BNP Paribas Bank Polska
Annual Report 2010

Plain-text annual report

ANNUAL REPORT 2010 Highlights Financial ($ thousands, except per share/unit) Production revenues Funds from operations (1) Per share (1) (2) Distributions declared Per unit Percentage of funds from operations(1) Net income Per share (2) Adjusted net income(3) Per share (2) Total assets Long-term debt, net of working capital (4) Long-term debt, net of adjusted working capital(3)(4) Shareholders’ equity Capital expenditures: Exploration and development Acquisitions, net Three months ended December 31, 2010 2009 % Change Years ended December 31, 2009 2010 % Change 234,706 232,870 1% 938,726 759,423 24% 127,258 0.81 64,242 0.48 135,534 0.93 59,783 0.48 50% 44% 39,784 0.25 55,222 0.35 39,647 0.27 56,588 0.39 (6%) (13%) 7% - 6% - (7%) (2%) (10%) 526,987 3.44 252,298 1.92 447,743 3.46 217,965 2.00 48% 49% 201,581 1.32 198,760 1.30 106,606 0.82 169,767 1.31 3,342,988 3,092,129 1,021,455 881,169 1,020,318 874,409 1,877,608 1,723,583 18% (1%) 16% (4%) (1%) 89% 61% 17% (1%) 8% 16% 17% 9% 94,394 (39,801) 62,044 13,172 52% (402%) 349,481 220,514 203,845 629,999 71% (65%) Weighted average outstanding equivalent shares: (thousands)(2) Basic Diluted 156,380 157,670 146,019 148,035 7% 7% 153,094 154,832 129,263 131,233 18% 18% Operating (boe conversion – 6:1 basis) Production: Natural gas (mmcf/day) Oil and liquids (bbls/day) Total oil equivalent (boe/day) Product prices:(5) Natural gas ($/mcf) Oil and liquids ($/bbl) Operating expenses ($/boe) General and administrative expenses ($/boe) Cash costs ($/boe)(6) Operating netback ($/boe)(7) 250 26,692 68,307 4.08 59.46 7.88 0.87 10.60 22.98 222 24,849 61,832 4.84 62.79 9.04 0.92 10.74 13% 7% 10% (16%) (5%) (13%) (5%) (1%) 25.53 (10%) 240 26,182 66,259 4.50 58.56 8.05 0.86 10.12 23.85 191 23,484 55,299 4.78 58.18 9.80 0.89 26% 11% 20% (6%) 1% (18%) (3%) 11.38 (11%) 23.77 - Highlights (cont’d) Drilling (gross wells): Natural gas Oil Average success rate Land: Undeveloped (net acres) Total (net acres) Reserves: (8) Proved: Natural gas (bcf) Oil and liquids (mbbls) Total oil equivalent (mboe) Proved and probable: Natural gas (bcf) Oil and liquids (mbbls) Total oil equivalent (mboe) % Proved producing % Proved % Probable Net present value of future cash flow before income taxes ($ millions): 0% discount rate 5% discount rate 10% discount rate Reserve life index (years): Proved Proved and probable Finding, development and acquisition costs – proved and probable ($/boe): Including changes in future development expenditures Excluding changes in future development expenditures Recycle ratio – proved and probable: (9) Including changes in future development expenditures Excluding changes in future development expenditures December 31, 2010 2009 % Change 140 77 61 99% 114 57 55 98% 1,522,867 3,003,411 1,633,649 3,004,146 840.4 83,695 223,756 1,177.4 115,578 311,811 45% 72% 28% 9,947 6,283 4,537 9.1 12.0 13.35 8.99 1.8 2.7 732.2 71,722 193,750 1,039.2 99,419 272,617 46% 71% 29% 9,676 6,497 4,876 8.6 11.5 12.01 8.20 2.0 2.9 23% 35% 11% 1% (7%) - 15% 17% 15% 13% 16% 14% (1%) 1% (1%) 3% (3%) (7%) 6% 4% 11% 10% (10%) (7%) Trust Unit Trading Statistics ($ per unit, except volume) High Low Close Average Daily Volume - Units NOTES: December 31, 2010 September 30, 2010 June 30, 2010 March 31, 2010 Three months ended 29.50 23.88 28.80 24.91 22.34 23.89 25.60 22.03 22.81 25.70 22.40 23.35 304,761 309,312 423,688 341,312 (1) Management uses funds from operations to analyze operating performance, distribution coverage and leverage. Funds from operations as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculations of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share. (2) Basic per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. Previous historical references to “unitholders”, “distributions”, “trust units” and “per unit” have now been replaced by “common shareholders”, “dividends”, “common shares”, and “per share” respectively, where applicable. (3) Amounts have been adjusted to exclude unrealized gains and losses on financial instrument contracts, their related tax impact and associated assets or liabilities. (4) Amounts exclude convertible debentures. (5) Product prices include realized gains and losses on financial instrument contracts. (6) Cash costs equal the total of operating, general and administrative, and financing expenses, calculated on a boe basis. (7) Operating netback equals production revenues including realized gains and losses on financial instrument contracts, less royalties, transportation and operating expenses, calculated on a boe basis. (8) Company interest reserves are gross reserves prior to deduction of royalties and includes any royalty interests of the Corporation. (9) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition costs per boe. MESSAGE TO SHAREHOLDERS Bonavista Energy Corporation (“Bonavista”) is pleased to report to shareholders its consolidated financial and operating results for the year ended December 31, 2010. Bonavista has continued its pattern of generating profitable results since commencing operations in 1997. Despite continued volatility in both commodity prices and capital markets throughout 2010, we remained focused on the consistent execution of Bonavista’s disciplined business strategies which has resulted in excellent operational and financial results. This past year marked the final year that Bonavista operated as an energy trust, concluding a four year undertaking focused on ensuring that Bonavista is well positioned to provide our investors with an enhanced growth profile when it converted to a dividend paying corporation. As we persevered in adding incremental operational and capital efficiencies to our business through cost discipline, we continued to assemble a robust inventory of growth opportunities through both organic development and strategic acquisitions in 2010. Complementing our transformational Hoadley acquisition in our Western Core Region in 2009, we closed another significant acquisition in the second quarter of 2010 of liquids rich, natural gas weighted assets (the “Acquired Properties”) adding a high quality, opportunity rich extension to our Western Core Region within the Deep Basin of Alberta. Bonavista closed this acquisition on May 31, 2010 for a cash purchase price of $230.4 million, which was partially funded by our $177.0 million equity financing completed on April 15, 2010. The Acquired Properties have provided Bonavista the opportunity to expand our application of leading technologies to access large, underdeveloped reservoirs, similar to our efforts over the past two years in our Western Core Region. On December 14, 2010 Bonavista announced the receipt of security and court approvals for its conversion to a corporation. With securityholders voting 99.95% in favour of our plan of arrangement, the conversion became effective on December 31, 2010 and the common shares of Bonavista began trading under the symbol “BNP” on the Toronto Stock Exchange on January 7, 2011. Prompted by our desire to strike a healthy balance between sustainable growth and yield, Bonavista established an initial dividend rate of $0.12 per common share per month commencing January 2011. This new dividend level, although reduced by 25% from prior trust distribution levels, represents a meaningful dividend yield of approximately 5% based on the current trading price of Bonavista’s common shares. As a result of the lower payout ratio, the incremental cash flow available for reinvestment is now being allocated to our low risk, high-impact resource development programs that offer solid rates of return. Furthermore, these programs exhibit attractive capital efficiencies which we expect will provide annual production growth of 5% to 7% over a sustained period of time. With our proven underlying operating strategies remaining intact through our corporate conversion, our business model has been designed to deliver long-term total shareholder returns of between 10 and 15% per annum. Specific accomplishments for Bonavista in 2010 include: Increased production volumes to a record level of 66,259 boe per day. This represents a 20% increase over our production levels in 2009. We are currently producing 67,800 boe per day after accounting for recent asset dispositions of approximately 1,000 boe per day; Increased proved and probable reserves by 14% to 311.8 mmboe; Added 63.4 mmboe of proved and probable reserves, which replaced 2010 annual production by 262%; Improved our proved and probable reserve life index to 12.0 years from 11.5 years in 2009 and increased our proved reserve life index to 9.1 years from 8.6 years in 2009; Achieved attractive finding, development and acquisition costs, including changes in future development expenditures, of $14.48 per boe on a proved basis ($10.52 per boe excluding changes in future development expenditures) and $13.35 per boe on a proved and probable basis ($8.99 per boe excluding changes in future development expenditures). Increased proved and probable future development capital by 39% to $986 million representing the significant development and growth potential yet to be realized on our asset base; Attained a 2010 proved and probable operating netback recycle ratio of 1.8:1 as a result of this level of finding, development and acquisition costs, including future development capital (2.7:1 recycle ratio excluding future development costs); Executed an effective capital program in 2010 investing $349.5 million in exploration and development activities drilling 140 wells with an overall 99% success rate. We invested an additional $220.5 million on 18 synergistic A&D property transactions within our core regions which includes the previously mentioned $230.4 million Deep Basin Acquisition and is net of $65.6 million in non-core asset dispositions;  Drilled 97 successful horizontal wells which include unconventional resource development in the Glauconite, Cardium, Montney, Viking, Bluesky and Rock Creek horizons. The key highlights of our horizontal drilling program are as follows:  Hoadley Glauconite Drilled 35 operated horizontal wells and participated in seven non-operated horizontal wells on the highly prospective Hoadley Glauconite trend in our Western Core Region. Our Hoadley Glauconite liquids rich natural gas development program remains the cornerstone of growth for our company and continues to impress with a predictable production profile and attractive economics even in today’s compressed natural gas price environment. Bonavista has now participated in the drilling of 66 horizontal Glauconite wells since 2008 and the results of the producing wells to date continue to meet our expectations. Despite our robust drilling activity, we have consistently grown our inventory of future opportunities through land consolidation activities and successful step out development. Bonavista believes that our Glauconite horizontal development program is one of the most profitable liquids rich natural gas resource developments in North America with economics that outperform many oil projects being developed today. Single well economics are exceptionally attractive and provide abundant capital spending flexibility with half cycle breakeven economics of approximately $2.00 per mcf.  Cardium Light Oil Drilled 13 horizontal wells and participated in 8 additional non-operated horizontal wells on the emerging unconventional Cardium light oil play in our Western Core Region. With 29 horizontal Cardium wells drilled to date, we’ve experienced a meaningful improvement in production rates resulting from a greater understanding of the geological model, successful refinement of our completion techniques and a robust level of industry activity within all areas of the known Cardium trends. With the majority of our 300 section land base currently being held by production, we have the comfort to prudently advance our development program and focus on gaining continued improvement in average well results. We anticipate the potential to accelerate development of our currently identified drilling inventory of 120 locations if we continue to see positive improvements in production results in 2011.  Deep Basin Liquids Rich Natural Gas Drilled four horizontal wells on lands we acquired through the Deep Basin acquisition which closed in May 2010. With three Bluesky and six Rock Creek horizontal wells drilled to date, initial test results are positive and we will continue to allocate capital to these plays in 2011. At Pine Creek, our initial Bluesky well drilled on the acquisition lands was brought on production in the fourth quarter at 620 boe per day and is currently at 560 boe per day after four months of production and is supported by an attractive liquids yield of 40 bbls per mmcf. Similarly, our first two Rock Creek wells drilled at Rosevear have recently been brought on-stream with a first month production average of 500 boe per day which includes natural gas liquids of 25 bbls per mmcf. In addition to the development of the Acquired Properties, we continue to pursue multiple liquids rich natural gas plays on heritage lands throughout the deep basin. Including both acquisition and heritage lands, we currently have identified 180 horizontal drilling locations, which offer attractive capital efficiencies targeting the Bluesky, Rock Creek, Notikewin, Pekisko, Mannville and Wilrich horizons.  Blueberry Montney Assembled a contiguous land position of 55 net sections in the Blueberry area of North East British Columbia which is prospective for unconventional resource development in both the upper and lower Montney horizons. 2010 marked the commencement of our delineation program with one vertical well and two horizontal wells drilled into the upper Montney formation. Initial testing has produced a high heat content natural gas stream plus a significant quantity of free condensate totaling a combined liquids yield of approximately 80 to 150 bbls per mmcf. While the high liquids yield can drive attractive netbacks at current commodity prices, the elevated quantities tested to date have prompted us to pursue detailed core and reservoir simulation work prior to proceeding with a scalable development program at this point.  Participated at Crown land sales in 2010 purchasing approximately 119,000 net acres of undeveloped land spending $63.8 million. This represents a record participation level at Crown land sales for Bonavista and will enhance our ability to generate profitable drilling opportunities for many years to come; Continued to achieve significant improvements in our cost structure with operating costs on a per boe basis decreasing 18% for the year ended December 31, 2010 to $8.05 per boe from $9.80 per boe in the comparable period of 2009. These improvements stem from continued cost discipline in all operating areas and continued development drilling in areas where we own and operate infrastructure with ample processing capacity; Generated funds from operations of $527.0 million ($3.44 per share) for the year ended December 31, 2010. Bonavista distributed 48% of these funds to shareholders with the remaining funds reinvested in the business to continue growing our production base; Completed the renewal of Bonavista’s $1.4 billion bank credit facility for an additional three year term to September 10, 2013. On March 3, 2011, Bonavista elected to reduce the committed amount of its bank credit facility by $400 million from $1.4 billion to $1.0 billion as a result of debt capacity created from Bonavista’s issuance of senior unsecured notes and the desire to reduce the cost of carrying the larger undrawn facility. Additionally, on November 2, 2010, Bonavista completed the issuance of approximately $350 million of senior unsecured notes by way of a private placement for a total of $400 million issued during 2010. The notes issued in November have a blended rate of 4.1% and a weighted average term of approximately 8.8 years; Continued to achieve profitability with a return on equity of 11% and an adjusted net income to funds from operations ratio of 38% for the year ended December 31, 2010. The above ratios reflect net income adjusted to negate the after tax impact of the unrealized gains and losses on financial instrument contracts; and Since inception as a trust, and continuing in our new legal structure as a dividend paying corporation, Bonavista has delivered over $2.0 billion or $23.27 per common share of cumulative dividends. Strengths of Bonavista Energy Corporation Beginning in 1997 with an initial restructuring to create a high growth junior exploration company, throughout the income trust phase between 2003 and 2010, and now operating as a dividend paying corporation, Bonavista remains committed to the same strategies that have resulted in our tremendous success over the last thirteen years. We have maintained a high level of investment activity on our asset base, increasing current production by approximately 95% since converting to an energy trust in 2003. This activity stems from the operational and technical focus of our people, their attention to detail, and their entrepreneurial approach to generating low risk, highly profitable projects within the Western Canadian Sedimentary Basin. Our experienced technical teams have a solid understanding of our assets and they continue to exercise the discipline and commitment required to deliver long-term value to our shareholders. We actively participate in undeveloped land acquisitions through Crown land sales, property purchases and farm-in opportunities, which have all enhanced the quality and quantity of our extensive drilling inventory. These activities have led to low cost reserve additions, lengthening of our reserve life index, and a production base that continues to grow at a healthy pace. Our production base is currently weighted 61% towards natural gas and is geographically focused within select, multi-zone regions primarily in Alberta and British Columbia. The low cost structure of our asset base maintains attractive operating netbacks in most operating environments. In addition, our asset base is predominantly operated by Bonavista, providing control over the pace of operations and ensuring that operating and capital cost efficiencies are consistently optimized. Our team brings a successful track record of executing low to medium risk development programs, including both asset and corporate acquisitions, along with a solid track record of sound financial management. Our Board of Directors and management team possess extensive experience in the oil and natural gas business. They have successfully guided our organization through many different economic cycles utilizing a proven strategy consisting of disciplined cost controls and prudent financial management. Directors, management and employees also own approximately 15% of the equity of Bonavista, resulting in the alignment of interests with all shareholders. MANAGEMENT’S DISCUSSION AND ANALYSIS Management’s discussion and analysis (“MD&A”) of the financial condition and results of operations should be read in conjunction with Bonavista Energy Corporation’s (“Bonavista” or the “Corporation”) audited consolidated financial statements for the year ended December 31, 2010. The following MD&A of the financial condition and results of operations was prepared at, and is dated March 3, 2011. Our audited consolidated financial statements, Annual Report, and other disclosure documents for 2010 will be available on or before March 31, 2011 through our filings on SEDAR at www.sedar.com or can be obtained from Bonavista’s website at www.bonavistaenergy.com Basis of Presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent (“boe”) using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. A boe may be misleading, particularly if used in isolation. A boe conversion of 6 mcf to one barrel is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Forward-Looking Statements - Certain information set forth in this document, including management’s assessment of Bonavista’s future plans and operations, contains forward-looking statements including: (i) forecasted capital expenditures; (ii) exploration, drilling and development plans; (iii) prospects and inventory; (iv) anticipated production rates; (v) expected royalty rate; (vi) anticipated operating and service costs; (vii) our financial strength; (viii) incremental development opportunities; (ix) anticipated natural gas supply and demand; (x) reserve life index; (xi) utilization of technology; and (xii) rate of return and dividend yield, which are provided to allow investors to better understand our business. By their nature, forward-looking statements are subject to numerous risks and uncertainties; some of which are beyond Bonavista’s control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, changes in environmental tax and royalty legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Bonavista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward- looking statements or if any of them do so, what benefits that Bonavista will derive there from. Bonavista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. Investors are also cautioned that dividend yield represents a blend of return of an investor’s initial investment and a return on investors' initial investment and is not comparable to traditional yield on debt instruments where investors are entitled to full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Non-GAAP Measurements - Within Management’s discussion and analysis, references are made to terms commonly used in the oil and natural gas industry. Management uses "funds from operations" and the "ratio of debt to funds from operations" to analyze operating performance and leverage. Funds from operations as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital and abandonment expenditures. Funds from operations per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of net income per share. Operating netbacks equal production revenue and realized gains and losses on financial instrument contracts, less royalties, transportation and operating expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the number of days in the period. Corporate conversion - On December 31, 2010, Bonavista Energy Trust (the “Trust”) completed its conversion from an energy trust to a dividend paying corporation pursuant to a plan of arrangement (the “Arrangement”) under Section 193 of the Business Corporations Act (Alberta). The conversion involved the internal reorganization of the Trust and certain subsidiaries through which the trust structure was replaced with the corporate structure of the Corporation. Bonavista owns, directly or indirectly, the same assets that were owned by the Trust immediately prior to the effective date of the conversion and assumed all of the obligations of the Trust. In addition, the directors and officers remain unchanged. Pursuant to the Arrangement, unitholders received one common share of Bonavista for each trust unit held and exchangeable shareholders of Bonavista Petroleum Ltd. received 2.40917 exchangeable shares of Bonavista for each exchangeable share held. In conjunction with the Arrangement, a stock option plan and restricted share award incentive plan were established and the common share rights incentive plan (formerly the trust unit rights incentive plan of the Trust) and the restricted common share incentive plan (formerly the restricted trust unit incentive plan of the Trust) were amended. These plans are further outlined in note 9 of the notes to the consolidated financial statements of Bonavista. The common shares of Bonavista began trading on the Toronto Stock Exchange on January 7, 2011 under the trading symbol BNP. Beginning with the January 31, 2011 record date, shareholders of the Corporation will receive payments in the form of dividends. Prior to the conversion of the Trust to Bonavista on December 31, 2010, distributions were paid to unitholders. Previous historical references to “unitholders”, “distributions”, “trust units” and “per unit” have now been replaced by “common shareholders”, “dividends”, “common shares”, and “per share”, respectively, where applicable. Bonavista will continue with the business activities and business strategies of the Trust. The business plan of Bonavista is to create sustainable and profitable per share growth in reserves, production and cash flow while delivering a consistent dividend to our shareholders. To accomplish this, Bonavista will pursue an integrated growth strategy with active development and exploration drilling within its core areas, together with focused acquisitions, similar to the strategies previously pursued by the Trust. Operations - Bonavista's exploration and development program for year ended December 31, 2010 led to the drilling of 140 wells in our three core regions with an overall success rate of 99%. This program resulted in 77 natural gas wells and 61 oil wells. A strong recycle ratio driving a high level of profitability continues to guide our exploration and development program which remains flexible to changes in commodity price, development risk and deliverability upside. Once again, our operations for the year have resulted in superior capital efficiencies driven off of strong production performance, healthy reserve additions and a disciplined approach to spending with every well drilled. These activities continue to enhance the predictability in our overall production base, in addition, to lengthening our reserve life index ("RLI") to approximately 12.0 years on a proved plus probable basis. Reserves - Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of Disclosure (“NI 51-101”). Under NI 51-101, proved reserves are defined as reserves that can be estimated with a high degree of certainty to be recoverable with a target of a 90% probability that the actual reserves recovered over time will equal or exceed proved reserve estimates, while probable reserves are defined as having an equal (50%) probability that the actual reserves recovered will equal or exceed the proved and probable reserve estimates. In accordance with NI 51-101, proved undeveloped reserves have been recognized in cases where plans are in place to bring the reserves on production within a short, well defined time frame. Proved undeveloped reserves often involve infill drilling into existing pools. Of the net present value of the Corporation's reserves, 84% were evaluated by independent third party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") and Ryder Scott Company Canada (“Ryder Scott”) in their reports dated February 25, 2011 and February 11, 2011, respectively. The balance of approximately 16% of proved and probable net present value reserves were evaluated internally and reviewed by GLJ. The reserve estimates contained in the following tables represent Bonavista’s gross reserves as at December 31, 2010: Natural Gas (MMcf) Reserves:(1)(4) Proved: Proved producing Proved non-producing Proved undeveloped Total proved Probable Total proved and probable Proved reserve life index, years(3) Proved and probable reserve life index, years(3) 509,869 26,634 299,443 835,946 335,938 1,171,884 Light and Medium Oil (Mbbls) Heavy Oil (Mbbls) Natural Gas Liquids (Mbbls) Total Reserves(2) (Mboe) 25,729 592 6,284 32,605 9,734 42,340 5,062 1,133 502 6,698 2,591 9,289 24,403 1,000 18,891 44,294 19,513 63,806 140,172 7,165 75,585 222,921 87,828 310,749 9.1 12.0 (1) (2) (3) (4) Bonavista’s gross reserves before royalties, based on the GLJ and Ryder Scott reserve reports dated February 25, 2011 and February 11, 2011 respectively, GLJ and Ryder Scott reserve estimates based on forecast prices and costs as of January 1, 2011. Boes 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. Calculated based on the amount for the relevant reserve category divided by the 2011 production forecast. Amounts may not add due to rounding. Reserve Reconciliation: Balance, December 31, 2009 Extensions and improved recovery Technical revisions Acquisitions Dispositions Economic factors Production Balance, December 31, 2010 Proved (Mboe) 193,187 24,124 11,462 21,008 (1,909) (788) (24,163) 222,921 Probable (Mboe) 78,726 8,459 (5,447) 7,363 (907) (366) - 87,828 Proved and Probable (Mboe) 271,913 32,583 6,015 28,371 (2,816) (1,154) (24,163) 310,749 Bonavista’s 2010 year-end proved reserves totalled 222.9 mmboe, a 15% increase compared to the 193.2 mmboe at the year-end of 2009. Furthermore, Bonavista’s proved and probable reserves increased by 14% to 310.7 mmboe when compared to the 271.9 mmboe at year-end 2009. The Corporation had proved and probable positive reserve revisions of 5.2 mmboe which were primarily related to improved performance at three properties in British Columbia and enhanced liquid recoveries in our Hoadley Glauconite development. Proved and Probable Finding, Development and Acquisition Costs:(1) Total capital expenditures ($ millions) Total capital expenditures plus change 2010 570.0 2009 833.8 2008 482.3 in forecast future development costs ($ millions) 846.3 1,221.8 594.4 Proved and probable reserves (Mboe): Opening balance Discoveries and extensions Acquisitions and dispositions Revisions and economic factors Production Closing balance Proved and probable FD&A costs ($/boe) Proved and probable three-year FD&A costs ($/boe) (2) (2) 271,913 32,583 25,555 4,861 (24,163) 190,240 21,799 84,087 (4,061) (20,152) 178,575 23,861 10,373 (3,410) (19,159) 310,749 271,913 190,240 13.43 14.85 12.01 15.68 19.11 16.77 (1) (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. Amounts are calculated including the change in future development costs. Finding, development and acquisition costs in 2010, including changes in future capital expenditures, amounted to $14.56 per boe ($10.58 per boe before changes in future capital expenditures) on a proved basis and $13.43 per boe ($9.05 per boe before changes in future capital expenditures) on a proved and probable basis. Capital Efficiency: Operating netback ($/boe) Total capital expenditures (1) (excluding future development costs) Proved and probable FD&A costs ($/boe) Recycle ratio (3) (2) Total capital expenditures (including future development costs) Proved and probable FD&A costs ($/boe) Recycle ratio (3) 2010 23.85 9.05 2.6 13.43 1.8 2009 23.77 8.20 2.9 12.01 2.0 2008 35.49 15.50 2.3 19.11 1.9 Three-Year Average 27.70 10.92 2.6 14.85 1.9 (1) Operating netback is calculated using production revenues including realized gains or losses on financial instruments contracts less royalties, transportation and operating costs calculated on a per barrel of oil equivalent basis. FD&A costs take into account reserve revisions during the year on a per barrel of oil equivalent basis (6:1). Recycle ratio is defined as operating netback per barrel of oil equivalent divided by finding, development and acquisition costs on a per barrel of oil equivalent. (2) (3) Bonavista generated an attractive recycle ratio of 1.8:1 for proved and probable reserves and 1.6:1 for proved reserves which includes revisions and changes in future development expenditures; excluding changes in future development expenditures, the proved and probable recycle ratio improved to 2.6:1 and the proved recycle ratio improved to 2.3:1. Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista’s Annual Information Form that will be filed on SEDAR. Financial and operating highlights - The following is a summary of key financial and operating results for the respective periods noted: ($ thousands, except per boe and share/unit amounts where noted) Three months ended December 31, 2009 2010 Years ended December 31, 2009 2010 Product prices: Natural gas ($/mcf) Oil and liquids ($/bbl) Production: Natural gas (mmcf/d) Oil and liquids (bbls/d) Total production (boe/d) Production revenues per boe Royalties per boe % of Production revenues Operating expenses per boe Transportation expenses per boe General and administrative expenses per boe Financing expenses per boe Unit-based compensation per boe Depreciation, depletion and accretion per boe Income taxes (recovery) per boe Net income per boe per share – basic Distributions declared per unit Funds from operations per boe per share – basic 4.08 59.46 4.84 62.79 4.50 58.56 4.78 58.18 250 26,692 68,307 234,706 37.35 35,071 5.58 14.9% 49,494 7.88 10,677 1.70 5,441 0.87 10,956 1.74 3,045 0.48 91,552 14.56 (16,034) (2.55) 39,784 6.33 0.25 64,242 0.48 127,258 20.25 0.81 222 24,849 61,832 232,870 40.94 36,347 6.39 15.6% 51,407 9.04 9,435 1.66 5,227 0.92 4,456 0.78 2,939 0.52 85,229 14.99 (15,825) (2.78) 39,647 6.97 0.27 59,783 0.48 135,534 23.83 0.93 240 26,182 66,259 938,726 38.82 143,507 5.93 15.3% 194,755 8.05 39,652 1.64 20,897 0.86 28,272 1.17 11,584 0.48 354,593 14.66 (21,888) (0.91) 201,581 8.34 1.32 252,298 1.92 526,987 21.79 3.44 191 23,484 55,299 759,423 37.62 117,217 5.81 15.4% 197,795 9.80 36,833 1.82 17,900 0.89 14,035 0.70 11,386 0.56 295,296 14.63 (52,627) (2.61) 106,606 5.28 0.82 217,965 2.00 447,743 22.18 3.46 Production - For the year ended December 31, 2010, production increased 20% to a record level of 66,259 boe per day when compared to 55,299 boe per day for the same period a year ago. Natural gas production increased 26% to 240 mmcf per day in 2010 from 191 mmcf per day for the same period a year ago, while total oil and liquids production increased 11% to 26,182 bbls per day in 2010 from 23,484 bbls per day for the same period in 2009. For the fourth quarter of 2010, production increased 10% to 68,307 boe per day when compared to 61,832 boe per day for the same period a year ago. Natural gas production increased 13% to 250 mmcf per day in the fourth quarter of 2010 from 222 mmcf per day for the same period a year ago, while total oil and liquids production increased 7% to 26,692 bbls per day in the fourth quarter of 2010 from 24,849 bbls per day for the same period in 2009. The following table highlights Bonavista's production by product for the three months and years ended December 31: Natural gas (mmcf/day) Oil and liquids (bbls/day): Light and medium oil Heavy oil Total oil and liquids (bbls/day) Total oil equivalent (boe/day) Three months ended December 31, 2009 2010 Years ended December 31, 2009 2010 250 222 240 191 22,342 4,350 26,692 68,307 19,864 4,985 24,849 61,832 21,395 4,787 26,182 66,259 18,037 5,447 23,484 55,299 Our current production is approximately 67,800 boe per day, consisting of 61% natural gas, 33% light and medium oil and 6% heavy oil after accounting for approximately 1,000 boe per day of recent asset divestitures. Production revenues - Production revenues for the year ended December 31, 2010 increased 24% to $938.7 million when compared to $759.4 million for the same period a year ago, due mainly to a 20% increase in production volumes. For the year ended December 31, 2010, natural gas prices decreased 6% to $4.50 per mcf, when compared to $4.78 per mcf realized in the same period in 2009. The average oil and liquids price increased 1% to $58.56 per bbl for the year ended December 31, 2010 from $58.18 per bbl for the same period in 2009. For the fourth quarter of 2010, production revenues increased 1% to $234.7 million when compared to $232.9 million for the same period a year ago. This increase was due in part to a 10% increase in production volumes offset by an 11% decrease in product pricing in the fourth quarter of 2010 as compared to the same period in 2009. In the fourth quarter of 2010, natural gas prices decreased 16% to $4.08 per mcf, when compared to $4.84 per mcf realized in the same period in 2009. The average oil and liquids price decreased 5% to $59.46 per bbl for the fourth quarter 2010 from $62.79 per bbl for the same period in 2009. The following table highlights Bonavista's realized product pricing for the three months and years ended December 31: Natural gas ($/mcf): Production revenues Realized gain on financial instrument contracts Light and medium oil ($/bbl): Production revenues Realized gain on financial instrument contracts Heavy oil ($/bbl): Production revenues Realized gain on financial instrument contracts Total ($/boe): Production revenues Realized gain on financial instrument contracts Three months ended December 31, 2009 2010 Years ended December 31, 2009 2010 $ 3.86 0.22 4.08 $ 4.72 0.12 4.84 $ 4.33 0.17 4.50 $ 4.48 0.30 4.78 59.02 0.01 59.03 61.68 - 61.68 58.35 3.70 62.05 65.16 0.54 65.70 58.01 0.07 58.08 60.68 0.04 60.72 37.35 0.78 $ 38.13 40.94 1.68 $ 42.62 38.82 0.66 $ 39.48 51.67 7.22 58.89 53.74 2.08 55.82 37.62 3.57 $ 41.19 Commodity price risk management - As part of our financial management strategy, Bonavista has adopted a disciplined commodity price risk management program. The purpose of this program is to stabilize funds from operations against volatile commodity prices, costs and protect economics of capital invested. Bonavista’s Board of Directors has approved a commodity price risk management limit of 60% of forecast production, net of royalties, primarily using costless collars. Our strategy of using costless collars limits Bonavista’s exposure to downturns in commodity prices, while allowing for participation in commodity price increases. For the year ended December 31, 2010, our risk management program on financial instrument contracts resulted in a gain of $19.8 million, consisting of a realized gain of $16.1 million and an unrealized gain of $3.7 million. The realized gain of $16.1 million consisted of a $15.5 million gain on natural gas commodity derivative contracts and a $600,000 gain on crude oil commodity derivative contracts. For the same period in 2009, our risk management program on financial instruments contracts resulted in a net loss of $13.6 million, consisting of a realized gain of $72.1 million and an unrealized loss of $85.7 million. The realized gain of $72.1 million consisted of a $20.4 million gain on natural gas commodity derivative contracts and a $51.7 million gain on crude oil commodity derivative contracts. For the fourth quarter of 2010, our risk management program on financial instrument contracts resulted in a net loss of $16.1 million, consisting of a realized gain of $4.9 million and an unrealized loss of $21.0 million. The realized gain of $4.9 million is related entirely to a gain on natural gas commodity derivative contracts. For the same period in 2009, our risk management program on financial instruments contracts resulted in a loss of $13.5 million, consisting of a realized gain of $9.5 million and an unrealized loss of $23.0 million. The realized gain of $9.5 million consisted of a $2.5 million gain on natural gas commodity derivative contracts and a $7.0 million gain on crude oil commodity derivative contracts. Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for crude oil and natural gas are impacted not only by global economic events that dictate the levels of supply and demand but also by the relationship between the Canadian and United States dollar. Bonavista has attempted to mitigate a portion of the commodity price risk through the use of various financial instrument contracts and physical delivery sales contracts. i) Financial instrument contracts: As at December 31, 2010, Bonavista entered into the following costless collars to sell natural gas and crude oil as follows: Volume Average Price Term 10,000 gjs/d CDN$5.13 - CDN$7.75 - AECO 10,000 gjs/d CDN$4.30 - CDN$5.55 - AECO 5,000 gjs/d CDN$4.50 - CDN$7.24 - AECO 10,000 gjs/d CDN$5.25 - CDN$7.20 - AECO 9,500 bbls/d CDN$79.58 - CDN$97.09 - WTI 2,000 bbls/d CDN$81.25 - CDN$100.01 - WTI January 1, 2011 - March 31, 2011 April 1, 2011 - October 31, 2011 January 1, 2011 - October 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2012 - December 31, 2012 Subsequent to December 31, 2010 Bonavista entered into the following costless collars to sell natural gas and crude oil as follows: Volume Average Price Term 5,000 5,000 1,000 gjs/d CDN$3.50 - CDN$4.28 - AECO gjs/d CDN$3.60 - CDN$4.60 - AECO bbls/d CDN$87.50 - CDN$110.00 - WTI April 1, 2011 - October 31, 2011 April 1, 2012 - October 31, 2012 January 1, 2012 - December 31, 2012 As at December 31, 2010, Bonavista entered into the following option contracts to manage its overall commodity exposure: Volume Price Contract Term 28,000 10,000 1,000 500 1,000 gjs/d CDN$4.07 gjs/d CDN $6.45 bbls/d CDN$100.00 bbls/d USD$102.50 bbls/d CDN$105.00 Swap - AECO Sold Call - AECO Sold Call - WTI Sold Call - WTI Sold Call - WTI April 1, 2011 - October 31, 2011 April 1, 2011 - October 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2012 - December 31, 2012 Subsequent to December 31, 2010, Bonavista entered into the following options contracts to manage its overall commodity exposure: Volume Average Price Contract Term 5,000 gjs/d CDN$3.72 500 bbls/d USD$105.00 Swap - AECO Sold Call - WTI April 1, 2011 - October 31, 2011 February 1, 2011 - December 31, 2011 Financial instrument contracts are recorded on the consolidated balance sheet at fair value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated statements of operations, comprehensive income and accumulated earnings. As at December 31, 2010, the fair market value recorded on the consolidated balance sheet for these financial instrument contracts was a net liability of $5.8 million, compared to a net liability of $9.5 million as at December 31, 2009. These financial instrument contracts had the following gains and losses reflected in the consolidated statements of operations, comprehensive income and accumulated earnings: Realized gains on financial instrument contracts Unrealized gains (losses) on financial Three months ended December 31, 2009 2010 Years ended December 31, 2009 2010 $ 4,927 $ 9,536 $ 16,080 $ 72,100 instrument contracts (21,024) (22,998) 3,764 (85,746) $ (16,097) $ (13,462) $ 19,844 $ (13,646) Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instrument contracts. A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $900,000 on net income for those financial instrument contracts that were in place as at December 31, 2010. A $1.00 change in the price per barrel of oil – WTI would have an impact of approximately $2.2 million on net income for those financial instrument contracts that were in place as at December 31, 2010. ii) Physical purchase and sale contracts: As at December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as follows: Volume Average Price Term 10,000 gjs/d CDN$5.00 - CDN$7.34 - AECO 10,000 gjs/d CDN$5.13 - CDN$6.99 - AECO 7,000 gjs/d CDN$4.15 - AECO January 1, 2011 - March 31, 2011 January 1, 2011 - December 31, 2011 April 1, 2011 - October 31, 2011 As at December 31, 2010, Bonavista entered into the following contracts to purchase electricity as follows: Volume Average Price Term 6 mw/h CDN$50.37 - AESO mw/h CDN$51.00 - AESO 1 January 1, 2011 - December 31, 2011 January 1, 2011 - December 31, 2012 Subsequent to December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as follows: Volume Average Price Term 12,500 gjs/d CDN$3.84 - AECO April 1, 2011 - October 31, 2011 Physical purchase and sale contracts are being accounted for as they are settled. Royalties - For the year ended December 31, 2010, royalties increased by 22% to $143.5 million from $117.2 million for the same period a year ago, largely attributed to a 20% increase in production volumes. In addition, royalties as a percentage of revenues (including the year ended December 31, 2010 increased to 15.0% compared to 14.1% in 2009, largely due to the impact of lower realized gains on financial instruments contracts and a higher percentage of natural gas liquids production volumes that attract higher royalty rates. For the three months ended December 31, 2010, royalties decreased by 4% to $35.1 million from $36.3 million from the same period a year ago, largely due to a decrease in product pricing as compared to the same period in 2009. In addition, royalties as a percentage of revenues (including realized gains and losses on financial instrument contracts) for the fourth quarter of 2010 decreased to 14.6% as compared to 15.0% in 2009, for the same reasons as discussed above. instrument contracts) realized gains on financial for The following table highlights Bonavista's royalties by product for the three months and years ended December 31: Natural gas ($/mcf): Royalties % of revenues (1) Light and medium oil ($/bbl): Royalties % of revenues (1) Heavy oil ($/bbl): Royalties % of revenues (1) Three months ended December 31, 2009 2010 Years ended December 31, 2009 2010 0.37 9.0% 10.90 18.5% 10.71 17.4% 0.51 10.5% 11.59 18.7% 10.54 16.0% 0.44 9.7% 11.03 19.0% 10.86 17.9% 0.59 12.3% 9.05 15.4% 8.47 15.2% (1) % of revenues include realized gains and losses on financial instrument contracts On January 1, 2009 the Alberta Government’s New Royalty Framework (“NRF”) took effect. Subsequent to this legislation the Government of Alberta has introduced a number of programs to stimulate new and continued economic activity in Alberta. The Transitional Royalty Plan (“TRP”), which expires December 31, 2013, offers reduced royalty rates for new wells drilled that meet certain depth requirements. In addition to the TRP, a second royalty incentive program was announced by the Government of Alberta. The Three Point Incentive Plan includes a drilling royalty credit for new conventional oil and natural gas wells and a new royalty incentive program which is set to expire on March 31, 2011. On March 11, 2010 the Alberta Competitiveness Review board made a number of recommendations for further improvements to Alberta’s current royalty structure. These recommendations are effective on a permanent basis for the January 2011 production month and are outlined as follows: The current incentive program rate of 5% on new natural gas and conventional oil wells will become a permanent feature of the royalty system, with the current time and volume limits; The maximum royalty rate for conventional oil will be reduced at higher price levels from 50% to 40% to provide better risk-reward balance to investors; Recognizing the fundamental changes to the North American supply/demand balance and increased competition from other jurisdictions, the maximum royalty rate for conventional and unconventional natural gas will be reduced at higher price levels from 50% to 36%; and The NRF legislated in November 2008 will continue until its original announced expiration on December 31, 2013. Effective January 1, 2011, no new wells will be allowed to select the transitional royalty rates. On May 27, 2010 the Government of Alberta revealed its proposed changes to the base royalty curves for both conventional oil and natural gas, which take effect on January 1, 2011. The Government also unveiled further initiatives, as a result of the competiveness review, intended to energize investment and encourage development of Alberta’s unconventional and deep resource pools. The most significant of these initiatives are modifications to the natural gas deep drilling program and the implementation of the emerging resources and technologies initiative. Bonavista has identified approximately 190 horizontal drilling prospects in our Western Region that will benefit from the reduction in qualifying depth of the deep drilling program from 2,500 to 2,000 meters true vertical depth. This depth change will result in a significant royalty credit of approximately $1.0 million per horizontal well. Operating expenses - Operating expenses for the year ended December 31, 2010 decreased 2% to $194.8 million compared to $197.8 million for the same period a year ago. Operating expenses for the fourth quarter of 2010 decreased 4% to $49.5 million compared to $51.4 million for the same period a year ago, due to increased production volumes in areas with lower associated per boe operating expenses. Operating expenses per unit of production for the year ended December 31, 2010 decreased 18% to $8.05 per boe, from $9.80 per boe in the comparable period of 2009. For the three months ended December 31, 2010 operating expenses per unit of production decreased 13% to $7.88 per boe from $9.04 per boe in the comparable period of 2009. This significant decrease on a per boe basis is attributed to efficiency gains derived from production additions through our recent drilling program, lower per unit operating costs from acquisitions, lower electricity costs and our ongoing operating cost reduction initiatives. The following table highlights Bonavista's operating expenses by product for the three months and years ended December 31: Natural gas ($/mcf) Light and medium oil ($/bbl) Heavy oil ($/bbl) Three months ended December 31, 2009 2010 $ 1.29 $ 1.10 10.05 9.03 14.44 14.46 Years ended December 31, 2009 2010 $ 1.41 $ 1.13 10.66 9.05 14.94 14.45 Total ($/boe) $ 7.88 $ 9.04 $ 8.05 $ 9.80 Transportation expenses - For the year ended December 31, 2010, transportation expenses increased 8% to $39.7 million compared to $36.8 million for the same period in 2009 and increased 13% to $10.7 million for the three months ended December 31, 2010 from $9.4 million in the same period in 2009. On a per boe basis for the three months ended December 31, 2010, transportation costs increased slightly to $1.70 per boe compared to $1.66 per boe in the same period in 2009 and for the year ended December 31, 2010 transportation costs decreased 10% to $1.64 per boe compared to $1.82 per boe in the same period in 2009, due to a significant increase in production volumes in areas with lower associated transportation costs. The following table highlights Bonavista's transportation expenses by product for the three months and years ended December 31: Natural gas ($/mcf) Light and medium oil ($/bbl) Heavy oil ($/bbl) Three months ended December 31, 2009 2010 $ 0.30 $ 0.33 0.94 0.86 3.53 3.40 Years ended December 31, 2009 2010 $ 0.33 $ 0.31 0.92 0.83 3.83 3.31 Total ($/boe) $ 1.70 $ 1.66 $ 1.64 $ 1.82 General and administrative expenses - General and administrative expenses, after overhead recoveries, increased 17% to $20.9 million for the year ended December 31, 2010 from $17.9 million in the same period in 2009 and increased 4% to $5.4 million for the three months ended December 31, 2010 from $5.2 million in the same period in 2009. On a per boe basis, general and administrative expenses decreased 3% for the year ended December 31, 2010 to $0.86 per boe from $0.89 per boe in the same period in 2009 and decreased 5% to $0.87 per boe for the three months ended December 31, 2010 from $0.92 per boe in the same period in 2009. Our current rate of general and administrative expenses on a boe basis remains among the lowest in our sector. For the three months and year ended December 31, 2010, Bonavista incurred restructuring costs associated with the Arrangement of $736,000 (2009 – nil). This includes legal and advisory fees as well as other associated costs. In connection with its trust unit rights incentive plan and restricted trust unit incentive plan, Bonavista recorded a unit- based compensation charge of $3.0 million and $11.6 million for the three months and year ended December 31, 2010 respectively, compared to $2.9 million and $11.4 million for the same periods in 2009. Financing expenses - Financing expenses increased 101% to $28.3 million for the year ended December 31, 2010, from $14.0 million for the same period in 2009 and on a per boe basis, increased 67% to $1.17 per boe for the year ended December 31, 2010 from $0.70 per boe for the same period in 2009. For the three months ended December 31, 2010, financing expenses increased 146% to $11.0 million from $4.5 million for the same period in 2009 and on a per boe basis, increased 123% to $1.74 per boe for the three months ended December 31, 2010 from $0.78 per boe for the same period in 2009. The increase in financing expenses for the three months and year ended December 31, 2010 compared to the same period in 2009 is the result of an increase in borrowing costs on our loan facilities, an increase in our average debt levels and an increase in interest rates. For the year ended December 31, 2010, Bonavista paid cash interest of $24.6 million compared to $14.4 million for the same period in 2009. During the fourth quarter of 2010, Bonavista paid cash interest of $8.0 million compared to $5.1 million for the same period in 2009. Bonavista's effective interest rate as at December 31, 2010 was approximately 3.7% (2009 – 1.5%). Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 20% to $354.6 million for the year ended December 31, 2010 from $295.3 million for the same period in 2009. For the three months ended December 31, 2010, depreciation, depletion and accretion expenses increased 7% to $91.6 million from $85.2 million for the same period in 2009. These increases are largely due to an increase in our overall production base compared to the same periods in 2009. For the year ended December 31, 2010, the average cost increased slightly to $14.66 per boe from $14.63 per boe for the same period in 2009. For the three months ended December 31, 2010, the average cost decreased 3% to $14.56 per boe from $14.99 per boe for the same period a year ago due to lower finding, development and acquisition costs. Income taxes - For the year ended December 31, 2010, the income tax recovery was $21.9 million compared to a recovery of $52.6 million for the same period in 2009. For the three months ended December 31, 2010, the income tax recovery was $16.1 million compared to a recovery of $15.8 million for the same period in 2009. Bonavista made no cash payments on tax installments for the three months and year ended December 31, 2010 or for the comparative periods in 2009. Funds from operations, net income and comprehensive income - For the year ended December 31, 2010, Bonavista experienced an 18% increase in funds from operations to $527.0 million ($3.44 per share, basic) from $447.7 million ($3.46 per share, basic) for the same period in 2009. The increase in funds from operations for the year ended December 31, 2010 is largely attributed to an increase in production volumes. For the three months ended December 31, 2010, Bonavista experienced a 6% decrease to $127.3 million ($0.81 per share, basic) from $135.5 million ($0.93 per share, basic) for the same period in 2009. The decrease in funds from operations for the three months ended December 31, 2010 is largely due to lower product prices. Net income and comprehensive income for the year ended December 31, 2010, increased 89% to $201.6 million ($1.32 per share, basic) from $106.6 million ($0.82 per share, basic) for the same period in 2009. For the three months ended December 31, 2010, net income and comprehensive income increased slightly to $39.8 million ($0.25 per share, basic) from $39.6 million ($0.27 per share, basic) for the same period in 2009. from operations funds in The following table is a reconciliation of a non-GAAP measure, funds from operations, to its nearest measure prescribed by GAAP: Calculation of Funds From Operations: (thousands) Cash flow from operating activities Asset retirement expenditures Changes in non-cash working capital Three months ended December 31, 2009 2010 Years ended December 31, 2009 2010 $ 115,741 7,012 4,505 $ 154,758 3,440 (22,664) $ 514,164 15,831 (3,008) $ 423,933 12,036 11,774 Funds from operations $ 127,258 $ 135,534 $ 526,987 $ 447,743 Capital expenditures - Capital expenditures for the year ended December 31, 2010 were $570.0 million, consisting of $349.5 million spent on exploration and development activities with the remaining $220.5 million spent on net property acquisitions. For the same period in 2009 capital expenditures were $833.8 million, consisting of $203.8 million on exploration and development spending and $630.0 million on net property acquisitions. Capital expenditures for the three months ended December 31, 2010 were $54.6 million, consisting of $94.4 million spent on exploration and development activities and net property dispositions of $39.8 million. For the same period in 2009, capital expenditures were $75.2 million, consisting of $62.0 million spent on exploration and development and $13.2 million spent on net property acquisitions. Our service costs supporting our exploration and development activities have experienced some pressure in the fourth quarter of 2010. A significant increase in the demand for services year over year has resulted in a modest erosion in pricing efficiency. We will continue to monitor the situation and will rely heavily on our relationships that we have cultivated over the past 13 years. The following table outlines capital expenditures by category for the years ended December 31, 2010 and 2009: (thousands) Land acquisitions Geological and geophysical Drilling and completion Production equipment and facilities Other Exploration and development expenditures Acquisitions Dispositions Net capital expenditures Years ended December 31, 2010 2009 $ 71,444 11,898 199,669 65,051 1,419 349,481 286,084 (65,570) $ 20,385 6,829 133,811 41,704 1,116 203,845 737,117 (107,118) $ 569,995 $ 833,844 Liquidity and capital resources - As at December 31, 2010, long-term debt including working capital (excluding associated assets and liabilities from financial instrument contracts and their related tax impact) was $1.0 billion with a debt to fourth quarter 2010 annualized funds from operations ratio of 2.0:1. Bonavista has significant flexibility to finance future expansions of its capital programs, through the use of its current funds generated from operations and its debt facilities. As at December 31, 2010, Bonavista has approximately $844.7 million of unused borrowing capacity from its $1.4 billion bank credit facility. In addition to the bank credit facility, Bonavista has a US$125.0 million master shelf agreement of which US$75.0 million remains undrawn. On September 10, 2010 Bonavista combined and renewed its bank credit facilities into a single facility of $1.4 billion provided by a syndicate of 12 domestic and international banks. This facility is a three year revolving facility and may at the request of Bonavista and with the consent of the lenders be extended on an annual basis. The facility has a maturity date of September 10, 2013. Under the terms of the credit facility, Bonavista has provided the covenant that its: (i) consolidated senior debt borrowing will not exceed three times net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion and accretion; (ii) consolidated total debt will not exceed three and one half times consolidated net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion and accretion; and (iii) consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus consolidated shareholders’ equity of the Corporation, in all cases calculated based on a rolling prior four quarters. On March 3, 2011, Bonavista elected to reduce the committed amount of its bank credit facility by $400 million from $1.4 billion to $1.0 billion as a result of capacity created from the issuance of senior unsecured debt and the desire to reduce the cost of carrying the larger undrawn facility. The result of this reduction will leave Bonavista with $444.7 million of undrawn borrowing capacity, proforma as at December 31, 2010. In the second quarter of 2010, Bonavista entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125 million in notes at a rate equal to the related US treasury rate corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. On June 4, 2010 Bonavista drew down US$50 million on the master shelf agreement with a coupon rate of 4.86% with US$25 million maturing on June 4, 2016 and the remaining US$25 million maturing on June 4, 2017. Under the terms of the master shelf agreement, the Corporation has provided the same significant covenants that exist under the bank credit facility. On November 2, 2010, Bonavista issued by way of a private placement US$300 million and CDN$50 million of long-term notes with a weighted average coupon rate of 4.12% and a weighted average term of 8.8 years. Proceeds from the issuance were used to repay existing long-term debt under the bank credit facility. In 2011, Bonavista plans to invest between $345 and $375 million on its capital programs within its core regions. Bonavista intends on financing its 2011 capital program with a combination of funds from operations and to the extent required its existing credit facilities. Going forward, Bonavista remains committed to the fundamental principle of maintaining financial flexibility and the prudent use of debt. Shareholders’ and Unitholders’ equity – On December 31, 2010, pursuant to the Arrangement, unitholders received one common share of Bonavista for each trust unit held, in addition, exchangeable shareholders of Bonavista Petroleum Ltd. received 2.40917 exchangeable shares of Bonavista for each exchangeable share held. As at December 31, 2010, Bonavista had 156.6 million equivalent common shares outstanding, which includes 22.6 million exchangeable shares. As at March 3, 2011, Bonavista had 156.8 million equivalent common shares outstanding. This includes 22.2 million exchangeable shares, which are exchangeable into 22.3 million common shares. The exchange ratio in effect at March 3, 2011 for exchangeable shares was 1.00413:1. In addition, Bonavista has 5.0 million common share incentive rights outstanding as at March 3, 2011, with an average exercise price of $21.77 per common share. Contractual obligations - The following is a summary of Bonavista’s contractual obligations and commitments as at December 31, 2010: (thousands) Long-term debt repayments (1)(3) Interest payments (2)(3) Transportation expenses Office premises Total 2011 2012 2013 2014 2015 and thereafter Payments Due by Period $ 955,348 143,126 49,205 21,376 $ - 16,765 16,428 1,272 $ - 16,765 12,662 3,054 $ 555,348 16,765 9,521 3,054 $ - 16,765 5,612 3,054 $ 400,000 76,066 4,982 10,942 Total contractual obligations $1,169,055 $ 34,465 $ 32,481 $ 584,688 $ 25,431 $ 491,990 (1) (2) (3) Long-term debt repayments include the bank loan facility and principal payments due on senior unsecured notes. Based on the existing terms of the revolving bank credit facility, the amounts owing under this facility are required to be paid in 2013. Fixed interest payments on senior unsecured notes. US dollars payments are converted using the exchange rate of $1.00 US/Canadian dollar. Distributions/Dividends - For the year ended December 31, 2010, Bonavista declared distributions of $252.3 million ($1.92 per unit) compared to $218.0 million ($2.00 per unit) in the same period in 2009. For the three months ended December 31, 2010, Bonavista declared distributions of $64.2 million ($0.48 per unit) compared to $59.8 million ($0.48 per unit) in the same period in 2009. Bonavista’s dividend policy is constantly monitored and is dependent upon its forecasted production, commodity prices, funds from operations, debt levels and capital expenditures. Within a dividend paying corporate structure, Bonavista is well positioned to provide our shareholders a combination of sustainable growth and meaningful income. While the proven underlying operating strategies of Bonavista will remain intact, our new business model has been designed to deliver long-term total shareholder returns of between 10% and 15% per annum. The following table illustrates the relationship between cash flow provided from operating activities and distributions declared, as well as net income and distributions declared. Net income includes significant non-cash charges, such as depreciation, depletion and accretion, unrealized gains and losses on financial instrument contracts, unrealized gains and losses on foreign exchange, fluctuations in future income taxes due to changes in tax rates and tax rules, and unit- based compensation. These non-cash charges do not represent the actual cost of maintaining our production capacity given the natural declines associated with oil and natural gas assets. For the three months ended December 31, 2010, the non-cash charges amounted to $87.5 million compared to $95.3 million for the same period in 2009. For the year ended December 31, 2010, the non-cash charges amounted to $327.3 million compared to $339.8 million for the same period in 2009. In instances where distributions exceed net income, a portion of the cash distribution paid to unitholders may be considered an economic return of unitholders' equity. Distribution Analysis (thousands) Cash flow provided from operating activities Net income Distributions declared Excess of cash flow provided from operating Three months ended December 31, Years ended December 31, 2010 2009 2010 2009 $ 115,741 39,784 64,242 $ 154,758 39,647 59,783 $ 514,164 201,581 252,298 $ 423,933 106,606 217,965 activities over distributions declared Shortfall of net income over distributions declared 51,499 (24,458) 94,975 (20,136) 261,866 (50,717) 205,968 (111,359) Bonavista expects to deliver a 5% to 7% annual production growth rate and expects to pay a monthly dividend of $0.12 per share for the production month beginning January 2011. Annual financial information - The following table highlights selected annual financial information for each of the three years ended December 31, 2010, 2009 and 2008: Years ended December 31, (thousands, except per share amounts) Consolidated Statement of Operations Information: Production revenues, net of royalties Funds from operations Per share – basic Per share – diluted Net income Per share – basic Per share – diluted Consolidated Balance Sheet Information: Total capital expenditures Total assets Working capital deficiency Long-term debt Shareholders’ equity Distributions declared 2010 2009 2008 $ 795,219 526,987 3.44 3.40 201,581 1.32 1.30 $ 569,995 3,342,988 (70,012) 951,443 1,877,608 252,298 $ 642,206 447,743 3.46 3.43 106,606 0.82 0.81 $ 833,844 3,092,129 (87,124) 832,138 1,723,583 217,965 $ 994,424 643,876 5.64 5.56 438,366 3.84 3.80 $ 482,297 2,543,240 (11,726) 588,792 1,411,972 332,540 Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly periods ending on March 31, 2009 to December 31, 2010: December 31 September 30 June 30 March 31 December 31 September 30 June 30 March 31 2010 2009 ($ thousands, except per share amounts) Production revenues Net income Net income per share: Basic Diluted 234,706 39,784 222,656 36,614 227,732 45,449 253,632 79,734 232,870 39,647 180,977 33,339 166,430 661 179,146 32,959 0.25 0.25 0.24 0.23 0.30 0.30 0.54 0.53 0.27 0.27 0.25 0.25 0.01 0.01 0.28 0.28 Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and increasing production volumes. Net income in the past eight quarters has fluctuated from a low of $661,000 in the second quarter of 2009 to a high of $79.7 million in the first quarter of 2010. These fluctuations are primarily influenced by production volumes, commodity prices, realized and unrealized gains and losses on financial instrument contracts and marketable securities; gains and losses on foreign exchange and future income tax recoveries associated with the reduction in corporate income tax rates. Net income increased slightly in the fourth quarter of 2010 as compared to the fourth quarter of 2009, as the decline in product pricing was offset by a 10% increase in production volumes. Disclosure controls and procedures - Disclosure controls and procedures have been designed to ensure that information to be disclosed by Bonavista is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosures. The Chief Executive Officer and Chief Financial Officer have concluded, as of the end of the period covered by the interim and year end filings that Bonavista’s disclosure controls and procedures are appropriately designed and operating effectively to provide reasonable assurance that material information relating to the issuer is made known to them by others within the Corporation. Internal control over financial reporting - Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system is met. Management has reporting as defined by assessed National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Management has concluded that their internal control over financial reporting was effective as of December 31, 2010. There were no material changes to the internal controls over financial reporting during the three months ended December 31, 2010. the effectiveness of Bonavista’s internal control over financial International financial reporting standards - On January 1, 2011 International Financial Reporting Standards (“IFRS”) will become the generally accepted accounting principles in Canada. The adoption date of January 1, 2011 will require restatement, for comparative purposes, of amounts reported by Bonavista for the year ended December 31, 2010, including the opening consolidated balance sheet as at January 1, 2010. Since its inception the project has been led by a group of internal staff assisted by external consultants and supported by the management team. Bonavista’s auditors have also continued to be involved throughout the process to ensure that its accounting policies are in accordance with the standards set out by IFRS. Most adjustments required on the transition to IFRS will be made retrospectively against the opening retained earnings of the first comparative balance sheet presented, based on the applicable standards at that time. IFRS 1 provides entities adopting IFRS for the first time certain optional and mandatory exemptions to the general requirements of full retrospective application of IFRS. Management has analyzed the various exemptions available under IFRS 1 and has implemented those determined to be the most appropriate for Bonavista at this time. Accordingly, Bonavista has applied the following IFRS 1 exemptions in its opening consolidated balance sheet. Property, Plant and Equipment (“PP&E”) – Bonavista’s PP&E assets must be allocated to its cash generating units (“CGU”) unlike under Canadian GAAP where all oil and natural gas assets are accumulated into one cost centre. The deemed cost of Bonavista’s oil and natural gas assets have been allocated to its defined CGUs based on Bonavista’s proved and probable reserve values as at January 1, 2010. These CGUs are aligned within the major geographic regions in which Bonavista operates and could change in the future as a result of significant acquisition and disposition activity. Business Combinations – IFRS 1 would allow Bonavista to use the IFRS rules from business combinations on a prospective basis rather than restating all business combinations. Bonavista will not be recording adjustments to retrospectively restate any of its business combinations that have occurred prior to January 1, 2010. The following is a listing of key areas where accounting policies will differ from Canadian GAAP and where accounting policy decisions will impact our reported financial position and results of operations: Exploration and Evaluation (“E&E”) expenditures – Upon transition to IFRS, Bonavista will reclassify all E&E expenditures that are currently included in the PP&E balance on the Consolidated Balance Sheet. This will consist of the book value for Bonavista’s undeveloped land that relates to exploration properties. E&E assets will not be depleted and must be assessed for impairment when indicators of impairment exist. Management has identified and reclassified approximately $179.7 million of assets from PP&E to E&E in the opening consolidated balance sheet prepared under IFRS as at January 1, 2010. Depletion expense – Upon transition to IFRS, Bonavista has the option to calculate depletion using a reserve base of proved reserves or both proved plus probable reserves, as compared to using only proved reserves under Canadian GAAP. Bonavista has determined to calculate its depletion expense based upon using proved and probable reserves as its depletion base and therefore we anticipated the depletion expense for the year ended December 31, 2010 to decrease as compared to its current calculation under Canadian GAAP. Impairment of PP&E assets – Under IFRS, an impairment test of PP&E must be performed at the CGU level as opposed to the entire PP&E balance, which is currently required under Canadian GAAP through the full cost ceiling test. Bonavista is required to recognize an impairment loss if the carrying amount of a CGU exceeds the higher of its fair value less cost to sell and value in use. Under Canadian GAAP, estimated future cash flows used to assess impairments are not discounted. Impairment of Goodwill – For goodwill impairment under IFRS, goodwill that arises from a business combination is allocated to the specific CGUs that are expected to benefit from the business combination. The carrying value of the CGU including goodwill is compared to the fair value of the CGU and any excess of the carrying value over the fair value is considered impairment and would be charged to retained earnings on the opening consolidated balance sheet prepared under IFRS. Bonavista is currently in the process of determining whether a goodwill impairment exists or not. Provisions for Asset Retirement costs – Under IFRS, Bonavista is required to revalue its liability for asset retirement costs at each balance sheet date using the current risk-free rate of interest when the expected cash flows are risked. Under present Canadian GAAP, once recorded, asset retirement obligations are not adjusted for future changes in discount rates. IFRS also requires that asset retirement obligations be re-measured each reporting period for changes in the discount rate with a corresponding adjustment to the cost of property, plant and equipment, whereas under Canadian GAAP, changes in discount rates do not result in a re-measurement. At January 1, 2010 Bonavista’s total of its asset retirement obligations will increase by $141.0 million to $301.4 million as the liability is revalued to reflect the estimated risk free rate of interest of 4.1% as compared to the credit adjusted risk-free rate of 7.5% used under Canadian GAAP.  Exchangeable shares - Under IFRS, exchangeable shares are considered to be a puttable financial instrument and will be classified as a financial liability. They will be recorded on the statement of financial position at their fair value with any changes being recorded in the statement of comprehensive income. As at January 1, 2010, Bonavista’s liability associated with Bonavista Petroleum Ltd. exchangeable shares under IFRS is $479.1 million. On December 31, 2010 the Trust completed its conversion from an energy trust to a corporation resulting in exchangeable shares being classified as equity under IFRS. Common share-based payments – Under IFRS, Bonavista’s common share incentive rights and restricted common share incentive rights are considered to be cash-settled awards and will be classified as a liability. The liability is measured at fair value with subsequent changes in the fair value recognized in the statement of comprehensive income. Under Canadian GAAP, Bonavista uses the fair value based method for the determination of the common share-based compensation costs. As at January 1, 2010, Bonavista’s liability associated with common share-based payments under IFRS is approximately $12.0 million. On December 31, 2010, the Trust completed its conversion from an energy trust to a corporation resulting in common share based awards to be classified as equity under IFRS. Deferred taxes – Under IFRS, entities that are subject to different tax rates on distributed and undistributed income must calculate deferred taxes using the undistributed profits rate, which is the higher of the two. Canadian GAAP requires each individual tax rate to be applied to distributed and undistributed profits, respectively. As a result of using the undistributed profits rate, Bonavista will record a reduction in its deferred tax liability upon transition to IFRS, with the offset recorded as a reduction to its shareholders equity. This amount has been calculated based upon the adjustments made to the opening consolidated balance sheet prepared under IFRS as determined at March 3, 2011. The following table summarizes Bonavista’s January 1, 2010 consolidated balance sheet under Canadian GAAP and the transitional entries required to present the opening consolidated balance sheet under IFRS as determined at March 3, 2011. The amounts are unaudited as Bonavista has not yet completed a full set of annual financial statements under IFRS. Consolidated Balance Sheet as at January 1, 2010 (thousands) Current assets Long-term assets Current liabilities Long-term liabilities Shareholders’ equity Canadian GAAP IFRS Adjustments IFRS $ 144,735 2,947,394 3,092,129 231,859 1,136,687 1,723,583 $ 3,092,129 $ $ (4,424) (192) (4,616) 486,475 116,891 (607,982) (4,616) $ 140,311 2,947,202 3,087,513 718,334 1,253,578 1,115,601 $ 3,087,513 In addition to accounting policy differences, Bonavista’s transition to IFRS is expected to impact internal controls over financial reporting, disclosure controls and procedures, certain business activities and information systems. Internal controls over financial reporting (“ICFR”) – In conjunction with assessing our accounting policy choices under IFRS, we also assessed whether there were any instances where controls needed to be amended or added. We have determined that there are no material changes to our control procedures as we transition to IFRS. Disclosure controls and procedures – Bonavista has assessed the impact of the transition to IFRS on its disclosure controls and procedures and has not identified any material changes required to its control environment. It is expected that there will be increased note disclosure around certain financial statement items than what is currently required under Canadian GAAP. Management is currently drafting its IFRS note disclosure in accordance with the current IFRS standards and will continue to monitor further requirements put forth by the International Accounting Standards Board in discussion papers and exposure drafts for future disclosure requirements. Bonavista will continue to assess its stakeholders’ information requirements to ensure that adequate and timely information is provided to meet these needs.  Business activities – Upon transition to IFRS, management has been cognizant of ensuring that any existing agreements with counterparties and lenders that contain references to Canadian GAAP are modified to allow for IFRS statements. Based on the changes to Bonavista’s accounting policies no issues are expected to arise with the existing wording of our debt covenants and other related agreements as a result of converting to IFRS. Information systems – Bonavista has completed the accounting system updates required in order to prepare for the transition to IFRS reporting. These updates while not significant are critical to allow for reporting of both Canadian GAAP and IFRS statements in 2010 as well as tracking of PP&E and E&E expenditures to a more detailed level as required under IFRS. Critical Accounting Estimates - The consolidated financial statements have been prepared in accordance with Canadian GAAP. A summary of significant accounting policies are presented in note 1 of the Notes to the Consolidated Financial Statements. Certain accounting policies are critical to understanding the financial condition and results of operations of Bonavista. a) Proved oil and natural gas reserves - Proved oil and natural gas reserves, as defined by the Canadian Securities Administrators in National Instrument 51-101 with reference to the Canadian Oil and Natural Gas Evaluation Handbook, are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. An independent reserve evaluator using all available geological and reservoir data as well as historical production data has prepared Bonavista’s oil and natural gas reserve estimates. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in Bonavista’s development plans. The effect of changes in proved oil and natural gas reserves on the financial results and position of Bonavista is described in b) below. b) Depreciation, depletion and accretion expense - Bonavista uses the full cost method of accounting for exploration and development activities whereby all costs associated with these activities are capitalized, whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproved properties, and estimated future development costs is amortized using the unit-of-production method based on estimated proved reserves. Changes in estimated proved reserves or future development costs have a direct impact on depreciation and depletion expense. Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly to determine if proved reserves should be assigned, at which point they would be included in the depletion calculation, or for impairment, for which any write-down would be charged to depreciation and depletion expense. c) Full cost accounting ceiling test - The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The cost recovery ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charged as additional depletion and depreciation expense. d) Asset retirement obligations - The asset retirement obligations are estimated based on existing laws, contracts or other policies. The fair value of the obligation is based on estimated future costs for abandonment and reclamation discounted at a credit adjusted risk free rate. The costs are included in property, plant and equipment and amortized over their useful life. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings and for revisions to the estimated future cash flows. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. e) Income taxes - The determination of Bonavista’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded. Assessment of Business Risks The following are the primary risks associated with our business. Bonavista’s financial position, results of operations and dividends to shareholders are directly impacted by these factors and include: 1) operational risk associated with the production of oil and natural gas; 2) reserve risk in respect to the quantity and quality of recoverable reserves; 3) market risk relating to the availability of transportation systems to move the product to market; 4) commodity risk as crude oil and natural gas prices fluctuate due to market forces; 5) financial risk such as volatility of the Canadian/US dollar exchange rate, interest rates and debt service obligations; 6) potential risk of change in dividends; 7) environmental and safety risk associated with well operations and production facilities; 8) changing government regulations relating to royalty legislation, income tax laws, incentive programs, operating practices and environmental protection relating to the oil and natural gas industry; 9) continued participation of Bonavista’s lenders; 10) counterparty risk with respect to non-performance by counterparties to financial derivative contracts; and 11) financial risk associated with domestic and international debt and equity markets. Bonavista seeks to mitigate these risks by: 1) acquiring properties with well established production trends to reduce technical uncertainty; 2) acquiring long life reserves to ensure more stable production and to reduce the economic risks associated with commodity price cycles; 3) maintaining a low cost structure to maximize product netbacks and reduce impact of commodity price cycles; 4) diversifying properties to mitigate individual property and well risk; 5) maintaining product mix to balance exposure to commodity prices; 6) conducting rigorous reviews of all property acquisitions; 7) monitoring pricing trends and developing a mix of contractual arrangements for the marketing of products with creditworthy counterparties; 8) maintaining a hedging program to hedge commodity prices and foreign exchange currency rates with creditworthy counterparties; 9) ensuring strong third party-operators for non-operated properties; 10) adhering to our safety program and keeping abreast of current operating best practices; 11) keeping informed of proposed changes in regulations and laws to properly respond to and plan for the effects that these changes may have on our operations; 12) carrying insurance to cover losses and business interruption; and 13) establishing and maintaining adequate cash resources to fund future abandonment and site restoration costs. OUTLOOK As we embark on our first year as a dividend paying corporation, we continue to apply the same proven strategies that we have employed throughout our history of creating value for our investors. The foundation of these strategies is to consistently exercise cost discipline and a high level of capital spending efficiency as we actively pursue a variety of quality drilling opportunities on our extensive land base, coupled with complementary acquisitions within geographically concentrated areas of operations. Since the Federal Government’s trust tax announcement on October 31, 2006, Bonavista has been preparing for the inevitable corporate conversion by enhancing our entrepreneurial team, improving both our operating cost structure and capital efficiencies, and increasing our inventory of organic growth opportunities. This transition has been successfully completed. We currently have identified approximately 1,150 drilling prospects on our land base which represents a 100% increase over our inventory at the time of the government’s announcement signaling the end of the trust structure. More importantly, we have also managed to gain significant improvements in the quality of our drilling inventory. Through a purposeful effort to pursue higher impact drilling targets, we have focused our development and acquisition efforts on deeper geological horizons towards scalable resource plays that are amenable to the benefits of horizontal drilling and multi-stage completion technology. We have been successful in this regard with average reserves per well increasing by over 400% and average initial production rates increasing by over 250% as compared to 2007 results. As we proceed into 2011, more than 80% of our future opportunities involve the application of horizontal drilling and multi-stage fracture technology within scalable resource plays. Our timely and prudent approach to capital investment has been very effective in the past and our attention to detail together with our steadfast commitment to adding shareholder value will continue to provide the foundation for the future success of our organization. Today our efficiency, productivity, and confidence are among the highest level in our thirteen year history. We continue to closely monitor natural gas prices and believe the excessive North American supply growth will moderate as current pricing does not generate sufficient full cycle profitability metrics for most plays being developed today. However, because the timing of this supply response is difficult to determine and current natural gas prices remain weak, we will reduce our capital spending program for 2011 between $345 and $375 million, directed entirely towards exploration and development activities. We plan to allocate a majority of our 2011 capital spending towards the development of four key resource plays consisting of our Hoadley Glauconite, Cardium Light Oil, Deep Basin Liquids Rich Natural Gas and Blueberry Montney programs, collectively making up approximately 60% of total budgeted development spending in 2011. As always, maximum flexibility over our capital spending will be maintained and while our primary focus will be to efficiently execute our drilling program in 2011, we will also continue to evaluate incremental acquisition opportunities as they present themselves. With 75% of the wells budgeted in 2011 targeting high impact plays using horizontal drilling and multi-stage completion techniques, we remain confident that we can achieve modest growth in our 2011 annual production to average between 69,000 and 71,000 boe per day. We are proud of our accomplishments over the past year and despite continued weak natural gas prices, we remain enthusiastic and confident about our future. Throughout many business cycles Bonavista has converted adversity into opportunity, pursued counter-cyclical strategies and has emerged as an even stronger entity. We would like to thank our employees for their significant effort and their continued perseverance as we embrace the future as a dividend paying corporation. We remain confident that our operating philosophy works well in any environment and this will aid in our goal to continually create long-term value for our shareholders. Our team is very committed to this vision. On behalf of the Board of Directors Keith A. MacPhail Chairman and Chief Executive Officer Jason E. Skehar President and Chief Operating Officer March 3, 2011 Calgary, Alberta MANAGEMENT’S REPORT The preparation of the accompanying consolidated financial statements in accordance with accounting principles generally accepted in Canada is the responsibility of management. Financial information contained elsewhere in this Annual Report is consistent with that in the consolidated financial statements. Management is responsible for the integrity and objectivity of the financial statements. Where necessary, the financial statements include estimates, which are based on management’s informed judgments. Management has established systems of internal controls, which are designed to provide reasonable assurance those assets, are safeguarded from loss or unauthorized use and to produce reliable accounting records for the preparation of financial information. The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. It exercises its responsibilities primarily through the Audit Committee, all of whose members are non-management directors. The Audit Committee has reviewed the consolidated financial statements with management and the auditors and has reported to the Board of Directors, which have approved the consolidated financial statements. KPMG LLP are independent auditors appointed by Bonavista’s shareholders. The auditors have considered, for the purposes of determining the nature, timing and extent of their audit procedures, Bonavista’s internal controls and have audited the consolidated financial statements in accordance with generally accepted auditing standards to enable them to express an opinion on the fairness of the financial statements in accordance with Canadian generally accepted accounting principles. Keith A. MacPhail Chairman and Chief Executive Officer Glenn A. Hamilton Senior Vice President and Chief Financial Officer March 3, 2011 Calgary, Alberta INDEPENDENT AUDITORS’ REPORT To the Shareholders of Bonavista Energy Corporation We have audited the accompanying consolidated financial statements of Bonavista Energy Corporation (“the Corporation”), which comprise the consolidated balance sheets as at December 31, 2010 and 2009, the consolidated statements of operations, comprehensive income, and accumulated earnings, and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information. Management’s Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditors’ Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Corporation as at December 31, 2010 and 2009, and the results of its consolidated operations and its consolidated cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. Chartered Accountants Calgary, Canada March 3, 2011 BONAVISTA ENERGY CORPORATION Consolidated Balance Sheets December 31, (thousands) Assets: Current assets: Accounts receivable and prepaids Marketable securities Financial instrument contracts (note 11) Future income tax asset (note 10) Oil and natural gas properties and equipment (note 6) Goodwill Liabilities and Shareholders’/Unitholders’ Equity: Current liabilities: 2010 2009 $ 139,008 $ 128,363 - 11,413 3,241 6,322 5,626 4,424 153,662 144,735 3,148,005 2,906,073 41,321 41,321 $ 3,342,988 $ 3,092,129 Accounts payable and accrued liabilities $ 186,447 $ 157,019 Distributions payable Financial instrument contracts (note 11) Convertible debentures (note 8) Future income tax (note 10) Financial instrument contracts (note 11) Long-term debt (note 7) Asset retirement obligations (note 4) Future income tax (note 10) Shareholders’/Unitholders’ equity: (note 9) 21,436 12,931 - 2,860 223,674 4,261 951,443 168,423 117,579 19,937 15,169 38,093 1,641 231,859 - 832,138 160,314 144,235 Unitholders’ capital and debenture conversion component - 1,531,299 Shareholders’ capital Exchangeable shares Contributed surplus Accumulated earnings Commitments (note 13) See accompanying notes to the consolidated financial statements. Approved on behalf of the Board of Directors of Bonavista Energy Corporation: 1,737,077 57,286 14,292 68,953 - 59,295 13,319 119,670 1,877,608 1,723,583 $ 3,342,988 $ 3,092,129 Ian S. Brown, Director Michael M. Kanovsky, Director BONAVISTA ENERGY CORPORATION Consolidated Statements of Operations, Comprehensive Income and Accumulated Earnings Years ended December 31, (thousands, except per share amounts) Revenues: Production Royalties Realized gains on financial instruments contracts (note 11) Unrealized gains (losses) on financial instruments contracts (note 11) Expenses: Operating Transportation General and administrative Restructuring costs Financing (note 7) Loss (Gain) on marketable securities Foreign exchange gain Unit-based compensation Depreciation, depletion and accretion Income before taxes Income taxes (recovery) (note 10) Net income and comprehensive income Accumulated earnings, beginning of year Distributions declared Accumulated earnings, end of year Net income per share – basic Net income per share – diluted See accompanying notes to the consolidated financial statements. 2010 2009 $ 938,726 $ 759,423 (143,507) (117,217) 795,219 642,206 16,080 3,764 19,844 72,100 (85,746) (13,646) 815,063 628,560 194,755 39,652 20,897 736 28,272 (1,871) (13,248) 11,584 354,593 197,795 36,833 17,900 - 14,035 1,336 - 11,386 295,296 635,370 574,581 179,693 (21,888) 53,979 (52,627) 201,581 106,606 119,670 231,029 (252,298) (217,965) 68,953 $ 119,670 1.32 $ 0.82 1.30 $ 0.81 $ $ $ BONAVISTA ENERGY CORPORATION Consolidated Statements of Cash Flows Years ended December 31, (thousands) Cash provided by (used in): Operating Activities: Net income Items not requiring cash from operations: Depreciation, depletion and accretion Unit-based compensation Unrealized (gains) losses on financial instruments contracts Loss (Gain) on marketable securities Foreign exchange gain Future income taxes (recovery) Asset retirement expenditures Changes in non-cash working capital items Financing Activities: Issuance of equity, net of issue costs Issuance of senior notes Distributions Repayment of bank credit facility Increase in bank credit facility Repayment of convertible debentures Changes in non-cash working capital items Investing Activities: Exploration and development Property acquisitions Property dispositions Proceeds on sale of marketable securities Changes in non-cash working capital items 2010 2009 $ 201,581 $ 106,606 354,593 11,584 (3,764) (1,871) (13,248) (21,888) (15,831) 3,008 295,296 11,386 85,746 1,336 - (52,627) (12,036) (11,774) 514,164 423,933 188,043 409,301 (250,799) (409,301) 132,511 (38,567) 1,079 404,115 - (226,759) - 243,346 (6,586) (349) 32,267 413,767 (349,481) (285,409) 65,570 8,193 14,696 (203,845) (737,117) 107,118 - (3,856) (546,431) (837,700) Change in cash Cash, beginning of year Cash, end of year See accompanying notes to the consolidated financial statements. - - - $ - - - $ BONAVISTA ENERGY CORPORATION Notes to Consolidated Financial Statements Years ended December 31, 2010 and 2009 Structure of Bonavista and Basis of Presentation: The principal undertakings of Bonavista Energy Corporation, its predecessor Bonavista Energy Trust (the “Trust”) and its subsidiaries, (“Bonavista” or the “Corporation”), are to carry on the business of acquiring, developing and holding interests in oil and natural gas properties and assets. On December 31, 2010, the Trust effectively completed its conversion from an energy trust to a corporation pursuant to the plan of arrangement (the “Arrangement”) under Section 193 of the Business Corporations Act (Alberta) that was approved by securityholders at the Joint Special Meeting of Securityholders of the Trust and Bonavista Petroleum Ltd. on December 14, 2010. On December 31, 2010, the Trust and Bonavista Petroleum Ltd. were merged into the Corporation. Unitholders of the Trust received one common share of the Corporation for each trust unit held, in addition, exchangeable shareholders of Bonavista Petroleum Ltd. received 2.40917 exchangeable shares of Bonavista for each exchangeable share held. The Board of Directors and senior management of the Trust continued as the Board of Directors and senior management of the Corporation. In connection with the Arrangement, Bonavista assumed all of the obligations of the Trust in respect of the trust unit rights incentive plan (amended to the common share rights incentive plan) and the restricted trust unit incentive plan (amended to the restricted common share incentive plan). The Arrangement did not result in the acceleration of vesting of any such awards. Upon vesting, holders of these rights are entitled to receive common shares on the same terms and conditions that existed prior to the Arrangement. No new incentive awards will be granted in the amended plans. The stock option plan and restricted share award incentive plan of Bonavista were established for new stock options and incentive rights under the Corporation. These plans are functionally similar to their predecessor plans. The incentive plans are further outlined in note 9 of the notes to the consolidated financial statements of the Corporation. The Arrangement has been accounted for as a continuity of interests and accordingly, the consolidated financial statements for periods prior to the effective date of the Arrangement reflect the financial position, income and cash flows as if the Corporation had always carried on the business formerly conducted by the Trust. In these and future consolidated financial statements, Bonavista will refer to “common shares”, “shareholders”, “dividends” and “ per share” which were formerly referred to as “trust units”, “unitholders”, “distributions” and “per unit” under the trust structure. Comparative amounts in these and future consolidated financial statements will reflect the history of the Trust. 1. Significant accounting policies: As determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions, which have been made using careful judgement. In particular, the amounts recorded for depreciation, depletion and accretion of the oil and natural gas properties and for asset retirement obligations are based on estimates of reserves and future costs. By their nature, these estimates, and those related to future cash flows used to assess impairment, are subject to change and the impact on the financial statements of future periods could be material. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below: a) Principles of consolidation: The consolidated financial statements include the accounts of the Corporation and its wholly-owned subsidiaries and proportionate share of its partnerships. All inter-entity transactions have been eliminated. b) Oil and natural gas properties and equipment: The Corporation follows the full cost method of accounting, whereby all costs associated with the exploration for and development of oil and natural gas reserves are capitalized in cost centres on a country-by-country basis. Such costs include land and property acquisitions, geological and geophysical activities, drilling, well equipment and facilities. Gains or losses are not recognized upon disposition of oil and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion by 20% or more. Costs capitalized in the cost centres, including well equipment, together with estimated future capital costs associated with proved reserves, are depreciated and depleted using the unit-of-production method which is based on gross production and estimated proved oil and natural gas reserves as determined by independent engineers. The cost of unproven properties is excluded from the depreciation and depletion base. For purposes of the depreciation and depletion calculations, oil and natural gas reserves are converted to a common unit of measure on the basis of their relative energy content, being six thousand cubic feet of natural gas for one barrel of oil. Facilities are depreciated using the declining balance method over their useful lives, which range from 12 to 15 years. Oil and natural gas properties and equipment are evaluated in each reporting period to determine whether the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying amounts are assessed to be recoverable when the sum of the undiscounted future cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs, and are discounted using a risk-free interest rate. c) Joint operations: A portion of Bonavista’s oil and natural gas operations are conducted jointly with others. Accordingly, the consolidated financial statements reflect only Bonavista’s proportionate interest in such activities. d) Goodwill: Goodwill is tested for impairment on an annual basis in the fourth quarter of each year. If indications of impairment are present, a loss would be charged to net income for the amount that the carrying value of goodwill exceeds its fair value. e) Asset retirement obligations: Bonavista records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost, which is depleted on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability. f) Revenue recognition: Revenues from the sale of oil and natural gas are recorded when title passes to an external party. g) Financial instruments: i) A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument to another entity. Upon initial recognition, all financial instruments, including all derivatives, are recognized on the balance sheet at fair value. Subsequent measurement is then based on the financial instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other liabilities. The Corporation has designated its cash and cash equivalents and investments, other than equity investments, as held for trading which are measured at fair value. Accounts receivable are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities, distributions payable, and long-term debt are classified as other liabilities which are measured at amortized cost, which is determined using the effective interest rate method. The convertible debentures are classified as debt on the balance sheet with a portion of the proceeds allocated to equity. The debt component has been measured at amortized cost. ii) The Corporation is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments may be used by the Corporation to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Corporation does not use these derivative instruments for trading or speculative purposes. The Corporation considers all of these transactions to be economic hedges; however, the majority of the Corporation’s contracts do not qualify or have not been designated as hedges for accounting purposes. As a result, all derivative contracts are classified as held for trading and are recorded on the balance sheet at fair value, with changes in the fair value recognized in net income, unless specific hedge criteria are met. The fair values of these derivative instruments are based on an estimate of the amounts that would have been received or paid to settle these instruments prior to maturity given future market prices and other relevant factors. Proceeds and costs realized from holding the derivative contracts are recognized in net income at the time each transaction under a contract is settled. The Corporation has elected to account for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as non- financial derivatives. The Corporation nets all transaction costs incurred, in relation to the acquisition of a financial asset or liability, against the related financial asset or liability. In accordance with this policy convertible debentures are recorded net of issue costs and long-term debt is presented net of deferred interest payments, with interest recognized in net income on an effective interest basis. h) Share-based compensation: Bonavista has established long-term incentive plans for employees which are described in note 9. These plans include a stock option plan and the restricted share award incentive plans, in addition to the amended plans of the Trust; the common share rights incentive plan (formerly the trust unit right incentive plan) and the restricted common share incentive plan (formerly the restricted trust unit incentive plan). i) Stock Option Plan and Common Share Rights Incentive Plan: The equity incentive plans for employees do not involve the direct award of common shares, or call for the settlement in cash or other assets. Bonavista uses the fair value method for valuing these incentive rights. Under this method, the compensation cost attributable to the share rights granted is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. Upon the exercise of the share rights, consideration received together with the amount previously recognized in contributed surplus is recorded as an increase to Shareholders’ equity. ii) Restricted Share Awards Plan and Restricted Common Shares Incentive Plan: Vesting arrangements on these awards are within the discretion of our board of directors, but all awards will vest within three years from the date of grant. On the vesting date, the holder will receive equivalent common shares for each share award, including dividends made on the shares from the date of the grant to and including the vesting date, net of statutory withholding tax. Common shares may be issued from treasury or purchased on the open market. The compensation cost attributable to these restricted awards is measured at fair value at the grant date and expensed to contributed surplus. Upon the vesting of the restricted shares, the amount previously recognized in contributed surplus is recorded as an increase in Shareholders’ equity. i) Income taxes: Bonavista follows the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are recognized for the estimated tax consequences attributable to differences between the amounts reported in the financial statements of Bonavista and their respective tax base, using substantively enacted future income tax rates. The effect of a change in income tax rates on future tax assets and liabilities is recognized in income in the period in which the change occurs, provided that the income tax rates are substantively enacted. Temporary differences arising on acquisitions result in the recording of future income tax assets and liabilities. j) Per share amounts: Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of the Stock Option and Common Share Rights Incentive Plans. 2. Future accounting changes: International Financial Reporting Standards (“IFRS”) In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accountable enterprises will be required to apply IFRS, in full and without modification, for all financial periods beginning January 1, 2011. The transition to IFRS at January 1, 2011 requires the restatement, for comparative purposes, of amounts reported by Bonavista for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010. 3. Business relationships: Bonavista and NuVista are considered related as two directors of NuVista, one of whom is NuVista’s chairman, are directors and officers of Bonavista and a director of NuVista is also an officer of Bonavista. For the year ended December 31, 2010, no management fees, other than standard industry overhead recoveries, were charged by NuVista for our jointly owned partnership (2009 - $1.2 million). As at December 31, 2010, the amount payable to NuVista was $134,000 (2009 - $343,000). On February 2, 2011, Bonavista completed the rationalization of its partnership interest in NuVista Energy in exchange for working interests in certain of NuVista Energy’s oil and natural gas properties. NuVista Energy was a general partnership held with NuVista Energy Ltd. of which Bonavista Petroleum had a 24.22% beneficial interest. 4. Asset retirement obligations: Bonavista’s asset retirement obligations result from net ownership interests in oil and natural gas assets including well sites, gathering systems and processing facilities. The Corporation estimates the total undiscounted amount of expenditures required to settle its asset retirement obligations is approximately $776.0 million (2009 - $753.5 million) which will be incurred over the next 50 years. The majority of the costs will be incurred between 2012 and 2039. A credit-adjusted risk-free rate of 7.5% (2009 - 7.5%) and an inflation rate of 2% (2009 - 2%) were used to calculate the fair value of the asset retirement obligations. A reconciliation of the asset retirement obligations is provided below: (thousands) Balance, beginning of year Accretion expense Liabilities incurred Liabilities acquired Liabilities settled Change in estimate Balance, end of year 5. Property acquisition: Years ended December 31, 2010 2009 $ 160,314 $ 127,467 11,741 3,369 6,820 (15,831) 2,010 10,033 3,195 31,234 (12,036) 421 $ 168,423 $ 160,314 On May 31, 2010 the Corporation acquired certain long-life natural gas weighted properties located in west central Alberta for a cash purchase price of approximately $230.4 million. 6. Oil and natural gas properties and equipment: December 31, 2010 (thousands) Oil and natural gas properties Facilities Office equipment December 31, 2009 (thousands) Oil and natural gas properties Facilities Office equipment Cost $ $ 4,163,248 929,442 9,796 5,102,486 Cost Accumulated depreciation and depletion $ $ 1,726,779 221,671 6,031 1,954,481 Accumulated depreciation and depletion $ $ 3,667,533 842,307 8,378 4,518,218 $ $ 1,423,169 183,886 5,090 1,612,145 Net book value $ 2,436,469 707,771 3,765 $ 3,148,005 Net book value $ 2,244,364 658,421 3,288 $ 2,906,073 Unproved property costs of $219.6 million as at December 31, 2010 (2009 - $179.7 million) were excluded from the depreciation and depletion calculation. Future development costs of $759.0 million as at December 31, 2010 (2009 - $587.0 million) were included in the depreciation and depletion calculation. Bonavista has calculated the ceiling test as of December 31, 2010. Based on the calculation, the present value of future net revenues from the Corporation’s proved reserves exceeds the carrying value of Bonavista’s oil and natural gas properties and equipment at December 31, 2010. The benchmark reference prices, as provided by our independent engineering consultants, used in the calculation and adjusted for commodity differentials specific to Bonavista are as follows: Benchmark Reference Price Forecasts: Year 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Remainder (1) (1) Escalated at 2% per year thereafter 7. Long-term debt: (thousands) Bank credit facility Senior unsecured notes Balance, end of year a) Bank credit facility: WTI Oil (US$/bbl) 88.00 89.00 90.00 92.00 95.17 97.55 100.26 102.74 105.45 107.56 2.0% AECO Gas (Cdn$/mmbtu) 4.16 4.74 5.31 5.77 6.22 6.53 6.76 6.90 7.06 7.21 2.0% USD/CAD Exchange Rates 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 December 31, 2010 December 31, 2009 $ 555,348 396,095 $ 951,443 $ 832,138 - $ 832,138 On September 10, 2010, Bonavista combined and renewed its bank credit facilities into a single facility of $1.4 billion provided by a syndicate of 12 domestic and international banks with a maturity date of September 10, 2013. This facility is an unsecured, covenant-based, extendible revolving facility and includes a $50 million working capital facility. This facility provides that advances may be made by way of prime rate loans, bankers' acceptances and/or US dollar LIBOR advances. These advances bear interest at the banks' prime rate and/or at money market rates plus a stamping fee. This facility is a three year revolving credit and may, at the request of the Corporation with the consent of the lenders, be extended on an annual basis. There is an accordion feature providing that at anytime during the term, on participation of any existing or additional lenders, the Corporation can increase the facility by $250 million. On March 3, 2011, Bonavista elected to reduce the committed amount of its bank credit facility by $400 million from $1.4 billion to $1.0 billion. Under the terms of the bank credit facility, Bonavista has provided the covenant that its: (i) consolidated senior debt borrowing will not exceed three times net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion and accretion; (ii) consolidated total debt will not exceed three and one half times consolidated net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion and accretion; and (iii) consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus consolidated shareholders’ equity of the Corporation, in all cases calculated based on a rolling prior four quarters. b) Senior unsecured notes issued under a master shelf agreement: In the second quarter of 2010, the Corporation entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125 million in notes at a rate equal to the related US treasury rate corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. On June 4, 2010 the Corporation drew down US$50 million on the master shelf agreement with a coupon rate of 4.86% with US$25 million maturing on June 4, 2016 and the remaining US$25 million maturing on June 4, 2017. Under the terms of the master shelf agreement, Bonavista has provided similar significant covenants that exist under the bank credit facility. c) Senior unsecured notes not subject to the master shelf agreement: On November 2, 2010, Bonavista issued the following senior unsecured notes by way of a private placement. The significant covenants of the senior unsecured notes are the same as those under the bank credit facility. The terms and coupon rates of the notes are summarized below: Issued Date November 2, 2010 November 2, 2010 November 2, 2010 November 2, 2010 Principal CDN $50.0 million US $90.0 million US $160.0 million US $50.0 million Coupon Rate 3.79% 3.66% 4.37% 4.47% Maturity Date November 2, 2015 November 2, 2017 November 2, 2020 November 2, 2022 for Financing expenses long-term debt of $27.0 million (2009 - $11.2 million) and convertible debentures of $1.3 million (2009 - $2.8 million). For the year ended December 31, 2010, Bonavista paid cash interest of $24.6 million (2009 - $14.4 million). Our effective interest rate for period ending December 31, 2010 was approximately 4.3% (2009 – 1.5%). the year ended December 31, 2010 interest on include 8. Convertible debentures: On June 30, 2010, the 6.75% convertible debentures with a conversion price of $29.00 per trust unit matured and were cash settled. The debt component of the debentures has been recorded net of the fair value of the conversion feature and issue costs. The fair value of the conversion feature of the debentures included in shareholders’ equity at the date of issue was $2.8 million. The issue costs are amortized to net income over the term of the obligation. The debt portion is accreted over the term of the obligation to the principal value on maturity with a corresponding charge to net income. The following table sets out the convertible debenture activities to December 31, 2010: (thousands) Balance, December 31, 2008 Accretion Issue expenses related to conversions to trust units Amortization of issue expenses Repayment of convertible debentures on maturity Conversion to trust units Balance, December 31, 2009 Accretion Amortization of issue expenses Repayment of convertible debentures on maturity Balance, December 31, 2010 Debt Component Equity Component $ $ $ 43,711 452 2 525 (6,586) (11) (11) 38,093 285 189 (38,567) - $ $ $ 933 - - - (123) (2) (2) 808 - - (808) - 9. Shareholders’ and Unitholders’ equity: On December 31, 2010, pursuant to the Arrangement, all outstanding trust units were exchanged for common shares of the Corporation on a one for one basis and holders of exchangeable shares of Bonavista Petroleum Ltd. received 2.40917 exchangeable shares of Bonavista for each exchangeable share held. a) Authorized: Unlimited number of voting common shares. b) Issued and outstanding: (i) Trust units: (thousands) Balance, December 31, 2008 Issued for cash Issued on conversion of convertible debentures Issued on conversion of exchangeable shares Issued upon exercise of trust unit incentive rights Conversion of restricted trust units Issue costs, related to debenture conversions Issue costs, net of future tax benefit Adjustment to equity component of debenture on conversion Unit-based compensation Balance, December 31, 2009 Issued for cash Issued on property acquisition Issued on conversion of exchangeable shares Issued upon exercise of trust unit incentive rights Conversion of restricted trust units Issue costs, net of future tax benefit Unit-based compensation Exchanged pursuant to the Arrangement Balance, December 31, 2010 (ii) Common shares: (thousands) Balance, December 31, 2009 Issued pursuant to the Arrangement Balance, December 31, 2010 (iii) Contributed surplus: (thousands) Balance, December 31, 2008 Unit-based compensation expense Unit-based compensation capitalized Exercise of trust unit incentive rights and conversion of restricted trust units Adjustment to equity component of debenture on repayment Balance, December 31, 2009 Unit-based compensation expense Unit-based compensation capitalized Exercise of trust unit incentive rights and conversion of restricted trust units Adjustment to equity component of debenture on repayment Balance, December 31, 2010 Number of Units 95,770 25,000 1 3,380 335 118 - - - - 124,604 7,500 28 741 1,021 81 - - (133,975) - Number of Shares - 133,975 133,975 Amount $ 1,099,835 421,250 11 10,193 4,478 - (2) (16,218) 2 10,942 $ 1,530,491 177,000 675 2,009 20,395 - (6,986) 13,493 (1,737,077) $ - Amount $ - 1,737,077 $ 1,737,077 Amount $ 10,687 11,386 2,065 (10,942) 123 13,319 11,584 2,074 (13,493) 808 $ 14,292 (iv) Exchangeable shares: Pursuant to the Arrangement, 9.4 million exchangeable shares of Bonavista Petroleum Ltd. were exchanged for exchangeable shares of Bonavista based on the exchange ratio of 2.40917 resulting in 22.6 million exchangeable shares being authorized and issued. The exchangeable shares of Bonavista are exchangeable into common shares of the Corporation based on the exchange ratio, which is adjusted monthly, to reflect dividends paid on common shares. As a result, dividends are not paid on exchangeable shares. (thousands) Balance, beginning of year Exchanged for trust units Exchangeable shares issued pursuant to the Arrangement Balance, end of year Exchange ratio, end of year Shares issuable on exchange Years ended December 31, 2010 2009 Number Amount Number Amount 9,707 (329) 13,215 $ 59,295 (2,009) - 11,375 (1,668) - $ 69,488 (10,193) - 22,593 $ 57,286 9,707 $ 59,295 1.00000 - 2.21352 - 22,593 $ 57,286 21,486 $ 59,295 The holders of the Corporation’s exchangeable shares shall be entitled to notice of, to attend at, and to that number of votes equal to the number of exchangeable shares held multiplied by the exchange ratio in effect at the meeting record date at any meeting of the shareholders of Bonavista. In accordance with the provisions of the Corporation’s exchangeable shares, Bonavista may require, at any time, the exchange of that number of the Corporation’s exchangeable shares as determined by the Board of Directors on the basis of the exchange ratio in effect on the date set by Bonavista (the “Compulsory Exchange Date”). On and after the applicable Compulsory Exchange Date, the holders of the Corporation’s exchangeable shares called for exchange shall cease to be holders of such Corporation’s exchangeable shares and shall not be entitled to exercise any of the rights of holders in respect thereof, other than; (i) the right to receive their proportionate part of the common shares; and (ii) the right to receive any declared and unpaid dividends on such common shares. c) Stock option and common share rights incentive plan: In conjunction with the Arrangement, the stock option plan of the Corporation was established and the common share rights incentive plan (formerly the trust unit rights incentive plan of the Trust) was amended. The amended plan provided that all rights to acquire trust units became rights to acquire common shares. The amended plan will remain in place until such time as all rights granted have been exercised or expired. All new rights granted after December 31, 2010 will be granted under the stock option plan. As at December 31, 2010, there were no stock options granted under the stock option plan. The number of common shares under all long-term incentive plans shall be limited to 8% of the aggregate number of issued and outstanding common shares of the Corporation. The option exercise prices are equal to the weighted average trading price of the five trading days preceding the date of the grant. The incentive rights granted under the stock option plan vest over a three year period and expire three years after each vesting date, whereas rights granted under the amended common share rights incentive plan vest over a four year period and expire two years after each vesting date. The following tables summarize the common share incentive rights outstanding and exercisable under the plan at December 31, 2010: Balance, December 31, 2008 Granted Exercised Expired and forfeited Reduction in exercise price Balance, December 31, 2009 Granted Exercised Expired and forfeited Reduction in exercise price Balance, December 31, 2010 Exercisable, December 31, 2010 Number of Common Share Incentive Rights Weighted Average Exercise Price 3,208,795 1,616,820 (335,410) (673,963) - 3,816,242 1,563,840 (1,021,017) (402,337) - 3,956,728 952,368 $ 25.88 16.57 (13.35) (22.62) (1.80) 21.28 23.13 (19.93) (20.86) (1.85) $ $ 20.28 20.98 Range of exercise prices $ 12.35 – 20.69 20.70 – 22.68 22.69 – 35.99 $ 12.35 – 35.99 Common Share Incentive Rights Outstanding Common Share Incentive Rights Exercisable Number outstanding at year-end 1,316,118 1,202,910 1,437,700 3,956,728 Weighted average remaining contractual life Weighted average exercise price Number exercisable at year-end Weighted average exercise price 2.7 2.6 3.1 2.8 $ 13.13 21.24 26.02 $ 20.28 361,433 280,280 310,655 952,368 $ $ 12.96 21.26 30.05 20.98 The Corporation uses the fair value based method for the determination of the share-based compensation costs. The fair value of each common share incentive right granted was estimated on the date of grant using the modified Black-Scholes option-pricing model. In the pricing model, the risk free interest was 3.5% (2009 - 3.5%); average volatility of 33% (2009 - 66%); a forfeiture rate of 10% (2009 - 10%) and an expected life of 4.5 years. The fair value of the options granted in 2010 average $7.68 (2009 - $9.76) per common share incentive right. d) Restricted share award incentive plan and restricted common share incentive plan: In conjunction with the Arrangement, the restricted share award incentive plan was established and the restricted common share incentive plan (formerly the restricted trust unit incentive plan of the Trust) was amended. The amended plan provided that all rights to acquire trust units became rights to acquire common shares. The amended plan will remain in place until such time as all rights granted have vested or been cancelled. All new rights granted after December 31, 2010 will be granted under the restricted share award plan. As at December 31, 2010 there were no share awards granted under the restricted share award plan. Vesting arrangements are within the discretion of our Board of Directors, but all awards will vest within three years from the date of grant. On the vesting date, the holder will receive equivalent common shares for each share award, including dividends made on the common shares from the date of the grant to and including the vesting date, net of statutory withholding tax. The following December 31, 2010: table summarizes the restricted common share incentive rights outstanding under the plan at Balance, December 31, 2009 Granted Forfeited Conversion of restricted trust units Balance, December 31, 2010 197,896 163,855 (31,938) (81,261) 248,552 For the year ended December 31, 2010, Bonavista expensed $2.9 million (2009 – $2.2 million) relating to the restricted common share incentive plan. e) Per common share/trust unit amounts: The following table summarizes the weighted average common shares/trust units, exchangeable shares and convertible debentures used in calculating net income per common share/trust unit: (thousands) Trust units Common shares Exchangeable shares converted at the exchange ratio Basic equivalent common shares/trust units Convertible debentures Common share incentive rights Restricted common share incentive rights Diluted equivalent common shares/trust units Years ended December 31, 2010 - 131,075 22,019 153,094 656 832 250 154,832 2009 108,029 - 21,234 129,263 1,471 281 218 131,233 For the purposes of calculating net income per common share/unit on a diluted basis, the net income has been increased by $1.8 million (2009 - $3.8 million) with respect to the accretion, amortization and interest expense on the convertible debentures. For the year ended December 31, 2010 the Corporation excluded 3.1 million (2009 – 3.5 million) weighted average common share incentive rights from the diluted share/unit calculation as they are anti-dilutive. 10. Income taxes: The provision for income tax differs from the result which would have been obtained by applying the combined Federal and Provincial income tax rates to net income before taxes. This difference results from the following items: Expected tax rate (thousands) Expected tax expense Effect of change in tax rate Distributions to unitholders Other Income tax recovery The income tax recovery consists of: Current Future Income tax recovery Years ended December 31, 2009 2010 28.1% 29.2% $ 50,494 $ 15,762 (3,620) (70,911) 2,149 (21,888) - (21,888) (21,888) $ $ $ (8,949) (63,701) 4,261 (52,627) - (52,627) (52,627) $ $ $ The significant components of future income tax assets and liabilities as at December 31 are: (thousands) Oil and natural gas properties Facilities Asset retirement obligations Unrealized financial instruments contracts & Other Future income taxes For the years ended December 31, 2010 and 2009 Bonavista paid no tax installments. 11. Financial instruments: 2010 2009 $ 124,809 30,775 (38,598) 212 $ 146,547 36,135 (38,354) (2,876) $ 117,198 $ 141,452 Bonavista has exposure to credit and market risks from its use of financial instruments. This note provides information about the Corporation's exposure to each of these risks, the Corporation's objectives, policies and processes for measuring and managing risk. Further quantitative disclosures are included throughout these financial statements. a) Credit risk: Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to meet its contractual obligation and arises, primarily from joint venture partners, marketers and financial intermediaries. The companies accounts receivable are with customers and joint venture partners in the oil and natural gas business and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchaser’s under normal industry sale and payment terms. The Corporation routinely assesses the financial strength of its customers. The Corporation may be exposed to certain losses in the events of non-performance by counterparties to financial instrument contracts. The Corporation mitigates this risk by entering into transactions with highly rated financial institutions. The carrying amount of accounts receivable represents the maximum credit exposure. As at December 31, 2010 Bonavista’s receivables consisted of $77.7 million of receivables from oil and natural gas marketers which has substantially been collected, subsequent to December 31, 2010, $26.1 million from joint venture partners of which $6.3 million has been subsequently collected. As at December 31, 2010 the Corporation has $12.0 million in accounts receivable that is considered to be past due. Although these amounts have been outstanding for greater than 90 days, they are still deemed to be collectible. As the operator of properties, Bonavista has the ability to withhold production to joint venture partners, who are in default of amounts owing. The Corporation does not have an allowance for doubtful accounts as at December 31, 2010 and did not provide for any doubtful accounts nor was it required to write-off any receivables during the three months or year ended December 31, 2010. b) Liquidity risk: Liquidity risk is the risk that Bonavista will encounter difficulty in meeting obligations associated with the financial liabilities. The Corporation's financial liabilities consist of accounts payable and accrued liabilities, financial instruments contracts, bank debt and senior unsecured notes. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities, capital expenditures, and distributions payable. Bonavista processes invoices within a normal payment period. Accounts payable and accrued liabilities have contractual maturities of less than one year. Financial instruments contracts have contractual maturities of less than two years. Bonavista maintains a three year revolving credit facility, as outlined in note 7, which may, at the request of the Corporation with the consent of the lenders, be extended on an annual basis. The Corporation also has a series of senior unsecured notes outstanding, as outlined in note 7, which range in maturities from June 4, 2016 to November 2, 2022. The Corporation also maintains and monitors a certain level of cash flow which is used to partially finance all operating, investing and capital expenditures. c) Commodity price risk: Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted not only by global economic events that dictate the levels of supply and demand but also by the relationship between the Canadian and United States dollar. Bonavista has attempted to mitigate a portion of the commodity price risk through the use of various financial instrument contracts and physical delivery sales contracts. The Corporation's policy is to enter into commodity price contracts when considered appropriate to a maximum of 60% of net after royalty, forecasted production volumes. i) Financial instrument contracts: As at December 31, 2010, Bonavista entered into the following costless collars to sell natural gas and crude oil as follows: Volume Average Price Term 10,000 10,000 5,000 10,000 9,500 2,000 gjs/d CDN$5.13 - CDN$7.75 - AECO gjs/d CDN$4.30 - CDN$5.55 - AECO gjs/d CDN$4.50 - CDN$7.24 - AECO gjs/d CDN$5.25 - CDN$7.20 - AECO bbls/d CDN$79.58 - CDN$97.09 - WTI bbls/d CDN$81.25 - CDN$100.01 - WTI January 1, 2011 - March 31, 2011 April 1, 2011 - October 31, 2011 January 1, 2011 - October 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2012 - December 31, 2012 Subsequent to December 31, 2010, Bonavista entered into the following costless collar to sell natural gas and crude oil as follows: Volume Average Price Term 5,000 5,000 1,000 gjs/d CDN$3.50 - CDN$4.28 - AECO gjs/d CDN$3.60 - CDN$4.60 - AECO bbls/d CDN$87.50 - CDN$110.00 - WTI April 1, 2011 - October 31, 2011 April 1, 2012 - October 31, 2012 January 1, 2012 - December 31, 2012 As at December 31, 2010, Bonavista entered into the following option contracts to manage its overall commodity exposure: Volume Price Contract Term 28,000 10,000 1,000 500 1,000 gjs/d CDN$4.07 gjs/d CDN$6.45 bbls/d CDN$100.00 bbls/d USD$102.50 bbls/d CDN$105.00 Swap - AECO Sold Call - AECO Sold Call - WTI Sold Call - WTI Sold Call - WTI April 1, 2011 - October 31, 2011 April 1, 2011 - October 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2011 - December 31, 2011 January 1, 2012 - December 31, 2012 Subsequent to December 31, 2010, Bonavista entered into the following options contracts to manage its overall commodity exposure: Volume Average Price Contract Term 5,000 500 gjs/d CDN$3.72 bbls/d USD$105.00 Swap - AECO Sold Call - WTI April 1, 2011 - October 31, 2011 February 1, 2011 - December 31, 2011 Financial instrument contracts are recorded on the consolidated balance sheet at fair value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated statements of operations, comprehensive income and accumulated earnings. As at December 31, 2010, the fair market value recorded on the consolidated balance sheet for these financial instrument contracts was a net liability of $5.8 million, compared to a net liability of $9.5 million as at December 31, 2009. These financial instrument contracts had the following gains and losses reflected in the consolidated statements of operations, comprehensive income and accumulated earnings: Realized gains on financial instrument contracts Unrealized gains (losses) on financial instrument contracts Years ended December 31, 2009 2010 $ 16,080 $ 72,100 3,764 (85,746) $ 19,844 $ (13,646) Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instrument contracts. A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $900,000 on net income for those financial instrument contracts that were in place as at December 31, 2010. A $1.00 change in the price per barrel of oil – WTI would have an impact of approximately $2.2 million on net income for those financial instrument contracts that were in place as at December 31, 2010. iii) Physical purchase and sale contracts: As at December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as follows: Volume 10,000 10,000 7,000 Average Price Term gjs/d CDN$5.00 - CDN$7.34 - AECO gjs/d CDN$5.13 - CDN$6.99 - AECO gjs/d CDN$4.15 - AECO January 1, 2011 - March 31, 2011 January 1, 2011 - December 31, 2011 April 1, 2011 - October 31, 2011 As at December 31, 2010, Bonavista entered into the following contracts to purchase electricity as follows: Volume Average Price Term 6 1 mw/h CDN$50.37 - AESO mw/h CDN$51.00 - AESO January 1, 2011 - December 31, 2011 January 1, 2011 - December 31, 2012 Subsequent to December 31, 2010, Bonavista entered into the following physical contracts to sell natural gas as follows: Volume Average Price Term 12,500 gjs/d CDN$3.84 - AECO April 1, 2011 - October 31, 2011 Physical purchase and sale contracts are being accounted for as they are settled. d) Foreign exchange risk: Commodity prices are largely denominated in US dollars and as a result the prices that Canadian producers receive is determined by the relationship between the US and Canadian dollar. In addition, Bonavista also has US denominated debt and interest obligations of which future cash payments are directly impacted by the exchange rate in effect on the due date. A one cent change in the US/Canadian dollar exchange rate would have an impact of approximately $3.0 million on the revaluation of the outstanding US denominated debt. e) Interest rate risk: Bonavista is exposed to interest rate risk on its outstanding bank debt, as it has a floating interest rate and consequently changes to interest rates would impact the Corporation’s future cash flows. If interest rates applicable to the variable rate debt increases by one percent it is estimated that Bonavista’s net income for the year ended December 31, 2010 would decrease by $6.1 million. Fair value of financial instruments: The fair value of the financial instruments carried on Bonavista’s consolidated balance sheet is classified according to the following hierarchy based on the amount of observable inputs used to value the instruments. Level 1 – quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Level 3 – valuation in this level are those with inputs for the asset or liabilities that are not based on observable market data. The Corporation’s marketable securities and convertible debentures have been classified as Level 1, financial instrument contracts, bank debt and senior unsecured notes are classified as Level 2. The fair value of financial instrument contracts is determined by the financial intermediary to extinguish all rights or obligations of the financial instrument contracts. As at December 31, 2010, the fair market value of these financial instrument contracts was a net liability of approximately $5.8 million (2009 - $9.5 million net liability). Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value. The fair market value of the senior unsecured notes as at December 31, 2010 is approximately $383.0 million (2009 – nil), compared to a carrying amount of $396.1 million. 12. Capital management: The Corporation's objective when managing capital is to maintain a flexible capital structure which allows it to execute its growth strategy through strategic acquisitions and expenditures on exploration and development activities while maintaining a strong financial position that provides our shareholders with stable dividends and rates of return. The Corporation considers its capital structure to include working capital (excluding associated asset and liabilities from financial instrument contracts and their related tax impact), bank debt, senior unsecured notes and shareholders' equity. Bonavista monitors capital based on the ratio of net debt to annualized funds from operations. The ratio represents the time period it would take to pay off the debt if no further capital expenditures were incurred and if funds from operations remained constant. This ratio is calculated as net debt, defined as outstanding bank debt, and senior unsecured notes, plus or minus net working capital, divided by funds from operations for the most recent calendar quarter, annualized (multiplied by four). The Corporation's strategy is to maintain a ratio of less than 2.0 to 1. This strategy is more restrictive than the existing financial covenants on both the Corporation's bank credit facility and senior unsecured notes. This ratio may increase at certain times as a result of acquisitions or low commodity prices. As at December 31, 2010, Bonavista’s ratio of net debt to fourth quarter annualized funds from operations was 2.0 to 1 (2009 - 1.6 to 1), which is within the acceptable range established by the Corporation. In order to facilitate the management of this ratio, the Corporation prepares annual funds from operations and capital expenditure budgets, which are updated as necessary, and are reviewed and periodically approved by Bonavista’s Board of Directors. The Corporation manages its capital structure and makes adjustments by continually monitoring its business conditions, including; the current economic conditions; the risk characteristics of Bonavista’s oil and natural gas assets; the depth of its investment opportunities; current and forecasted net debt levels; current and forecasted commodity prices; and other factors that influence commodity prices and funds from operations, such as quality and basis differential, royalties, operating costs and transportation costs. In order to maintain or adjust the capital structure, Bonavista will consider; its forecasted ratio of net debt to forecasted funds from operations while attempting to finance an acceptable capital expenditure program including acquisition opportunities; the current level of bank credit available from the Corporation's lenders; the availability of other sources of debt with different characteristics than the existing bank debt; the sale of assets; limiting the size of the capital expenditure program; issuance of new equity if available on favourable terms; and its level of dividends payable to its shareholders. The Corporation's shareholder's capital is not subject to external restrictions, however the Corporation's bank credit facility and senior unsecured notes do contain financial covenants that are outlined in note 7 of the consolidated financial statements. There has been no change in Bonavista’s approach to capital management during the year ended December 31, 2010. 13. Commitments: The following is a summary of Bonavista’s commitments as at December 31, 2010: (thousands) Long-term debt repayments (1)(3) Interest payments (2)(3) Transportation expenses Office premises Total 2011 2012 2013 2014 2015 and thereafter Payments Due by Period $ 955,348 143,126 49,205 21,376 $ - 16,765 16,428 1,272 $ - 16,765 12,662 3,054 $ 555,348 16,765 9,521 3,054 $ - 16,765 5,612 3,054 $ 400,000 76,066 4,982 10,942 Total contractual obligations $1,169,055 $ 34,465 $ 32,481 $ 584,688 $ 25,431 $ 491,990 (1) (2) (3) Long-term debt repayments include the bank loan facility and principal payments due on senior unsecured notes. Based on the existing terms of the revolving bank credit facility, the amounts owing under this facility are required to be paid in 2013. Fixed interest payments on senior unsecured notes. US dollars payments are converted using the exchange rate of $1.00 US/Canadian dollar. CORPORATE INFORMATION DIRECTORS Keith A. MacPhail, Chairman and CEO Ian S. Brown, Independent Businessman Michael M. Kanovsky, Sky Energy Corporation Harry L. Knutson, Nova Bancorp Inc. Margaret A. McKenzie, Range Royalty Management Ltd. Ronald J. Poelzer, Executive Vice President and Vice Chairman Christopher P. Slubicki, OPTI Canada Inc. Walter C. Yeates, Independent Businessman OFFICERS Keith A. MacPhail, Chairman and CEO Jason E. Skehar, President and COO Ronald J. Poelzer, Executive Vice President and Vice Chairman Glenn A. Hamilton, Senior Vice President and CFO Thomas J. Mullane, Senior Vice President Johannes H. Thiessen, Senior Vice President Scott H. Hanson, Vice President, Production Orest G. Humeniuk, Vice President, Land Bruce W. Jensen, Vice President, Engineering Dean M. Kobelka, Vice President, Finance Wayne E. Merkel, Vice President, Exploration Lynda J. Robinson, Vice President, Human Resources and Administration Hank R. Spence, Vice President, Operations Grant A. Zawalsky, Corporate Secretary FOR FURTHER INFORMATION CONTACT: AUDITORS KPMG LLP Chartered Accountants Calgary, Alberta BANKERS Canadian Imperial Bank of Commerce The Toronto-Dominion Bank Bank of Montreal Royal Bank of Canada The Bank of Nova Scotia National Bank of Canada Alberta Treasury Branches HSBC Bank Canada Union Bank of California, N.A. (Canada Branch) BNP Paribas (Canada) Citibank, N.A. (Canadian Branch) Sumitomo Mitsui Banking Corporation of Canada Calgary, Alberta ENGINEERING CONSULTANTS GLJ Petroleum Consultants Ltd. Ryder Scott Company Canada Calgary, Alberta LEGAL COUNSEL Burnet, Duckworth & Palmer LLP Calgary, Alberta REGISTRAR AND TRANSFER AGENT Valiant Trust Company Calgary, Alberta STOCK EXCHANGE LISTING Toronto Stock Exchange Trading Symbol “BNP” HEAD OFFICE 1500, 525 – 8th Avenue SW Calgary, Alberta T2P 1G1 Telephone: (403) 213-4300 (403) 262-5184 Facsimile: inv_rel@bonavistaenergy.com Email: www.bonavistaenergy.com Website: Keith A. MacPhail Chairman and CEO (403) 213-4315 or Jason E. Skehar President and COO (403) 213-4363 or Glenn A. Hamilton Senior Vice President and CFO (403) 213-4302 

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