related to current portion of derivative liability Future Tax Asset - Current 2008 (212) $ (7,097) 4,593 1,134 $ 86,998 85,416 $ 2,669 $ – 2,669 $ 2007 (448) (14,828) 3,759 79 3,843 (7,595) – 913 913 $ $ $ $ $ As a result of the reorganization the Company recorded a deferred credit of $71,303,000 relating to the difference between the future income tax asset generated on the reorganization and the amount of the cash payment made to SRX immediately before the reorganization. This credit is being amortized (2008 - $4,240,000) on the same basis as the related future income tax asset (2008 - $4,909,000). A reconciliation of the deferred credit is as follows: Amount recorded on reorganization Amortized in current year Balance as of December 31, 2008 Current portion Long-term portion $ 71,303,000 (4,240,000) $ 67,063,000 $ 2,305,000 64,758,000 $ 67,063,000 Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial income tax rates as follows: ($000) Earnings before income taxes Combined federal and provincial income tax rates Income tax provision calculated using statutory tax rates Increase (decrease) in taxes resulting from: Saskatchewan resource surcharge Stock-based compensation Change in effective tax rate Trust income allocated to Unitholders prior to conversion Others $ 2008 58,014 $ 29.62% 17,184 437 357 (4,739) (10,291) (360) Income tax expense $ 2,588 $ 2007 33,434 32.27% 10,789 512 366 4,076 (13,176) 517 3,084 Bank debt at December 31, 2008 was $93,235,000 (December 31, 2007 - $57,422,000). 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 interest rate on the credit facilities is calculated as follows: Consolidated Total Funded Debt (1) to Consolidated Cash flow ratio Level I Level II Level III Level IV Level V Level VI Below Over 0.5:1 Over 1.0:1 Over 1.5:1 Over 2.0:1 0.50:1 to 1.0:1 to 1.5:1 to 2.0:1 to 2.5:1 Over 2.5:1 Canadian Prime Rate Plus Bankers’ Acceptances Rate Plus 50 150 75 175 85 185 100 200 125 225 150 250 (1) Consolidated total funded debt excludes related party amounts but includes working capital. Consolidated total funded debt to consolidated cash flow ratio shall be adjusted effective as of the first day of the third month following the end of each fiscal quarter, except for the end of a fiscal year in respect of which the adjustment shall be made effective as of the first day of the fifth month following the end of such fiscal year, with each such adjustment to be effective until the next such adjustment. rEOrGANIzATION COSTS Based on current accounting rules, costs associated with the Trust’s reorganization into Bonterra Oil and Gas Ltd. must be expensed. The costs consist of a $1,000,000 finders fee paid to a company that facilitated the reorganization, $931,000 of professional fees, $150,000 stock exchange fees and $40,000 of costs associated with the distribution of the reorganization document. These costs are all one time costs and no further costs are anticipated by the Company in direct relation to the reorganization. Of these total costs of $2,121,000, the Company expensed $1,369,000 in the fourth quarter of 2008 and $752,000 was expensed in the third quarter of 2008. 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. Due to the reorganization, all existing employee unit options vested and were either exercised or were cancelled. This resulted in approximately an additional $195,000 of stock-based compensation being recorded in the fourth quarter on the automatic vesting of outstanding options. Also the Company issued 1,390,500 stock options during 2008 resulting in a further expense of $97,000. The 1,390,500 common share options were issued at the end of November 2008 with an exercise price of $20.50 per share and a fair value of $1.11 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 2.2 percent (2007 – 4.7 percent), expected weighted average volatility of 31 percent (2007 – 27 percent), expected weighted average life of 3.5 years (2007 – 2.3 years) and an annual dividend/distribution rate based on the dividends paid to the Shareholders/Unitholders during the year. The future stock-based compensation impact of these options is approximately $225,000 per quarter over the next four quarters. 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, a life span of ten years is estimated and the related tangible costs are depreciated at one tenth of original cost per year. The use of a ten year life span instead of calculating depreciation over the life of reserves was determined to be more representative of actual costs of tangible property. Given the Company’s long production life, wells generally require replacement of tangible assets more than once during their life time. Most of the Company’s wells have been producing since the 1960’s and are expected to continue to produce for at least another twenty years. 32 BONT ERRA OIL & GAS LT D. BONTERRA OIL & GAS LTD. 9 The Company’s only significant general and administrative costs are employee compensation and professional services such as legal, engineering and accounting. Employee compensation expense increased by approximately 29 percent ($856,000). The increase is due primarily to the Company’s bonus plan which resulted in additional employee compensation of $610,000 (20.7 percent) with the remainder due to increased staffing levels (3.8 percent) and 2008 salary increases (4.5 percent). The Company’s bonus plan consists of cash payments equal to three percent of before tax net earnings to be paid to employees and key consultants based on performance throughout the year. Costs associated with professional services increased by approximately $90,000. Increases in other general and administrative areas have been offset by increased administration recovery charges to capital programs. The quarter over quarter decrease was primarily due to a lower bonus accrual but was almost fully offset by increased professional fees related to the internal control review and costs related to managing the integration of the Silverwing acquisition and reorganization. INTErEST ExpENSE ($ 000) Interest Expense Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 746 545 878 2,740 3,028 The decrease in interest expense in 2008 as compared to 2007 was due to much lower borrowing costs, offset partially by increased loan balances resulting from the Company’s acquisition of Silverwing and its reorganization. Interest rates during the year on the outstanding debt averaged approximately 4.5 percent (2007 - 5.9 percent). The Company maintained an average outstanding debt balance of approximately $60,600,000 (2007 - $51,600,000). Total debt (including negative working capital) as of December 31, 2008 represents approximately 17.9 months of 2008 annual cash flow from operations or 30.1 months based on annualized 2008 fourth quarter cash flow from operations. The ratio of bank debt only as of December 31, 2008 based on the annualized 2008 Q4 base was 27.1 months. Also in the fourth quarter of 2008 the Company had one time reorganization costs of approximately $1,369,000 reducing cash flow to $10,336,000 from approximately $11,700,000. This one item has significant implications on the ratio of bank debt to cash flow and would reduce the Q4 numbers of 30.1 to 26.6 and 27.1 to 23.9 months. working capital of $28,995,000. In addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000 plus reorganization costs of $2,121,000. The Company also experienced a decrease in cash flow due to the rather significant drop in commodity prices during the final four months of 2008. The Company ended 2008 with a debt to cash flow ratio that is higher than usual even though it is in a range that is normal with its peers at the present time. The main reason for the higher debt level is that early in the third quarter of 2008, when the Company announced its reorganization and Silverwing acquisition, it had share options outstanding that were well in the money for approximately $25 million. At closing of the reorganization on November 12, 2008, the world economy had changed substantially resulting in large reductions in share prices, including Bonterra’s and the majority of the outstanding options not being exercised. The debt level is still very manageable for Bonterra but plans for 2009 are to reduce the debt to equity ratio that presently exceeds 2:1. 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: ($000) Undepreciated capital costs Eligible capital expenditures Share issue costs Canadian oil and gas property expenditures Canadian development expenditures Canadian exploration expenditures SR&ED expenditures Income tax losses carried forward (1) Rate of Utilization % 20-100 $ 7 20 10 30 100 100 100 Amount 23,696 1,870 4,581 25,072 50,743 10,530 80,357 271,029 $ 467,878 (1) Income tax losses carried forward expire in the following years; 2014 - $1,069,000, 2025 - $3,179,000, 2026 - $109,244,000, 2027 - $116,787,000, 2028 - $40,750,000. The Company has $27,670,000 of investment tax credits (ITC) that expire in the following years; 2009 - $3,469,000, 2010 - $3,059,000, 2011 - $4,667,000, 2012 - $3,909,000, 2013 - $3,155,000, 2014 - $1,995,000, 2015 - $2,257,000, 2016 - $2,405,000, 2017 - $2,009,000, 2018 - $745,000. 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, and distrubution policy. A significant change in any of the preceding assumptions could materially affect the Company’s estimate of the future income tax asset. 12. ASSET rETIrEMENT OBLIGATIONS At December 31, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was $58,903,000 (2007 - $54,622,000). Costs for asset retirement have been calculated assuming a two 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 (2007 – five percent). During the year the Company acquired Silverwing a public oil and gas producer for cash consideration including negative Changes to asset retirement obligations were as follows: ($000) Asset retirement obligations, January 1 Adjustment to asset retirement obligations Adjustment related to asset additions (net of disposals) Liabilities settled during the year Accretion $ 2008 14,904 $ (217) 5,929 (3,063) 785 Asset retirement obligations, December 31 $ 18,338 $ 2007 14,819 (399) 563 (820) 741 14,904 13. ShArEhOLDErS’ EQUITY Authorized The Company is authorized to issue an unlimited number of common shares without nominal or par value. ($000) Issued Common Shares Balance, beginning of year Issued on reorganization to a corporation Balance, end of year 2008 2007 Number Amount Number Amount – $ 17,257,603 17,257,603 $ – 99,530 99,530 – $ – – $ – – – 8 B ONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 33 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 2 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 2 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 ($000) Issued Trust Units Balance, beginning of year Transfer of contributed surplus to unit capital Issued pursuant to Trust unit option plan Issued on acquisition of Silverwing Cancelled on conversion to a corporation Balance, end of year 2008 2007 New Alberta Crown royalty Framework (NrF) Number Amount Number Amount 16,928,158 $ – 321,700 7,745 (17,257,603) 90,590 805 7,935 200 (99,530) 16,874,658 $ – 53,500 – – – $ – 16,928,158 $ 89,488 109 993 – – 90,590 The Company is 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. The number of common shares (formerly trust units) used to calculate diluted net earnings per share (formerly per unit) for the year ended December 31, 2008 of 17,119,517 shares (2007 – 16,942,036 Units) included the basic weighted average number of common shares outstanding of 17,075,647 shares (2007 – 16,908,266 Units) plus 43,870 shares (2007 – 33,770 Units) related to the dilutive effect of common share options. A summary of the changes of the Company’s contributed surplus is presented below: Contributed surplus ($000) Balance, beginning of year Stock-based compensation expensed (non-cash) Stock-based options exercised (non-cash) Balance, end of year The deficit balance is composed of the following items: ($000) Accumulated earnings Accumulated cash dividends and distributions Deficit 2008 2,140 $ 1,207 (805) 2,542 $ 2007 1,116 1,133 (109) 2,140 2008 208,182 $ (254,897) (46,715) $ 2007 152,756 (204,299) (51,543) $ $ $ $ The Company provides an option plan for its directors, officers, employees and consultants. Under the plan, the Company may grant options for up to 1,725,760 common shares (2007 – 1,692,800 Trust Units). 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, 2008 and changes during the year is presented below: Outstanding at beginning of year Options granted Outstanding at end of year Options exercisable at end of year 2008 weighted- Average Exercise price Options – $ 1,390,500 1,390,500 $ – $ – 20.50 20.50 – Royalty rates in the fourth quarter averaged approximately 13.4 percent; slightly higher than preceding quarters. The NRF rates vary by prices as well as productivity levels. With the current low prices the new royalty rates should result in a significant reduction in the amount the Company will pay to the Province of Alberta. This combined with the Silvering acquisition (mostly BC production with lower Crown royalty rates) should result in a lower average Crown royalty rate for the Company in 2009. The effect of the NRF on the Company’s oil and liquid reserves was a reduction of 77,200 barrels for proved and a reduction of 132,800 barrels for proved plus probable reserves. For natural gas, the NRF accounted for a reduction of 56,500 MCF for proved and 128,800 MCF for proved plus probable reserves. On a BOE basis, this reduction represented approximately 0.6 percent of the Company gross reserves on a proved plus probable basis. prODUCTION COSTS ($ 000) Production costs $ per BOE Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 6,859 16.25 6,148 15.84 5,535 14.01 25,413 15.98 24,073 15.64 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. Operating costs on the Company’s newly acquired British Columbia (BC) properties as well as on the newly drilled wells are lower on a BOE basis than on its older low productivity wells and this may result in lower operating costs per BOE in the future. Operating costs increased slightly in the fourth quarter of 2008 compared to the prior quarter due primarily to the acquisition of Silverwing and from new wells put on production in the fourth quarter of 2008 and large industry wide increases for oilfield services especially for oil producing properties. Average production costs per BOE increased marginally in Q408 compared with the previous quarter due mainly to winterization programs performed on the Company’s wells As discussed above, Bonterra’s production comes primarily from low productivity wells. These wells generally result in higher operating costs on a per unit-of-production basis as costs such as municipal taxes, surface leases, power and personnel costs are not variable with production volumes. The Company is continually examining ways to reduce With the acquisition of Silverwing and the Company’s recent drilling success and expected declines in oilfield service costs, the Company anticipates operating costs in the $14 to $15 per BOE range for 2009. The higher operating costs for the Company are substantially offset by lower royalty rates and results in higher cash net backs on a combined basis despite higher than average operating costs. GENErAL AND ADMINISTrATIvE ExpENSE Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 824 1.95 845 2.18 739 1.69 3,401 2.14 2,603 1.69 and facilities. operating costs. ($ 000) G&A Expense $ per BOE General and administrative (G&A) expenses increased 31 percent in 2008 compared to 2007. The Company provides administrative services to Comaplex Minerals Corp. (Comaplex) and Pine Cliff Energy Ltd. (Pine Cliff), companies that share common directors and management. Please refer to discussion under Related Party Transactions for details. 34 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 7 Number Weighted-Average Oustanding At 12/31/08 1,390,500 Range of Exercise Prices $20.50 3.9 years $ 20.50 – $ – Remaining Weighted-Average Exercise Price Contractual Life Number Exercisable Weighted-Average At 12/31/08 Exercise Price As at December 31, 2008, Bonterra had only one gross (0.25 net) Cardium oil well, no natural gas wells, three gross The following table summarizes information about stock options outstanding at December 31, 2008: Options Outstanding Options Exercisable (2.5 net) coalbed methane (CBM) wells with assigned reserves and three gross (2.9 net) Shaunavon oil wells drilled but not on production. Subsequent to December 31, 2008 and up to the date of this report, the Company has put all of its oil wells on production. The timing for the tie-in of the CBM wells has not yet been determined. rEvENUE (Cdn $) Average Realized Prices: Crude oil and NGLs (per barrel) Natural gas (per MCF) Revenue – oil and gas sales (000’s) - cash 22,613 34,226 26,573 121,730 96,431 Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 58.91 7.00 103.36 8.20 77.60 6.70 87.54 8.21 70.31 6.75 Revenue from petroleum and natural gas sales increased 26 percent in 2008 compared to 2007 due to increased production volumes and an increase in the average price received for crude oil, natural gas liquids and natural gas. The fourth quarter of 2008 saw a substantial decrease in realized revenues over the third quarter of 2008 due to the significant decrease in commodity prices. Included in revenue is a risk management loss of $7,353,000 (2007 – gain of $621,000) due to lower prices received as a result of commodity risk management agreements. The Company may continue to hedge future production to assist in managing its cash flow. As at December 31, 2008, the Company had no outstanding risk management agreements. The value of the outstanding commodity hedging contracts as of December 31, 2007 was a net liability of $3,085,000. rOYALTIES ($ 000) Crown royalties Freehold royalties, gross overriding royalties and net carried interests Total royalty expense Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 2,337 3,523 2,634 13,736 9,209 558 2,895 1,134 4,657 682 3,316 3,479 17,215 3,235 12,444 Royalties paid by the Company consist primarily of Crown royalties paid to the Provinces of Alberta, Saskatchewan and British Columbia. The majority of the Company’s wells are low productivity wells and therefore have low Crown royalty rates. The Company’s average Crown royalty rate was approximately 10.6 percent (2007 – 10 percent) and approximately 2.7 percent (2007 – 3 percent) for other royalties before hedging adjustments. During 2007, the Company was advised by the owner of a gross overriding royalty that a production limit was attained that resulted in an additional gross overriding royalty in respect of certain of its Cardium oil wells. The production limit was triggered by a calculation on a multitude of Cardium wells including many that were not owned by the Company. determined. In discussions with the payee it was determined that the production limit was reached in late 2005. The royalty was calculated based on this agreed date and the affected wells for the Company and other operators in the area were identified. The approximate amount of the adjustment, net to the Company was $570,000 for periods prior to January 1, 2007. This amount has been included in the 2007 royalty numbers. Also in 2007 the Company was informed by the operator of its former Dodsland property that it had not been charged a net profit royalty for the years 2004, 2005 and 2006. In reviewing the agreements it was confirmed the claim was accurate and an amount of approximately $150,000 was paid by the Company in 2007 for the net profit royalty. This was also expensed in 2007. A summary of the former unit option plan as of December 31, 2008 and 2007, and changes during the years is presented below: Outstanding at beginning of year Options granted Options exercised Options cancelled Outstanding at end of year Options exercisable at end of year 2008 weighted- Average Exercise price Options 2007 Weighted- Average Options Exercise Price 1,177,000 $ 29,000 (321,700) (884,300) – $ – $ 27.59 39.09 24.66 29.03 – – 721,500 $ 553,000 (53,500) (44,000) 1,177,000 $ 530,000 $ 26.55 28.11 18.56 27.92 27.59 26.63 The Company records compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. The Company granted 1,390,500 stock options with an estimated fair value of $1,548,000 ($1.11 per option) using the Black-Scholes option pricing model with the following key assumptions: 2008 2007 Weighted-average risk free interest rate (%) Expected life (years) Weighted-average volatility (%) Dividend yield 2008 and 2007 4.7 2.3 27.2 based on the percentage of dividends or distributions paid during the year 2.2 3.5 31.3 In addition the exact wells that the production limit was applicable to was not readily known by the Company nor easily ($000) Unrealized gains on available for sale financial assets Unrealized gains and losses on derivatives designated as cash flow hedges ($000) Unrealized gains (losses) on available for sale financial assets Other January 1, Comprehensive December 31, 2008 Income (Loss) 2008 $ 3,031 $ (1,611) $ 1,420 Other January 1, Comprehensive December 31, 2007 Income (Loss) 2007 $ 1,566 $ 1,465 $ 814 $ 2,380 $ (814) 651 $ 3,031 – 3,031 14. ACCUMULATED OThEr COMprEhENSIvE INCOME 6 B ONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 35 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 9 2 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 2 9 0 2 0 4 9 2 _ B o n t e r r a P e r f e c t o r 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 2 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w S B I 1 15. rELATED pArTY TrANSACTIONS The Company received a management fee from Comaplex of $330,000 (2007 - $300,000) for management services and office administration. This fee has been included as a recovery in general and administrative expenses and represents the fair value of the services rendered. In order to facilitate the acquisition of Silverwing, the Company borrowed on a short-term basis $20,000,000 from Comaplex to allow time to finalize documentation for its new bank line of credit. The funds were repaid on November 21, 2008. Total interest paid on the loan was $21,000. As at December 31, 2008, the Company had an account receivable from Comaplex of $56,000 (December 31, 2007 - $63,000). The Company received a management fee from Pine Cliff Energy Ltd., a company with common directors and management with the Company and its subsidiaries, of $238,000 (2007 - $216,000) for management services and office administration. This fee has been included in general and administrative expenses as a recovery and represents the fair value of the services rendered. As at December 31, 2008 the Company had an account receivable from Pine Cliff of $1,000 (December 31, 2007 - $4,000). ($000) Restricted cash Future income tax benefit Property and equipment Working capital deficiency Asset retirement obligations ($000) Accounts receivable Prepaids Accounts payable 16. FINANCIAL AND CApITAL rISk MANAGEMENT INTErNAL CONTrOL ChANGES Silverwing 1,252 18,325 15,347 (14,979) (5,929) 14,016 SRX 2,158 1,701 3,859 Nil $ $ $ $ Financial risk Factors The Company undertakes transactions in a range of financial instruments including: • Receivables • Payables • Common share investments • Bank loans • Derivatives The Company’s activities result in exposure to a number of financial risks including market risk (commodity price risk, interest rate risk, foreign exchange risk, credit risk, and liquidity risk). 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 enters 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 in respect of interest rate risk. 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 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, the percentage of return of capital or issue new shares. The Company monitors capital on the basis of the ratio of debt to cash flow. During the year the Company acquired Silverwing, a public oil and gas producer for cash consideration including negative working capital of $28,795,000. In addition, the Trust underwent a reorganization resulting in a cash outlay of $11,257,000 plus reorganization costs of $2,121,000. The Company has also experienced a decrease in cash flow due to the rather significant drop in commodity prices during the final four months of 2008. The Company is required to comply with Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”, otherwise referred to as Canadian SOX (C-Sox). The 2008 certificate requires that the Company disclose in the MD&A any changes in the Company’s internal control over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect the Company’s internal control over financial reporting. The Company confirms that no such changes were made to the internal controls over financial reporting during 2008. prODUCTION Crude oil and NGLs (barrels per day) Natural gas (MCF per day) Average BOE per day Three months ended Twelve months ended December September December December December 31, 2008 30, 2008 31, 2007 31, 2008 31, 2007 3,105 8,892 4,587 3,013 7,233 4,219 3,098 7,176 4,295 3,073 7,637 4,346 3,113 6,627 4,218 Bonterra’s 2008 average production increased three percent on a per BOE basis. Crude oil production decreased by approximately 1.3 percent while gas production increased by approximately 15.2 percent. The decreased crude oil production was due to the timing of Bonterra’s 2008 development program in which production came on late in the year and therefore contributed little to 2008 and the 2007 property swap where the Company exchanged its predominantly Saskatchewan oil property for additional production in the Pembina area which had higher natural gas production. The natural gas increase was due to a combination of the successful 2008 development program, the acquisition of Silverwing on November 12, 2008 and the above mentioned property swap. The Company’s fourth quarter production in 2008 saw increases in crude oil (92 barrels per day) and natural gas (1,659 MCF per day) production over Q308 production due to the commencement of production from new wells drilled as well as the completion of the Silverwing acquisition. The Silverwing acquisition, which closed on November 12, 2008 added approximately 650 BOE per day, mainly natural gas. The Company’s average production volume for December was approximately 4,950 BOE per day. Bonterra’s overall annual decline rate for 2008 was approximately 8.5 percent. The Company was able to more than offset this decline with its 2008 drill program. Bonterra, along with its partners, drilled 33 gross (22.9 net) Cardium oil wells. This includes 26 gross and 21.9 net Cardium wells drilled directly by the Company. Also the Company drilled 7 gross (5 net) shallow gas wells in 2008 in the Pembina field and 3 gross (2.9 net) Shaunavon oil wells. The Company also participated in one (0.1 net) Cardium natural gas well drilled by one of its partners. Bonterra recorded a 100 percent success rate with its 2008 drilling program. The majority of the wells were drilled in the fourth quarter; 14 (10.2 net) Cardium oil wells, 7 gross (5 net) shallow Pembina gas wells and all three (2.9 net) of the Shaunavon oil wells. The closing date for the Silverwing acquisition was November 12, 2008 and therefore contributed little to production rates for the full year. 36 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 5 2 9 0 2 0 4 9 2 _ B o n t e r r a S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 1 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B C M Y C 7 0 C M Y B C M Y C M Y B C M Y M 7 0 C M Y B C M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B P r i n e c t 4 G S i F o r m a t 1 0 2 / 1 0 5 D i p c o 3 . 0 e ( p d f ) © 2 0 0 7 H e i d e l b e r g e r D r u c k m a s c h i n e n A G While Bonterra believes it has adequate DC&P in place, lapses in the disclosure controls and procedures could occur and/or mistakes could happen. Should such occur, the Company intends to take whatever steps it deems necessary to 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. 1. pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and The carrying amounts, fair value and face values of the Company’s financial assets and liabilities are shown in Table 1. 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 Table 1 ($000) Financial assets Restricted term deposit Accounts receivable Investment in related party Financial liabilities Accounts payable and accrued liabilities Due to related party Short-term debt Long-term debt 2. due to the limited number of staff, the Company relies upon third parties as participants in the Company’s internal The net debt and cash flow from operations figures are presented in Table 2. Table 2 ($000) Short-term debt Long-term debt Due to related party Accounts payable and accrued liabilities Current assets (1) Net Debt Cash flow from operations (2) Net debt to cash flow from operations As at December 31, 2008 Carrying value Fair value Face value 20 11,753 2,131 20 11,753 2,131 20 11,838 N/A 23,888 6,000 13,325 79,910 23,888 6,000 13,325 79,910 23,888 6,000 13,325 79,910 December 31, 2008 13,325 79,910 6,000 23,888 (18,971) 104,152 69,570 1.50 minimize the consequences thereof. Internal Controls Over Financial reporting includes those policies and procedures that: dispositions of the assets of the issuer; Internal controls over financial reporting (ICFR) are defined in NI 52-109 as “… a process designed by, or under the supervision of, an issuer’s certifying officers and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s Generally Accepted Accounting Practices (GAAP) and 2. are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the issuer’s GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and 3. are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material effect on the annual financial statements or interim financial statements.” The Company has conducted a review and evaluation of its ICFR, with the conclusion that as of December 31, 2008 the Company’s system of ICFR as defined under NI 52-109 is adequately designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. The control framework the Company used to design and evaluate its ICFR was COSO. In its evaluation, the Company identified certain material weaknesses in internal controls over financial reporting: 1. due to the limited number of staff at the Company, it is not feasible to achieve the complete segregation of incompatible duties; and controls over financial reporting. The Company believes these weaknesses are mitigated by: the active involvement of senior management and the board of directors in the affairs of the Company; open lines of communication within the Company; the present levels of activities and transactions within the Company being readily transparent; the thorough review of the Company’s financial statements by management, the board of directors and by the Company’s auditors (annual statements only); and the establishment of a whistle-blower policy. However, these mitigating factors will not necessarily prevent a material misstatement occurring as a result of the aforesaid weaknesses in the Company’s internal controls over financial reporting. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. The Company has no plans for remediating the above weaknesses. Limitation on Scope of Design of DC&p and ICFr The above design of DC&P and ICRF has been limited to exclude controls, policies and procedures of both Silverwing Energy Inc. (Silverwing) and operations of SRX Post Holdings (SRX) prior to the reorganization of Bonterra Energy Income Trust into the Company. The following tables summarize the information that has been included in the consolidated financial statements of the Company. (1) Current assets include restricted term deposit, accounts receivable, crude oil inventory, prepaid expenses and investment in related party. (2) Cash flow from operations includes annual net earnings less adjustment for non-cash (gain) loss on risk management contracts, stock- based compensation, depletion, depreciation and accretion, future income taxes, changes in non-cash working capital items and asset retirement obligations settled. 4 B ONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 37 w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 1 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S a r r e t n o B _ 2 9 4 0 2 0 9 2 G A n e n i h c s a m k c u r D r e g r e b l e d i e H 7 0 0 2 © ) f d p ( e 0 . 3 o c p i D 5 0 1 / 2 0 1 t a m r o F i S G 4 t c e n i r P B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M C B Y M C 0 7 M Y M C B Y M C Y M C B Y M C 0 7 C Y M C B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M 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, recently 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. Sensitivity Analysis Commodity prices have fluctuated significantly over the recent past. The following table updates the cash flow sensitivity for movements in the commodity prices of $1 U.S. per barrel WTI for crude oil, $0.10 per MCF AECO for natural gas and $0.01 fluctuation in exchange rates. ($000) U.S. $1.00 per barrel Canadian $0.10 per MCF Change of Canadian $0.01/U.S. $ exchange rate Interest rate risk Cash Flow 870,000 289,000 593,000 $ $ $ 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 bank borrowings which have a variable interest rate which gives rise to a cash flow interest rate risk. The Company’s debt consists of an $80,000,000 revolving operating line, $20,000,000 demand operating line and $6,000,000 due to the Company’s CEO and major shareholder. The borrowings under these facilities are at bank prime plus or minor various percentages as well as by means of banker acceptances (BA’s). 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. No income tax effect has been calculated as the Company has sufficient tax pools such that it will not be taxable in the near future. A one percent increase (decrease) in the Canadian prime rate would decrease cash flow by $992,000 (increase by $992,000). 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, recently 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; Financial ($000, except $ per unit) Revenue – realized oil and gas sales Cash flow from operations Per Unit Basic Per Unit Fully Diluted Cash payments per share/unit (1) Payout Ratio (1) Net Earnings Per Unit Basic Per Unit Fully Diluted Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Long-term debt Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Total BOE per day 4th 3rd 2nd 1st 2007 26,573 13,369 0.79 0.79 0.66 84% 7,920 0.47 0.47 7,213 142,329 58,766 – 44,218 3,098 7,176 4,295 23,794 11,886 0.70 0.70 0.66 94% 9,086 0.54 0.53 2,763 138,140 50,041 – 50,820 3,054 6,196 4,086 23,462 13,413 0.79 0.79 0.66 84% 4,440 0.26 0.26 1,699 139,432 49,595 – 51,920 3,074 6,663 4,184 22,602 12,765 0.76 0.76 0.66 87% 8,904 0.53 0.53 7,625 140,926 49,288 – 57,646 3,227 6,470 4,305 (1) Cash payments per share/unit are based on payments made in respect of production months within the quarter. Disclosure Controls and procedures Disclosure controls and procedures (DC&P) are defined under National Instrument 52-109 – Certification of Disclosure Controls in Issuers’ Annual and Interim Filings (NI 52-109) as “…controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its certifying officers as appropriate to allow timely decisions regarding required disclosure.” The Company has conducted a review and evaluation of its DC&P, with the conclusion that as at December 31, 2008 the Company has an effective system of DC&P as defined under NI 52-109. In reaching this conclusion, the Company recognizes that two key factors must be and are present: requirements; and 1. the Company is very dependent upon its advisors and consultants (principally its legal counsels) to assist in recognizing, interpreting, understanding and complying with the various securities regulations disclosure 2. the Company has an active Board and management with open lines of communications. Bonterra has a small staff with varying degrees of knowledge concerning the various regulatory disclosure requirements. In many circumstances, the various regulatory requirements are relatively new, subject to interpretation, and complex. The Company is not of sufficient size to justify a separate department or one or more staff member specialists in this area. Therefore the Company must rely upon its advisors/consultants to assist it and as such they form part of the disclosure controls and procedures. Proper disclosure necessitates that a person not only be aware of the pertinent disclosure requirements, but must also be sufficiently involved in the affairs of the Company and/or receives the communication of information to assess any necessary disclosure requirements. Accordingly, it is essential that there be proper communication among those people who manage and govern the affairs of the Company, this being the Board of Directors and senior management. The Company believes this communication exists. 38 BONTERRA OIL & GAS LTD. BONTERRA OIL & GAS LTD. 3 ANNUAL COMpArISONS Financial ($000, except $ per unit) Revenue – realized oil and gas Cash flow from operations Per Share/Unit Basic Per Share/Unit Fully Diluted Cash payments per share/unit (1) Payout Ratio (1) Net Earnings Per Share/Unit Basic Per Share/Unit Fully Diluted Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Long-term Debt Shareholders’/Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Total BOE per day QUArTErLY COMpArISONS Financial ($000, except $ per unit) Revenue – realized oil and gas sales Cash flow from operations Per Share/Unit Basic Per Share/Unit Fully Diluted Cash payments per share/unit (1) Payout Ratio (1) Net Earnings Per Share/Unit Basic Per Share/Unit Fully Diluted Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Long-term debt Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Total BOE per day 121,730 69,570 4.07 4.06 3.12 77% 55,426 3.25 3.23 45,407 265,301 23,878 79,910 56,777 3,073 7,637 4,346 34,226 22,492 1.31 1.30 0.96 73% 21,125 1.23 1.22 6,038 150,120 47,499 – 57,623 3,013 7,233 4,219 2008 96,431 51,433 3.04 3.04 2.64 87% 30,350 1.79 1.79 19,300 142,326 58,766 – 44,376 3,113 6,627 4,218 34,398 20,530 1.21 1.20 0.84 69% 12,912 0.76 0.75 2,543 153,247 57,148 – 46,612 3,024 7,272 4,236 88,734 51,944 3.10 3.08 2.82 91% 37,250 2.23 2.21 38,348 134,942 50,187 – 53,359 3,040 6,014 4,042 30,493 16,212 0.96 0.96 0.70 73% 10,804 0.64 0.64 6,421 150,169 57,810 – 48,136 3,153 7,139 4,343 22,613 10,336 0.59 0.59 0.62 105% 10,585 0.62 0.62 30,405 265,301 23,878 79,910 56,777 3,105 8,892 4,587 2008 2007 2006 • Investments are generally only with companies that have common management with the Company. • Agreements for product sales are primarily on 30 day renewal terms; and Of the accounts receivable balance of December 31, 2008 ($11,753,000) and December 31, 2007 ($10,575,000) over 82 (2007 – 90) percent relates to product sales with international oil and gas companies, tax receivables from the Canadian Government or risk contract payments from the Company’s principal banker. The Company assesses quarterly, if there has been any impairment of the financial assets of the Company. During the year ended December 31, 2008, there was no impairment provision required on any of the financial assets of the Company due to historical success of collecting receivables. The Company does have a credit risk exposure as the majority of the Company’s accounts receivable are with counterparties having similar characteristics. However, payments from the Company’s largest accounts receivable counter parties 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, 2008 approximately $99,000 or 0.8 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 net paying 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, 2008 is $85,000. There were no accounts written off during the year. The carrying value of accounts receivable approximates their fair value due to the relatively short periods to maturity on this instrument. The maximum exposure to credit risk is represented by the carrying amount on the balance sheet. There are no material financial assets that the Company considers past due. 4th 3rd 2nd 1st Liquidity risk Liquidity risk includes the risk that, as a result of 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 ($000) Recognized on Financial Statements Less Than One Year 1-3 Years 4-5 Years Accounts payable and accrued liabilities Due to related party Short-term bank debt Long-term bank debt Office leases Yes – Liability Yes – Liability Yes – Liability Yes – Liability No Total 23,888 6,000 13,325 – 589 43,802 – – – 79,910 1,238 81,148 – – – – 1,080 1,080 2 B ONTE RR A OIL & GAS LTD. BON TERRA OI L & G AS LTD. 39 M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B C M Y C 7 0 C M Y B C M Y C M Y B C M Y M 7 0 C M Y B C M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B P r i n e c t 4 G S i F o r m a t 1 0 2 / 1 0 5 D i p c o 3 . 0 e ( p d f ) © 2 0 0 7 H e i d e l b e r g e r D r u c k m a s c h i n e n A G 2 9 0 2 0 4 9 2 _ B o n t e r r a S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 1 F r o n t - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w G A n e n i h c s a m k c u r D r e g r e b l e d i e H 7 0 0 2 © ) f d p ( e 0 . 3 o c p i D 5 0 1 / 2 0 1 t a m r o F i S G 4 t c e n i r P B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M C B Y M C 0 7 M Y M C B Y M C Y M C B Y M C 0 7 C Y M C B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M c) Risk management contracts The Company currently has no outstanding risk management contracts: As of December 31, 2007, the fair value of the outstanding commodity risk management contracts was a net liability of $3,085,000. 17. 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: Contract Obligations ($000) Office leases (1) Total Less than 1 year 1 – 3 years $ 2,907 $ 589 $ 1,238 $ 4 – 5 years 1,080 (1) Includes Silverwing’s former office space which is being sublet at a rate that approximates the rates charged to the Company. The funds received on the sublease have not been offset against the contractual liability. 18. SUBSEQUENT EvENTS - DIvIDENDS Subsequent to December 31, 2008, the Company has declared the following dividends: Date declared January 6, 2009 February 9, 2009 March 5, 2009 Record date January 15, 2009 February 18, 2009 March 16, 2009 $ per share $0.16 $0.12 $0.12 Date payable January 30, 2009 February 27, 2009 March 31, 2009 40 BONTERRA OIL & GAS LTD. w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - k c a B 1 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S a r r e t n o B _ 2 9 4 0 2 0 9 2 BONTERRA OIL & GAS LTD. 1MANAGEMENT’S DISCUSSION AND ANALYSISThis report dated March 18, 2009 is a review of the operations, current financial position, and outlook for Bonterra Oil & Gas Ltd. (“Bonterra” or the “Company”) and should be read in conjunction with the audited financial statements for the year ended December 31, 2008, together with the notes related thereto.FOrwArD-LOOkING INFOrMATIONCertain statements contained in this Management’s Discussion and Analysis (MD&A) 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 MD&A 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. COrpOrATE INFOrMATION BOArD OF DIrECTOrS G.J. Drummond, Nassau, Bahamas G.F. Fink, Calgary, Alberta C.R. Jonsson, Vancouver, British Columbia F. W. Woodward, Calgary, Alberta OFFICErS G.F. Fink – Chief Executive Officer R.M. Jarock – President and Chief Operating Officer G.E. Schultz – Vice President, Finance, Chief Financial Officer & Secretary rEGISTrAr & TrANSFEr AGENT Olympia Trust Company, Calgary, Alberta AUDITOrS Deloitte & Touche LLP, Calgary, Alberta SOLICITOrS Borden Ladner Gervais LLP, Calgary, Alberta BANkErS The Royal Bank of Canada, Calgary, Alberta CIBC, Calgary, Alberta STOCk LISTING The Toronto Stock Exchange, Toronto, Ontario Trading symbol: BNE hEAD OFFICE 901, 1015 – 4th Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488 wEB SITE www.bonterraenergy.com 2 9 0 2 0 4 9 2 _ B o n t e r r a S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 4 5 : 1 8 1 B a c k - - a n d r e w S u n d o g _ P D F _ B o o k h i r e s B l a c k C y a n M a g e n t a Y e l l o w BON TERRA OI L & G AS LTD. 41 M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B C M Y C 7 0 C M Y B C M Y C M Y B C M Y M 7 0 C M Y B C M Y C M C Y C M Y B C M Y Y 7 0 C M Y B C M Y M Y C M Y C M Y B C M Y M 7 0 C M Y B C M Y s l u r C C M Y B C M Y C M Y B C M Y B 7 0 C 7 0 C M Y B C M Y M 7 0 C M Y B C M Y s l u r M C M Y B C M Y Y 7 0 C M Y B C M Y s l u r Y C M Y B P r i n e c t 4 G S i F o r m a t 1 0 2 / 1 0 5 D i p c o 3 . 0 e ( p d f ) © 2 0 0 7 H e i d e l b e r g e r D r u c k m a s c h i n e n A G Suite 901, 1015 – 4th Street SW | Calgary, Alberta T2R 1J4 42 BONTERRA OIL & GAS LTD. w o l l e Y a t n e g a M n a y C k c a l B s e r i h k o o B _ F D P _ g o d n u S w e r d n a - - t n o r F 1 8 1 : 5 4 : 5 1 6 2 - 3 0 - 9 0 e s i w t e e h S a r r e t n o B _ 2 9 4 0 2 0 9 2 G A n e n i h c s a m k c u r D r e g r e b l e d i e H 7 0 0 2 © ) f d p ( e 0 . 3 o c p i D 5 0 1 / 2 0 1 t a m r o F i S G 4 t c e n i r P B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M C B Y M C 0 7 M Y M C B Y M C Y M C B Y M C 0 7 C Y M C B Y M C Y r u l s Y M C B Y M C 0 7 Y Y M C B Y M C M r u l s Y M C B Y M C 0 7 M Y M C B Y M C 0 7 C 0 7 B Y M C B Y M C Y M C B Y M C C r u l s Y M C B Y M C 0 7 M Y M C B Y M C Y M C Y M Y M C B Y M C 0 7 Y Y M C B Y M C Y C M C Y M 2 9 0 2 0 4 8 5 _ B o n t e r r a E n e r g y S h e e t w i s e 0 9 - 0 3 - 2 6 1 5 : 2 7 : 0 8 1 F r o n t - - k e r i S u n d o g _ P D F _ B o o k h i r e s C y a n M a g e n t a Y e l l o w B l a c k P A N T O N E 6 5 3 C P A N T O N E 4 1 0 C Corporate Information Board of Directors G.J. Drummond, Nassau, Bahamas G.F. Fink, Calgary, Alberta C.R. Jonsson, Vancouver, British Columbia F. W. Woodward, Calgary, Alberta Officers G.F. Fink – Chief Executive Officer R.M. Jarock – President and Chief Operating Officer G.E. Schultz – Vice President, Finance, Chief Financial Officer & Secretary Registrar & Transfer Agent Olympia Trust Company, Calgary, Alberta Auditors Deloitte & Touche LLP, Calgary, Alberta Solicitors Borden Ladner Gervais LLP, Calgary, Alberta Bankers The Royal Bank of Canada, Calgary, Alberta CIBC, Calgary, Alberta Stock Listing The Toronto Stock Exchange, Toronto, Ontario Trading symbol: BNE Head Office 901, 1015 – 4th Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488 Web Site www.bonterraenergy.com 16 BONTERRA OIL & GAS LTD. CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Z X C B CMY Z X slurY CMYM 70 Z X Y M C B CMY Z X CMY CMYC 70MY Z X Y M C B CMY Z X slurM CMYB 70 Z X Y M C B CMY Z X CMYY 70X 70 Z X Y M C B CMY Z X slurC CMYM 70 Z X Y M C B CMY Z X CY CM CMYC 70 Z X Y M C B CMY Z X slurB CMYB 70 Prinect 6GS99iFormat 102/105 Dipco 3.0e (pdf) © 2007 Heidelberger Druckmaschinen AG 

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