BNP Paribas Bank Polska
Annual Report 2012

Plain-text annual report

Highlights Financial ($ thousands, except per share) Production revenues Funds from operations(1) Per share(1) (2) Dividends declared(3) Per share Net income (loss) Per share(4) Adjusted net income(5) Per share(4) Total assets Long-term debt, net of working capital Long-term debt, net of adjusted working capital(6) Shareholders’ equity Capital expenditures: Exploration and development Acquisitions, net of dispositions ANNUAL REPORT 2012 Three months ended December 31, 2012 2011 % Change Years ended December 31, % 2012 2011 Change 223,021 285,167 (22%) 832,491 1,044,414 (20%) 110,015 0.57 150,843 0.91 63,481 0.36 14,442 0.07 16,535 0.09 51,850 0.36 (3,321) (0.02) 16,994 0.10 (27%) (37%) 22% - 535% 450% (3%) (10%) 378,667 2.16 224,801 1.44 64,202 0.37 58,049 0.33 553,303 3.44 200,032 1.44 137,184 0.85 139,383 0.87 (32%) (37%) 12% - (53%) (56%) (58%) (62%) 4,062,852 3,924,160 4% 963,678 1,131,715 (15%) 963,500 1,123,001 (14%) 2,285,889 2,001,802 14% 76,937 118,837 81,035 57,858 (5%) 105% 402,090 (10,956) 453,550 153,160 (11%) (107%) Weighted average outstanding equivalent shares: (thousands)(4) Basic Diluted 192,638 194,322 165,355 165,355 16% 18% 175,581 176,747 160,712 161,787 9% 9% Operating (boe conversion – 6:1 basis) Production: Natural gas (mmcf/day) Natural gas liquids (bbls/day) Oil (bbls/day)(7) Total oil equivalent (boe/day) Product prices:(8) Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl)(7) Operating expenses ($/boe) General and administrative expenses ($/boe) Cash costs ($/boe)(9) Operating netback ($/boe)(10) 269 14,563 12,395 71,842 3.22 42.60 75.73 8.69 1.07 12.67 19.12 268 14,628 14,110 73,373 3.69 58.78 89.36 9.26 0.95 ) - - (12%) (2%) (13%) (28%) (15%) (6%) 13% 13.16 (4%) 24.75 (23%) 253 14,074 12,997 69,250 2.60 45.19 77.30 9.07 1.06 13.26 17.70 255 12,890 13,868 69,332 4.06 55.09 81.91 9.05 0.95 (1%) 9% (6%) - (36%) (18%) (6%) - 12% 13.27 - 24.53 (28%) Highlights (cont’d) Drilling (gross wells): Natural gas Oil Average success rate Land: Undeveloped (net acres) Total (net acres) Reserves: (11) Proved: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) Proved and probable: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) % Proved producing % Proved % Probable Net present value of future cash flow before income taxes ($ 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: (12) Including changes in future development expenditures Excluding changes in future development expenditures NOTES: December 31, 2012 2011 % Change 115 47 67 99% 143 67 76 100% 1,253,141 2,832,701 1,474,080 3,078,418 921.0 94,914 248,409 1,372.3 143,505 372,220 40% 67% 33% 9,005 5,742 4,126 9.6 13.5 11.16 6.98 1.6 2.5 838.5 92,011 231,760 1,246.2 133,697 341,390 43% 68% 32% 9,766 6,184 4,472 8.8 12.2 13.98 11.08 1.8 2.2 (20%) (30%) (12%) (1%) (15%) (8%) 10% 3% 7% 10% 7% 9% (3%) (1%) 1% (8%) (7%) (8%) 9% 11% (20%) (37%) (11%) 14% (1) Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations as presented does not have any standardized meaning prescribed by IFRS 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 activitie s, net income or other measures of financial performance calculated in accordance with IFRS. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. 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 funds from operations per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. (3) Dividends declared includes both cash dividends and common shares issued pursuant to Bonavista's dividend reinvestment plan (DRIP) and Bonavista's stock dividend program (SDP). For the three months ended December 31, 2012 approximately 1.6 million common shares were issued under the DRIP and SDP with an approximate value of $24.7 million. For the year ended December 31, 2012, approximately 5.0 million common shares were issued under the DRIP and SDP with an approximate value of $82.9 million. (4) Basic net income per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. (5) Amounts have been adjusted to exclude unrealized gains and losses on financial instrument commodity contracts. (6) Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts. (7) Oil includes light, medium and heavy oil. (8) Product prices include realized gains and losses on financial instrument commodity contracts. (9) Cash costs equal the total of operating, transportation, general and administrative, and financing expenses. (10) Operating netback equals production revenues including realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses, calculated on a boe basis. (11) Working interest reserves are gross reserves prior to deduction of royalties and without including any of our royalty interests. (12) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition costs per boe. Share Trading Statistics ($ per share, except volume) High Low Close Average Daily Volume - Shares December 31, 2012 September 30, 2012 June 30, 2012 March 31, 2012 Three months ended 18.85 14.05 14.82 626,743 19.14 15.46 17.44 596,502 20.15 13.76 15.92 720,519 26.79 19.77 20.20 593,273 2 MESSAGE TO SHAREHOLDERS The North American energy sector was challenged by low realized commodity prices throughout 2012. Persistently high US production levels and the absence of winter heating demand drove AECO natural gas prices down to a 14 year low, averaging $2.27 per gigajoule in 2012, a 34% decrease from 2011. In addition, realized propane and ethane prices fell 41% and 28% respectively in 2012 resulting from a supply imbalance caused by industry’s focus on natural gas liquids revenue to support the economic development of natural gas resources. Compounding this compression in North American natural gas prices, Canadian energy producers were further challenged in 2012 by discounted pricing for crude oil resulting from steadily increasing continental supply and regional transportation and infrastructure bottlenecks. Technological advancements continue to add crude oil and natural gas supply making it increasingly difficult to predict the future pricing for these commodities. Furthermore, incremental infrastructure and valuable export opportunities are facing strong opposition leaving our domestic energy sector challenged in the short term. Nonetheless, Bonavista remains true to our strategy of focusing on those elements of our business that we can control to create value in any environment. The key elements of this strategy include: - Delivering an exploration and development program focused on profitability and capital efficiency, supported by low risk drilling opportunities, disciplined cost control and optimum execution; - Delivering an acquisition and divestiture program designed to concentrate our asset portfolio in highly prospective, multi-zone areas where we can control and enhance operating and capital efficiencies to extract incremental value from our assets; - Maintaining agility with our capital program to ensure the pursuit of our highest return opportunities; and - Remaining focused on restoring sustainability and financial flexibility. While declining Canadian natural gas production and fuel switching demand in the US power generation market enabled natural gas prices to recover somewhat in the fourth quarter of 2012, the futures market for natural gas prices weakened again in early 2013, coincident with a lack of winter heating demand. Accordingly, on January 9, 2013 Bonavista’s Board of Directors approved a reduction in the monthly dividend from $0.12 per share to $0.07 per share. This new level provides Bonavista the flexibility to capitalize on numerous low risk drilling and acquisition opportunities, while maintaining a healthy balance sheet. Given the current commodity price environment, Bonavista believes this dividend level offers an appropriate balance between capital reinvestment and dividend allocation resulting in long-term profitability, consistent with our historical track record. Specific accomplishments for Bonavista in 2012 include: Completed a successful capital expenditure program, investing $402.1 million in exploration and development activities drilling 115 wells with an overall 99% success rate; Completed an active acquisition and divestiture program, divesting of $180.8 million of non-core assets and reinvesting $169.9 million in strategic acquisitions within our core regions to increase the focus of our asset portfolio; Replaced 222% of 2012 annual production; Increased proved and probable reserves by 9% to 372.2 mmboe resulting in a finding, development and acquisition cost of $6.98 per boe (excluding changes in future development capital) and $11.16 per boe (including changes in future development capital); Improved our operating costs on a per boe basis, decreasing 6% for the three months ended December 31, 2012 to $8.69 per boe from $9.26 per boe in the comparable period in 2011; Increased our drilling inventory by 12% to 1,570 locations (88% horizontal), of which 95% are oil and liquids rich natural gas opportunities; Managed our exposure to commodity price volatility resulting in approximately 52% of our forecasted natural gas production (net of royalties) hedged at an average floor price of $3.03 per mcf and 37% of our forecasted oil and liquids production (net of royalties) hedged at an average floor price of $87.25 per bbl for 2013; Generated funds from operations of $378.7 million ($2.16 per share) for the year ended December 31, 2012; Raised $345 million from an equity financing to accommodate our 2012 and 2013 capital programs and provide flexibility for future growth; and Since 2003, when Bonavista introduced an income component to our total shareholder return, Bonavista has delivered cumulative dividends of over $2.5 billion or $26.19 per common share. 3 Accomplishments for Bonavista subsequent to 2012 include: Bonavista closed a $72.5 million agreement on January 9, 2013 to acquire 2,450 boe per day of low decline production situated on a highly synergistic land base and infrastructure footprint further enhancing the level of concentration and control within our deep basin core area; and Bonavista entered into a strategic business arrangement involving the disposition of certain Duvernay rights in exchange for cash proceeds, a four year extension to the primary term of 50% of the freehold acreage included in the “Hoadley transaction” completed in 2009, a reduced lessor royalty applicable to future capital activity on this acreage and other miscellaneous considerations. 2012 Reserve Highlights Bonavista replaced 2012 annual production by 222%, adding 56.1 mmboe of proved and probable reserves. Proved and probable reserve additions included 19.7 mmbbls of oil and liquids and 36.4 mmboe of natural gas bringing total year end 2012 reserves to 372.2 mmboe; Bonavista’s oil and liquids focused exploration and development activity replaced 2012 annual oil and liquids production by 218%, resulting in a 16% increase in year end 2012 oil and liquids reserves net of acquisitions and dispositions; Bonavista’s proved and probable reserve life index increased 11% to 13.5 years based on the GLJ year end reserve report; Bonavista’s successful capital expenditure program in 2012 resulted in attractive finding, development and acquisition costs, including changes in future development expenditures, of $11.16 per boe on a proved and probable basis. Despite a compressed commodity price environment throughout 2012, these finding, development and acquisition cost metrics generated an attractive proved and probable operating netback recycle ratio of 1.6:1 based on 2012 operating netbacks and 1.8:1 based on forecasted 2013 operating netbacks; and Proved and probable future development capital increased by 21% to $1.4 billion, representing the growth in development potential of our asset base but remaining at a manageable level within 3.0 times forward cash flow and 3.2 times budgeted 2013 capital expenditures. 2012 Acquisition and Divestiture Highlights Bonavista completed 24 property transactions in 2012, both acquisitions and divestitures resulting in net disposition proceeds of $11.0 million for the year. Acquisition expenditures in 2012 of $169.9 million added production of 7,300 boe per day and proved and probable reserves of 29.9 mmboe resulting in acquisition metrics of $23,000 per boe per day and $10.39 per boe including future development costs. Divestiture activity in 2012 resulted in proceeds of $180.8 million involving the sale of certain non-core, higher cost assets comprising 3,200 boe per day of production and 9.7 mmboe of proved and probable reserves. The transaction metrics associated with our 2012 divestiture activity are attractive at $57,000 per boe per day and $21.68 per boe including changes in future development costs. With a specific goal to increase asset quality and concentration, Bonavista was an active consolidator in the deep basin area of west central Alberta in 2012. On October 1, 2012 Bonavista closed a $155 million asset acquisition producing 6,700 boe per day, which doubled Bonavista’s land position and greatly enhanced its control of strategic facility infrastructure. With the second transaction that Bonavista closed in January 2013, this recent acquisition activity has significantly expanded our operational presence in the area increasing production by 150% to approximately 14,000 boe per day, proved and probable reserves by 160% to 56 mmboe, land position by 140% to 210,000 net acres, processing capacity by 120% to 230 mmcf per day and inventory levels by 60% to 200 horizontal locations. More important in today’s commodity price environment, the increased scale of operations offered by this consolidation activity has enabled operating efficiency gains as evidenced by a 25% decline in area operating costs. Furthermore, with a larger development program now in place, Bonavista believes it can drive incremental growth and capital efficiencies through increasing economies of scale. 2012 Operational Highlights Hoadley Glauconite Liquids Rich Natural Gas Bonavista drilled seven horizontal wells in the fourth quarter bringing total 2012 activity to 34 horizontal wells in a program focused on continuous optimization of field level economics. Specific efforts in 2012 consisted of downspacing initiatives, longer lateral sections and enhancing our understanding of the geological characteristics of the reservoir. Bonavista’s 2012 development activities on the Hoadley Glauconite trend resulted in an efficient exploitation program adding $200.9 million of NPV 10% value and 13.1 mmboe of proved and probable reserves with attractive metrics of $6,800 per boe per day based on average initial month production rates and $7.25 per boe. Based on current production 4 levels and forward commodity pricing, Bonavista’s horizontal Glauconite program is expected to provide sufficient cash flow in 2013 to support continued growth at the field level while contributing to improved overall corporate sustainability. Despite the active development program in 2012, Bonavista increased its drilling inventory by 8% to 410 locations through continued land assembly and the testing of downspacing to four wells per section in a pilot program that has yielded successful initial results. We will continue to monitor well performance with these pilots throughout 2013 and with continued positive results, we expect the program to increase in scope in future years. At current natural gas prices, single well economics associated with this play remain competitive on a North American scale and within our asset portfolio owing to the predictable results, attractive natural gas liquids yield, low operating costs and strong capital efficiencies. Bonavista’s Glauconite development program remains a key growth platform in 2013, with a drilling program of approximately 45 horizontal wells. West Central Cardium Light Oil Bonavista drilled 12 horizontal wells in the fourth quarter bringing total 2012 activity to an annual record of 32 horizontal wells in a program balanced between the proven high productivity trends and the emerging portions of our land base. Our operated development program in 2012 focused on the Ferrier/Willesden Green area with 19 horizontal wells drilled. Production results in this area have been strong delivering average first month production rates of 250 boe per day in 2012. In a continued effort to de-risk additional acreage, Bonavista drilled one well at Lochend in the fourth quarter which confirmed our geological interpretation of the area despite operational issues that restricted the effective stimulation of the wellbore to less than 50% of the original program. Bonavista’s 2012 activity in the Cardium resulted in the addition of $111.9 million in NPV 10% value and 3.4 mmboe of proved and probable reserves with efficient metrics of $15,700 per boe per day based on average initial month production rates and $21.25 per boe. Importantly, Bonavista was successful in the conversion of 2.7 mmboe of Proved Undeveloped reserves to Proved Developed Producing reserves while continuing to grow our inventory of future drilling opportunities to 140 horizontal locations. Bonavista’s Cardium development program continues to rank favourably in our portfolio and we plan to drill approximately 20 horizontal wells in 2013. Deep Basin Multi-zone Liquids Rich Natural Gas Bonavista drilled two horizontal wells in the fourth quarter contributing to a total of eight wells in 2012 targeting low risk opportunities in the Bluesky formation at Pine Creek. Since entering the area in 2010 Bonavista’s activities in this multi- zone area of the deep basin involved a focus on low risk opportunities in the Bluesky and Rock Creek formations. This approach provided an opportunity to gain operational experience as we continue to evaluate additional emerging plays including the Montney, Notikewin and Wilrich. Bonavista plans to drill approximately 15 to 20 horizontal wells in the area including 10 Rock Creek light oil or liquids rich natural gas wells at Rosevear, two Bluesky liquids rich natural gas wells at Pine Creek and selective testing of the prolific Wilrich play in 2013. Bonavista’s acquisition activity in 2012 provided a solid platform of inventory and operations in the Wilrich, a play rapidly emerging with significance in the Deep Basin. Additional Emerging Opportunities Bonavista continued to de-risk two key emerging plays in the fourth quarter, drilling six horizontal Viking oil wells at Provost in eastern Alberta and one horizontal well targeting liquids rich natural gas in the Ellerslie formation in west central Alberta. Production results in the Viking formation at Provost have met expectations throughout 2012. Backed by incremental operational experience in this play, we are poised to enhance capital efficiencies with plans to drill 18 to 20 Viking oil wells in 2013. Similarly, we plan to drill up to seven Ellerslie horizontal wells in 2013 as we progress both the Ellerslie and Viking emerging plays to scaleable capital programs. Bonavista will continue to delineate its liquids rich Montney acreage at Blueberry in northeast British Columbia in 2013 with one to two horizontal wells planned. While encouraged by the high natural gas liquids yield exhibited by the six horizontal wells drilled to date, development economics are challenged in the current low natural gas price environment. Notwithstanding the near term challenges, offsetting industry activity in the Montney horizon has accelerated over the past year driven by technological achievements in well cost reductions and an increased motivation to secure large scale resources to support eventual west coast LNG export initiatives. Bonavista intends to drill four to six wells over the next two years to verify the scale of the opportunity while monitoring industry activity to maximize the net present value of the resource situated on our 55 net section land base. In addition to the Montney, Ellerslie and Viking formations, our technical teams continue to identify and evaluate additional emerging resource opportunities in 2013 with a focus on light oil or liquids rich natural gas in numerous formations. 5 Strengths of Bonavista Energy Corporation Beginning in 1997, with an initial restructuring to create a high growth junior exploration company, throughout the energy trust phase between July 2003 and December 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 past 15 years. We have steadily improved the quality and maintained a high level of investment activity on our asset base, increasing production by approximately 110% since converting to an energy trust in July 2003 and a further 8% since converting back to a corporation at the end of 2010. These results stem from the operational, technical and financial expertise of our people with 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 as they exercise the discipline and commitment required to deliver long-term value to our shareholders. We actively participate in undeveloped land acquisitions, 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, and a predictable production base that continues to grow at a healthy pace. Our production base is currently 64% weighted 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 ensures positive operating netbacks in most operating environments. Furthermore, our assets are predominantly operated by Bonavista, providing control over the pace of operations and optimum influence over our operating and capital cost efficiencies. Our team brings a successful track record of executing low to medium risk development programs, including both asset and corporate acquisitions, along with 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 13% of the equity of Bonavista, resulting in the alignment of interests with all shareholders. Outlook As we progress into our third year as a dividend paying corporation, Bonavista remains committed to a business model built on maximizing total shareholder return. Throughout the volatile commodity price environment of 2012, Bonavista decisively adjusted to the environment while maintaining sharp attention to our core strengths that have proven to add shareholder value over the long-term. These strengths include continually exercising cost discipline and a high level of capital spending efficiency as we pursue low risk, profitable opportunities. In 2013, Bonavista intends to maintain the same strategies we employed in 2012 in our quest to drive incremental efficiency into our business through further concentration of our asset base in a compelling acquisition and divestiture market. We are encouraged by the number of acquisition opportunities in the market and look forward to capitalizing on those that provide a synergistic advantage. Additionally, we are currently in the process of marketing certain non- strategic assets which, if successful, would enable a redeployment of capital into our most capital efficient areas of operation. Until conclusion of our current asset divestiture process, Bonavista’s 2013 capital budget remains at approximately $425 million, with a program to drill between 120 and 125 wells within our core areas. This capital program is expected to result in 2013 production volumes of between 73,500 and 74,500 boe per day. As in years past, we will be attentive to changes in commodity prices and the business environment and will maintain flexibility with our capital expenditure plans in order to maximize shareholder value. We would like to thank our employees for their commitment to Bonavista’s proven operating strategies and our shareholders for their continual support as we strive to weather this latest phase of the commodity cycle. We have confidence that our strategies are appropriate for today’s environment and we look forward to continually creating long- term value for our shareholders. Our team is very committed to this vision. On behalf of the Board of Directors Keith A. MacPhail Executive Chairman March 20, 2013 Calgary, Alberta Jason E. Skehar President and Chief Executive Officer 6 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, 2012. The following MD&A of the financial condition and results of operations was prepared at, and is dated March 20, 2013. Basis of Presentation - The financial data presented below has been prepared in accordance with International Financial Reporting Standards ("IFRS"). 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 and plans; (ii) exploration, drilling and development plans; (iii) prospects and drilling inventory and locations; (iv) anticipated production rates; (v) anticipated operating and service costs; (vi) our financial strength; (vii) incremental development opportunities; (viii) total shareholder return; (ix) asset acquisition and disposition plans; (x) growth prospects; (xi) sources of funding, 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. Non-IFRS 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 IFRS 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 IFRS. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. Basic funds from operations per share is calculated based on the weighted average number of common shares outstanding in accordance with International Financial Reporting Standards. Operating netbacks equal production revenues and realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the number of days in the period. Management uses these terms to analyze operating performance and leverage. light oil wells. Operations - Bonavista's exploration and development program for the year ended December 31, 2012 led to the drilling of 115 wells within our core regions and a success rate of 99%. This program resulted in 47 liquids rich natural gas wells and 67 three months ended December 31, 2012, led to the drilling of 28 wells within our core region and a success rate of 100%. The program resulted in 9 liquids rich natural gas wells and 19 light oil wells. Profitability continues to guide our exploration and development program which remains flexible to changes in commodity price, development risk and deliverability upside. Closely aligned with our expectations, our fourth quarter exploration and development programs have delivered solid rates of return and have reinforced our confidence in the predictability and repeatability of our extensive drilling inventory. Bonavista's exploration and development program the for 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, 88% were evaluated by independent third party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") in their report dated February 27, 2013. The balance of approximately 12% 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, 2012 and are defined under NI 51-101, as our interest before deduction of royalties and without including any of our royalty interests. 7  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) 550,744 27,448 342,776 920,968 451,323 1,372,291 Light and Medium Oil (Mbbls) Heavy Oil (Mbbls) Natural Gas Liquids (Mbbls) Total Reserves(2) (Mboe) 22,108 817 6,000 28,925 11,048 39,973 3,650 488 723 4,861 2,837 7,698 31,206 1,189 28,733 61,128 34,707 95,834 148,756 7,068 92,585 248,408 123,812 372,220 9.6 13.5 (1) (2) (3) (4) Bonavista’s gross reserves are based on the GLJ reserve report dated February 27, 2013, GLJ reserve estimates based on forecast prices and costs as of January 1, 2013. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl 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 2013 production forecast. Amounts may not add due to rounding. Reserve Reconciliation:(1) Balance, December 31, 2011 Extensions and improved recovery Technical revisions Acquisitions Dispositions Economic factors Production Balance, December 31, 2012 Amounts may not add due to rounding. (1) Proved (Mboe) 231,760 24,258 5,786 20,692 (6,739) (2,112) (25,236) 248,409 Probable (Mboe) 109,629 12,387 (3,071) 9,246 (2,933) (1,447) - 123,811 Proved and Probable (Mboe) 341,390 36,645 2,715 29,938 (9,672) (3,559) (25,236) 372,220 Bonavista’s 2012 year-end proved reserves totalled 248.4 mmboe, a 7% increase compared to the 231.8 mmboe at year-end 2011. Furthermore, Bonavista’s proved and probable reserves increased by 9% to 372.2 mmboe when compared to the 341.4 mmboe at year-end 2011. The following tables highlight both our proved and probable finding and development ("F&D") costs and our proved and probable finding, development and acquisition ("FD&A") costs: Proved and probable reserves (Mboe): (2) Opening balance Discoveries and extensions Acquisitions and dispositions Revisions and economic factors Production Closing balance Finding and development costs: Total F&D expenditures ($ millions) Total F&D expenditures plus change in forecast future development costs ($ millions) Proved and probable F&D costs ($/boe) Proved and probable three-year F&D costs ($/boe) (1) (1) Finding, development and acquisition costs: Total FD&A expenditures ($ millions) Total FD&A expenditures plus change in forecast future development costs ($ millions) Proved and probable FD&A costs ($/boe) Proved and probable three-year FD&A costs ($/boe) (1) (1) (1) (2) Amounts are calculated including the change in future development costs. Amounts may not add due to rounding. 2012 2011 2010 341,390 36,645 20,266 (844) (25,236) 372,220 310,749 33,667 22,402 (365) (25,063) 341,390 271,913 32,583 25,555 4,861 (24,163) 310,749 402.1 524.7 14.66 13.89 391.1 625.8 11.16 12.82 453.6 480.5 14.43 13.32 617.1 778.7 13.98 12.86 348.1 474.4 12.67 14.39 568.6 836.2 13.27 13.55 8 Finding, development and acquisition costs in 2012, including changes in future capital expenditures, amounted to $12.80 per boe ($9.34 per boe before changes in future capital expenditures) on a proved basis and $11.16 per boe ($6.98 per boe before changes in future capital expenditures) on a proved and probable basis. Capital Efficiency: Operating netback ($/boe) Total changes in capital expenditures: (1) (excluding changes in future development costs) Proved and probable F&D costs ($/boe) Recycle ratio (3) (2) Proved and probable FD&A costs ($/boe) Recycle ratio (3) (2) Total changes in capital expenditures: (including changes in future development costs) Proved and probable F&D costs ($/boe) Recycle ratio (3) (2) Proved and probable FD&A costs ($/boe) Recycle ratio (3) (2) 2012 17.70 2011 24.53 2010 23.85 11.23 1.6 6.98 2.5 14.66 1.2 11.16 1.6 13.62 1.8 11.08 2.2 14.43 1.7 13.98 1.8 9.30 2.6 9.03 2.6 12.67 1.9 13.27 1.8 Three- Year Average 22.03 11.30 1.9 9.02 2.4 13.89 1.6 12.82 1.7 (1) Operating netback is calculated using production revenues including realized gains or losses on financial instruments commodi ty contracts less royalties, transportation and operating costs calculated on a per barrel of oil equivalent basis. Both F&D and 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 either F&D or FD&A costs on a per barrel of oil equivalent. (2) (3) Despite the challenging commodity price environment in 2012, Bonavista generated an attractive recycle ratio of 1.6:1 for proved and probable reserves and 1.2:1 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 2.5:1 and the proved recycle ratio remained at 1.6:1. Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista’s Annual Information Form that will be filed on SEDAR. 9 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 amounts where noted) Three months ended December 31, 2012 2011 Years ended December 31, 2012 2011 Product prices: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Production: Natural gas (mmcf/d) Natural gas liquids (bbls/d) Oil (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 Transaction costs per boe Share-based compensation per boe Depreciation, depletion, amortization and impairment per boe Net finance costs per boe Deferred income taxes per boe Net income (loss) per boe per share – basic Dividends declared per share Funds from operations per boe per share – basic 3.22 42.60 75.73 269 14,563 12,395 71,842 223,021 33.74 29,650 4.49 13.3% 57,464 8.69 9,732 1.47 7,089 1.07 960 0.15 5,845 0.88 90,282 13.66 18,284 2.77 7,822 1.18 14,442 2.19 0.07 63,481 0.36 110,015 16.65 0.57 3.69 58.78 89.36 268 14,628 14,110 73,373 285,167 42.25 44,902 6.65 15.7% 62,486 9.26 11,488 1.70 6,392 0.95 - - 6,402 0.95 100,967 14.96 8,892 1.32 5,446 0.81 (3,321) (0.49) (0.02) 51,850 0.36 150,843 22.56 0.91 2.60 45.19 77.30 253 14,074 12,997 69,250 832,491 32.85 124,300 4.90 14.9% 229,847 9.07 38,367 1.51 26,967 1.06 960 0.04 19,450 0.77 331,023 13.06 41,611 1.64 26,292 1.04 64,202 2.53 0.37 224,801 1.44 378,667 14.94 2.16 4.06 55.09 81.91 255 12,890 13,868 69,332 1,044,414 41.27 161,742 6.39 15.5% 229,072 9.05 40,581 1.60 24,146 0.95 - - 17,282 0.68 313,475 12.39 60,419 2.39 57,149 2.26 137,184 5.42 0.85 200,032 1.44 553,303 21.92 3.44 10 Production - For the year ended December 31, 2012, total production was consistent at 69,250 boe per day when compared to 69,332 boe per day for the same period a year ago. Natural gas production was stable at 253 mmcf per day for the year ended December 31, 2012 compared to 255 mmcf per day for the same period a year ago. Natural gas liquids production increased 9% to 14,074 bbls per day in 2012 from 12,890 bbls per day for the same period in 2011, due in large part to our continued emphasis on drilling liquids rich natural gas wells. Oil production decreased 6% to 12,997 bbls per day in 2012 from 13,868 bbls per day for the same period in 2011, as a result of our dispositions of certain oil weighted properties. For the fourth quarter of 2012, total production decreased 2% to 71,842 boe per day when compared to 73,373 boe per day for the same period a year ago. The decrease in production volumes is largely the result of the disposition of 3,200 boe per day of non-core assets, 725 boe per day of reduced recoveries at third party facilities and 600 boe per day of dry natural gas curtailments. Natural gas production was stable at 269 mmcf per day in the fourth quarter of 2012 compared to 268 mmcf per day for the same period a year ago, while oil production decreased 12% to 12,395 bbls per day in the fourth quarter of 2012 from 14,110 bbls per day for the same period in 2011 largely due to the reasons stated above. Natural gas liquids production remained relatively unchanged in the fourth quarter of 2012 at 14,563 bbls per day which compares to 14,628 bbls per day for the same period in 2011. The following table highlights Bonavista's production by product for the three months and years ended December 31: Natural gas (mmcf/day) Natural gas liquids (bbls/day) Oil (bbls/day) Total oil equivalent (boe/day) Three months ended December 31, Years ended December 31, 2012 269 14,563 12,395 71 71,842 2011 268 14,628 14,110 73,373 2012 253 14,074 12,997 69,250 2011 255 12,890 13,868 69,332 Our current production is approximately 73,000 boe per day, consisting of 64% natural gas, 19% natural gas liquids and 17% oil and our reserve life index (“RLI”) has increased to approximately 14 years. Production revenues - Production revenues for the year ended December 31, 2012 decreased 20% to $832.5 million when compared to $1,044.4 million for the same prior year period, led largely by a decrease in commodity prices. For the year ended December 31, 2012, natural gas prices decreased 36% to $2.60 per mcf, when compared to $4.06 per mcf realized in the same period in 2011. Natural gas liquids price decreased 18% to $45.19 per bbl for the year ended December 31, 2012 from $55.09 per bbl for the same period in 2011. For the year ended December 31, 2012, oil pricing decreased 6% to $77.30 per bbl, compared to $81.91 per bbl for the same period a year ago. Production revenues for the fourth quarter of 2012 decreased 22% to $223.0 million when compared to $285.2 million for the same period a year ago, due to a lower product pricing environment. For the three months ended December 31, 2012, natural gas prices decreased 13% to $3.22 per mcf, when compared to $3.69 per mcf realized in the same period in 2011. Natural gas liquids pricing decreased 28% to $42.60 per bbl for the three months ended December 31, 2012 from $58.78 per bbl for the same period in 2011. For the three months ended December 31, 2012, oil pricing decreased 15% to $75.73 per bbl, compared to $89.36 per bbl for the same period a year ago. 11 The following table highlights Bonavista's realized commodity pricing for the three months and year ended December 31: Natural gas ($/mcf): Production revenues Realized gains/(losses) on financial instruments commodity contracts Natural gas liquids ($/bbl): Production revenues Realized gains on financial instrument commodity contracts Oil ($/bbl): Production revenues Realized gains/(losses) on financial instrument commodity contracts Total ($/boe): Production revenues Realized gains on financial instrument commodity contracts Three months ended December 31, 2012 2011 Years ended December 31, 2012 2011 $ 3.28 $ 3.57 $ 2.52 $ 3.91 (0.06) 3.22 42.60 - 42.60 74.25 1.48 75.73 33.74 0.12 3.69 58.78 - 58.78 90.96 (1.60) 89.36 42.25 0.08 2.60 45.19 - 45.19 76.93 0.37 77.30 32.85 0.15 4.06 55.09 - 55.09 83.19 (1.28) 81.91 41.27 0.03 0.12 0.34 0.31 $ 33.77 $ 42.37 $ 33.19 $ 41.58 Risk management activities - 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 and to protect acquisition economics. Bonavista’s Board of Directors has approved a commodity price risk management limit of 60% of the current year's total budgeted revenue, net of royalties provided that no more than 80% of forecasted revenues from any one product may be hedged. The term of any commodity hedge executed will be limited to no more than three calendar years subsequent to the current calendar year in which an executed hedge is made. We primarily use swaps and costless collars which limits Bonavista’s exposure to volatility in commodity prices, while in the case of costless collars allows for participation in commodity price increases. For the year ended December 31, 2012, our risk management program on financial instrument commodity contracts resulted in a gain of $16.8 million, consisting of a realized gain of $8.6 million and an unrealized gain of $8.2 million. The realized gain of $8.6 million consisted of a $6.8 million gain on natural gas commodity contracts and a $1.8 million gain on oil commodity contracts. For the same period in 2011, our risk management program on financial instrument commodity contracts resulted in a net gain of $4.8 million, consisting of a realized gain of $7.8 million and an unrealized loss of $2.9 million. The realized gain of $7.8 million consisted of a $14.3 million gain on natural gas commodity contracts and a $6.5 million loss on oil commodity contracts. For the fourth quarter of 2012, our risk management program on financial instrument commodity contracts resulted in a loss of $2.6 million, consisting of a realized gain of $204,000 and an unrealized loss of $2.8 million. The realized gain of $204,000 was the result of a gain of $1.7 million on oil commodity contracts, offset by a loss of $1.5 million on natural gas commodity contracts. For the same period in 2011, our risk management program on financial instrument commodity contracts resulted in a net loss of $26.3 million, consisting of a realized gain of $812,000 and an unrealized loss of $27.1 million. The realized gain of $812,000 consisted of a $2.9 million gain on natural gas commodity contracts and a $2.1 million loss on oil commodity contracts. 12 Commodity price risk is the risk that 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. As a result of higher than historical leverage ratios, Bonavista has engaged in a more active hedging program in order to protect future cash flows through the use of various financial instrument commodity contracts and physical delivery sales contracts. i) Financial instrument commodity contracts: As at December 31, 2012, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume Average Price Term 35,000 gjs/d 40,000 gjs/d 45,000 gjs/d 5,000 gjs/d 10,000 gjs/d 10,000 gjs/d 500 bbls/d 7,500 bbls/d 1,500 bbls/d CDN $2.87 - CDN $3.44 - AECO CDN $2.93 - CDN $3.73 - AECO CDN $2.75 - CDN $3.27 - AECO CDN $3.50 - CDN $4.00 - AECO CDN $3.25 - CDN $4.14 - AECO CDN $2.85 - CDN $3.50 - AECO CDN $95.00 - CDN $115.00 - WTI CDN $87.00 - CDN $102.35 - WTI CDN $83.33 - CDN $99.25 - WTI January 1, 2013 - December 31, 2013 January 1, 2013 - December 31, 2014 April 1, 2013 - October 31, 2013 November 1, 2013 - March 31, 2014 January 1, 2014 - December 31, 2014 April 1, 2014 - October 31, 2014 January 1, 2013 - June 30, 2013 January 1, 2013 - December 31, 2013 January 1, 2014 - December 31, 2014 Subsequent to December 31, 2012, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume Average Price Term 10,000 1,500 1,500 500 gjs/d bbls/d bbls/d bbls/d CDN $3.38 - CDN $3.92 - AECO CDN $88.17 - CDN $100.05 - WTI CDN $85.83 - CDN $99.57 - WTI CDN $87.50 - CDN $97.50 - WTI January 1, 2014 - December 31, 2015 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 January 1, 2015 - December 31, 2015 As at December 31, 2012, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume 10,000 35,000 1,000 gjs/d gjs/d bbls/d Price CDN $2.51 CDN $2.84 CDN $87.35 Contract Swap - AECO Swap - AECO Swap - WTI Term January 1, 2013 - June 30, 2013 January 1, 2013 - December 31, 2013 January 1, 2013 - December 31, 2013 Subsequent to December 31, 2012, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume 15,000 5,000 gjs/d gjs/d Price CDN $3.43 CDN $3.55 Contract Swap - AECO Swap - AECO Term January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 Financial instrument commodity contracts are recorded on the consolidated statements of financial position 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 income and comprehensive income. As at December 31, 2012, the fair market value recorded on the consolidated statement of financial position for these financial instrument commodity contracts was a net liability of $504,000, compared to a net liability of $8.7 million as at December 31, 2011. These financial instrument commodity contracts had the following gains and losses reflected in the consolidated statements of income and comprehensive income: Three months ended December 31, 2012 2011 Years ended December 31, 2012 2011 Realized gains on financial instrument commodity contracts Unrealized gains/(losses) on financial instrument commodity contracts $ 204 $ 812 $ 8,851 $ 7,766 (2,793) (27,109) 8,210 (2,935) Total ($/boe) $ (2,589) $ (26,297) $ 16,791 $ 4,831 13 A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $3.5 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2012 (2011 - $2.5 million). A $1.00 change in the price per barrel of oil - WTI would have an impact of approximately $1.6 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2012 (2011 - $1.8 million). Royalties - For the year ended December 31, 2012, royalties decreased by 23% to $124.3 million from $161.7 million for the same period a year ago, largely due to a 20% decrease in product pricing per boe. Royalties as a percentage of revenues (including realized gains and losses on financial instrument commodity contracts) for 2012 decreased to 14.8% compared to 15.4% in same period in 2011. The decrease in royalty rates for the year ended December 31, 2012 is attributed to lower natural gas and oil royalties as a result of lower product pricing. For the three months ended December 31, 2012, royalties decreased by 34% to $29.7 million from $44.9 million for the same period a year ago, largely attributable to a 20% decrease in product pricing per boe and a slight decrease in production volumes. Royalties as a percentage of revenues (including realized gains and losses on financial instrument commodity contracts) for the fourth quarter of 2012 decreased to 13.3% when compared to 15.7% for the same period in 2011 due to the reasons stated above. The fourth quarter royalty rates were also impacted by the 28% decrease in natural gas liquids pricing. The following table highlights Bonavista's royalties by product for the three months and year ended December 31: Natural gas ($/mcf): Royalties % of revenues (1) Natural gas liquids ($/bbl): Royalties % of revenues (1) Oil ($/bbl): Royalties % of revenues (1) Three months ended December 31, Years ended December 31, 2012 0.20 6.2% 9.43 22.1% 10.57 14.0% 2011 0.31 8.5% 13.19 22.4% 14.95 16.7% 2012 0.17 6.4% 10.00 22.1% 12.06 15.6% 2011 0.31 7.7% 12.89 23.4% 14.25 17.4% (1) % of revenues include realized gains and losses on financial instrument commodity contracts Operating expenses - Operating expenses for the year ended December 31, 2012 were virtually unchanged on both an absolute and per boe basis at $229.8 million and $9.07 per boe compared to $229.1 million and $9.05 per boe in the comparable period of 2011. Although our per boe operating costs for the year ended December 31, 2012 did not fluctuate year over year, we did experience some increased fluid hauling costs associated with our oil and natural gas liquids volumes, which were offset by a reduction of our natural gas operating costs through consolidation and acquisition activities. For the three months ended December 31, 2012 operating expenses decreased 8% to $57.5 million compared to $62.5 million for the same period a year ago, and on a per boe basis decreased 6% to $8.69 per boe, from $9.26 per boe for the same period in 2011. Absolute and per unit operating costs have decreased year over year as a result of dispositions of non-core assets characterized by a higher cost structure, modest reductions in per unit costs due to service providers competing in certain areas which have experienced reduced activity levels and the acquisition of lower cost production. The following table highlights Bonavista's operating expenses by product for the three months and year ended December 31: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) Three months ended December 31, Years ended December 31, $ 2012 1.15 10.94 12.57 $ $ 8.69 $ 2011 1.28 10.76 12.72 9.26 2012 1.23 10.90 12.59 9.07 $ $ 2011 1.29 10.24 12.01 9.05 $ $ Transportation expenses - For the year ended December 31, 2012, transportation expenses decreased 5% to $38.4 million compared to $40.6 million for the same period in 2011. For the year ended December 31, 2012, transportation costs on a per boe basis have decreased 6% to $1.51 per boe from $1.60 per boe in the same period in 2011. The decrease in transportation expenses is due to a change in the composition of production volumes, natural gas liquids volumes increased by 9% when compared to the same period in 2011, while oil volumes decreased by 6% when compared to the same prior year period. 14 For the three months ended December 31, 2012, transportation expenses decreased 15% to $9.7 million compared to $11.5 million for the same period in 2011. For the three months ended December 31, 2012, transportation costs on a per boe basis decreased by 14% to $1.47 per boe, compared to $1.70 per boe in the same period in 2011. The following table highlights Bonavista’s transportation costs by product for the three months and year ended December 31: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) Three months ended December 31, Years ended December 31, 2012 0.26 0.89 1.91 1.47 $ $ 2011 0.29 1.01 2.31 1.70 $ $ $ $ 2012 0.26 0.87 1.99 1.51 2011 0.29 0.86 1.91 1.60 $ $ General and administrative expenses - General and administrative expenses, after overhead recoveries, increased 12% to $27.0 million for the year ended December 31, 2012 from $24.1 million in the same period in 2011 and increased 11% to $7.1 million for the three months ended December 31, 2012 from $6.4 million in the same period in 2011. On a per boe basis, general and administrative expenses the year ended December 31, 2012 from $0.95 per boe in the same period in 2011 and increased 13% for the three months ended December 31, 2012 to $1.07 per boe from $0.95 per boe in the same period in 2011. The increase in general and administrative expenses for the three months and year ended December 31, 2012, when compared to the same periods in 2011, is due to higher costs of personnel required to manage our business and lower capital overhead recoveries associated with the composition of our exploration and development capital program. Our current rate of general and administrative expenses on a per boe basis remains among the lowest in our sector, despite the recent increase. to $1.06 per boe increased 12% for In connection with its stock option and common share rights incentive plans and restricted share award and restricted common share incentive plans, Bonavista recorded a share-based compensation charge of $5.8 million and $19.5 million for the three months and year ended December 31, 2012, respectively, compared to $6.4 million and $17.3 million for the same periods in 2011. Depletion, depreciation, amortization and impairment expenses - Depletion, depreciation, amortization and impairment expenses increased 6% to $331.0 million for the year ended December 31, 2012 from $313.5 million ($297.5 million excluding impairment) for the same period in 2011. The increase in depletion, depreciation, amortization and impairment expense year over year, having not recorded an impairment charge in 2012, is related to an overall increase in costs related to finding, developing and acquiring reserves. For the three months ended December 31, 2012, depreciation, depletion, amortization and impairment expenses decreased 11% to $90.3 million from $101.0 million ($85.0 million excluding impairment) for the same period in 2011 largely due to the impairment charge recognized in 2011 offset by an overall increase in costs relating to finding, developing and acquiring reserves. For the year ended December 31, 2012, the average charge increased 5% to $13.06 per boe from $12.39 per boe ($11.75 per boe excluding impairment) for the same period in 2011 and for the three months ended December 31, 2012, the average charge decreased 9% to $13.66 per boe from $14.96 per boe ($12.59 per boe excluding impairment) for the same period a year ago. For the three months and year ended December 31, 2012, there was no goodwill impairment charge. For the three months and year ended December 31, 2011, there was a goodwill impairment charge of $20.1 million related to two natural gas weighted cash generating units. Net financing costs - Net financing costs decreased 31% to $41.6 million for the year ended December 31, 2012 from $60.4 million for the same period in 2011, due mainly to fluctuations in foreign exchange gains and losses associated with the revaluation of our US denominated senior unsecured notes. For the year ended December 31, 2012, net financing costs decreased 31% to $1.64 per boe from $2.39 per boe for the same period in 2011. For the three months ended December 31, 2012, net financing costs increased 106% to $18.3 million from $8.9 million for the same period in 2011, due to similar reasons as stated above. For the three months ended December 31, 2012, net financing costs on a per boe basis increased 110% to $2.77 per boe compared to $1.32 per boe for the same period in 2011. 15 As part of our financial management program, Bonavista mitigates its currency risk associated with its repayment of its US senior unsecured notes by utilizing foreign exchange forward contracts. In the third quarter of 2011, Bonavista entered into the following foreign exchange forward contracts to manage its currency risk associated with its repayment of its US senior unsecured notes: Forward date November 2, 2017 November 2, 2020 November 2, 2022 Contract US purchased forward US purchased forward US purchased forward Notional US$ $30,000,000 $53,300,000 $16,500,000 CDN$/US$ 0.995 0.995 0.995 As at December 31, 2012, the fair market value recorded on the consolidated statement of financial position for those financial instrument contracts was a long-term asset of $4.3 million compared to a long-term asset of $3.6 million as at December 31, 2011. A $0.01 change in CDN$/US$ exchange rate would have an impact of approximately $655,000 on net income for those foreign exchange forward contracts in place as at December 31, 2012 (2011 - $619,000). Deferred income taxes - The provision for deferred income taxes for the year ended December 31, 2012, was $26.3 million compared to $57.1 million during the same period in 2011. For the three months ended December 31, 2012 the deferred income tax provision was $7.8 million compared to a provision of $5.4 million during the same period in 2011. The deferred income tax provision for the year ended December 31, 2012 is higher than the provision calculated using the expected rate which is mainly attributable to non-deductible share-based compensation expense offset by the income tax treatment of foreign currency translation gains on long-term debt. Bonavista made no cash payments or tax installments for the three months and year ended December 31, 2012 or for the comparative periods in 2011. Funds from operations, net income and comprehensive income - For the year ended December 31, 2012, Bonavista experienced a 32% decrease in funds from operations to $378.7 million ($2.16 per share, basic) from $553.3 million ($3.44 per share, basic) for the same period in 2011, due to a 20% decrease in product prices per boe. For the three months ended December 31, 2012, Bonavista experienced a 27% decrease in funds from operations to $110.0 million ($0.57 per share, basic) from $150.8 million ($0.91 per share, basic) for the same period in 2011, due to lower product prices and slightly lower production volumes. Net income and comprehensive income for the year ended December 31, 2012, decreased 53% to $64.2 million ($0.37 per share, basic) from $137.2 million ($0.85 per share, basic) for the same period in 2011, due to lower product pricing. Net income and comprehensive income for the three months ended December 31, 2012, was $14.4 million ($0.07 per share, basic) from a loss of $3.3 million ($0.02 loss per share, basic) for the same period in 2011, largely due to the impairment charges recorded in 2011. The following table is a reconciliation of a non-IFRS measure, funds from operations, to its nearest measure prescribed by IFRS: Calculation of Funds From Operations: (thousands) Cash flow from operating activities Interest expense Decommissioning expenditures Changes in non-cash working capital Funds from operations Three months ended December 31, 2012 2011 Years ended December 31, 2012 2011 $ 102,886 (9,487) 11,410 5,206 $ 145,150 (8,454) 5,973 8,174 $ 407,481 (40,878) 25,530 (13,466) $ 567,166 (41,922) 21,136 6,923 $ 110,015 $ 150,843 $ 378,667 $ 553,303 Capital expenditures - Net capital expenditures for the year ended December 31, 2012 were $394.4 million, consisting of $402.1 million spent on exploration and development activities, $169.9 million spent on property acquisitions, head office expenditures of $3.3 million and property dispositions of $180.8 million. For the same period in 2011, net capital expenditures were $617.1 million, consisting of $453.6 million spent on exploration and development activities, $183.5 million spent on acquisitions, including the purchase of two private oil and natural gas companies, property dispositions of $30.4 million and $10.4 million spent on head office expenditures. Net capital expenditures for the three months ended December 31, 2012 were $196.5 million, consisting of $76.9 million spent on exploration and development activities, $164.8 million spent on property acquisitions, head office expenditures of $704,000 and property dispositions of $45.9 million. For the same period in 2011, net capital expenditures were $139.1 million, consisting of $81.0 million spent on exploration and development activities, $70.7 million spent on property acquisitions including the purchase of a private oil and natural gas company, property dispositions of $12.9 million and head office expenditures of $211,000. Capital efficiencies remain our priority and we are encouraged by the opportunities identified to enhance these efficiencies throughout 2013 and beyond. 16 The following table outlines capital expenditures by category for the three months and years ended December 31: (thousands) Land acquisitions Geological and geophysical Drilling and completion Production equipment and facilities development and Exploration expenditures Cash used for acquisitions Cash received on dispositions Head office expenditures Net capital expenditures $ 2012 2,099 1,921 56,842 16,075 $ 76,937 164,757 (45,920) 704 $ 196,478 Three months ended December 31, $ 2011 3,906 2,007 55,754 19,368 $ 81,035 70,742 (12,884) 211 Years ended December 31, 2012 2011 $ $ 14,520 13,557 295,406 78,607 402,090 169,891 (180,848) 3,307 $ 34,900 13,390 274,440 130,820 $ 453,550 183,517 (30,357) 10,361 $ 139,104 $ 394,440 $ 617,071 Liquidity and capital resources - As at December 31, 2012, long-term debt including working capital (excluding associated assets and liabilities from financial instrument commodity contracts) was $963.5 million with debt to fourth quarter 2012 annualized funds from operations ratio of 2.2:1. Bonavista has 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, 2012, Bonavista had approximately $651.7 million of unused borrowing capacity on its $1.0 billion bank credit facility. On September 10, 2012, Bonavista amended and renewed its existing bank credit facility of $1.0 billion provided by a syndicate of 11 domestic and international banks to a maturity date of September 10, 2016, with no principal repayments required until then. The bank loan facility is a four year revolving facility and may at the request of Bonavista and the consent of the lenders, be extended on an annual basis beyond the existing term. In addition, the lenders may approve to increase the bank loan facility by $250 million on the participation of any existing or additional lenders. Under the terms of the amended and renewed bank credit facility, Bonavista has provided the covenants that its: (i) consolidated senior debt borrowing will not exceed three and one half times net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion, amortization and impairment for the four fiscal quarters from and including the fiscal quarter ending December 31, 2012 through to and including the fiscal quarter ending September 30, 2013; (ii) consolidated total debt will not exceed three and one half times of consolidated net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion, amortization and impairment; 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. The weighted average interest rate under the bank credit facility was 3.1% for the year ended December 31, 2012 (2011 - 3.4%). For 2013, Bonavista plans to invest approximately $425 million on its capital program within its core regions, which is comprised of an exploration and development program of $415 million and acquisitions, net of dispositions of $10 million. Bonavista intends on financing this capital program with a combination of funds from operations, its dividend reinvestment and stock dividend plans and to the extent required its existing bank credit facility. Going forward, Bonavista remains committed to the fundamental principle of maintaining financial flexibility and the prudent use of debt. Shareholders’ equity - As at December 31, 2012, Bonavista had 193.5 million equivalent common shares outstanding. This includes 14.1 million exchangeable shares, which are exchangeable into 15.9 million common shares. The exchange ratio in effect at December 31, 2012 for exchangeable shares was 1.13313:1. As at March 20, 2013, Bonavista had 195.3 million equivalent common shares outstanding. This includes 13.4 million exchangeable shares, which are exchangeable into 15.5 million common shares. The exchange ratio in effect at March 20, 2013 for exchangeable shares was 1.15469:1. In addition, Bonavista has 6.7 million stock option and common share incentive rights outstanding as at March 20, 2013, with an average exercise price of $21.67 per common share. Dividends - For the year ended December 31, 2012, Bonavista declared dividends of $224.8 million ($1.44 per share) compared to $200.0 million ($1.44 per share) in the same period in 2011. For the three months ended December 31, 2012, Bonavista declared dividends of $63.5 million ($0.36 per share) compared to $51.9 million ($0.36 per share) in the same period in 2011. 17 Bonavista announces its dividend policy on a quarterly basis and confirms its dividend payment on a monthly basis. Dividends are approved by the Board of Directors and are dependent upon the commodity price environment, production levels, and the amount of capital expenditures to be financed from funds from operations. As such, on January 9, 2013, Bonavista announced a reduction in the monthly dividend from $0.12 per share to $0.07 per share, beginning with the payment due February 15, 2013 to common shareholders of record on January 31, 2013. Although numerous initiatives had been employed throughout 2012 to preserve our prior dividend, the current forward commodity prices did not allow for these activities to continue under our growth plus dividend business model. The long-term goal of this business model remains intact with a commitment to generate an attractive return for our shareholders through a sustainable balance between dividends and corporate growth. Distributing between 25% and 35% of funds from operations will allow us to withhold sufficient funds to finance capital expenditures required to modestly grow our production base over the long-term, assuming current strip pricing is realized. Annual financial information - The following table highlights selected annual financial information for each of the three years ended December 31, 2012, 2011 and 2010: Years ended December 31, 2012 2011 2010 (thousands, except per share amounts) Consolidated Statement of Income and Comprehensive Income Information: Production revenues, net of royalties Funds from operations Per share – basic Per share – diluted Net income Per share – basic Per share – diluted Consolidated Statement of Financial Position Information: Net capital expenditures Total assets Working capital deficiency Long-term debt Shareholders’ equity Dividends declared $ 708,191 378,667 2.16 2.14 64,202 0.37 0.36 $ 882,672 553,303 3.44 3.42 137,184 0.85 0.85 $ 795,219 526,987 3.44 3.40 82,288 0.63 0.63 $ 394,440 4,062,852 (74,607) 889,071 2,285,889 224,801 $ 617,071 3,924,160 (51,110) 1,080,605 2,001,802 200,032 $ 569,995 3,444,555 (70,393) 951,443 1,841,422 252,298 Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly periods ending on March 31, 2011 to December 31, 2012: Production revenues Net income (loss) Basic Diluted December 31 September 30 June 30 223,021 14,442 0.07 0.07 188,610 2,484 0.01 0.01 193,826 3,553 0.02 0.02 March 31 227,034 43,723 0.26 0.26 December 31 September 30 June 30 285,167 (3,321) (0.02) (0.02) 264,349 31,166 0.19 0.19 256,100 77,318 0.49 0.49 March 31 238,798 32,021 0.20 0.20 2012 2011 Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and changes in production volumes. Net income in the past eight quarters has fluctuated from a deficit of $3.3 million in the fourth quarter of 2011 to a high of $77.3 million in the second quarter of 2011. These fluctuations are primarily influenced by production volumes, commodity prices, realized and unrealized gains and losses on financial instrument commodity contracts; gains and losses on foreign exchange; impairment charges and future income tax recoveries associated with the reduction in corporate income tax rates. 18 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 assessed reporting as defined by 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, 2012. There were no material changes to the internal controls over financial reporting during the three months ended December 31, 2012. the effectiveness of Bonavista’s internal control over financial Future accounting policies - Bonavista has reviewed the new and revised accounting standards issued by the International Accounting Standard Board (“IASB”) as at December 31, 2012, but not yet effective for financial statements for annual periods beginning on or after January 1, 2013. Each of these standards is to be adopted for fiscal years beginning January 1, 2013 with earlier adoption permitted, with the exception of IFRS 9, which has an effective date of January 1, 2015. IFRS 9 “Financial Instruments” - replaces the guidance in IAS 39 “Financial Instruments: Recognition and Measurement.” This standard eliminates the existing IAS 39 categories of held to maturity, available-for-sale and loans and receivables. IFRS 9 will require financial assets to be classified into two categories: amortized cost and fair value. The extent of the impact of the adoption of this standard has not yet been determined. IFRS 10 “Consolidated Financial Statements” supersedes IAS 27 “Consolidation and Separate Financial Statements” and SIC-12 “Consolidation - Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities. The adoption of IFRS 10 is not expected to impact Bonavista's financial statements. IFRS 11 “Joint Arrangements” are classified into two types, either joint operations or joint ventures, each with their own accounting treatment. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting. The adoption of IFRS 11 is not expected to have a material impact on Bonavista's financial statements. IFRS 12 “Disclosure of Interest in Other Entities” combines the disclosure requirements for entities that have interest in subsidiaries, joint arrangements, associates as well as unconsolidated structured entities. The adoption of IFRS 12 is not expected to have a material impact on Bonavista's financial statements. IFRS 13 “Fair Value Measurement” establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The adoption of IFRS 13 is not expected to have a material impact on Bonavista's financial statements. Critical accounting estimates - The consolidated financial statements have been prepared in accordance with IFRS. A summary of the significant accounting policies are presented in note 2 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 and probable oil and natural gas reserves - Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to interpretation and uncertainty. Bonavista expects that over time its reserve estimates will be revised either upward or downward depending upon the factors as stated above. These reserve estimates can have a significant impact on net income, as it is a key component in the calculation of depletion, depreciation and amortization, and also for the determination of potential asset impairments. b) Depreciation, depletion and amortization - Property, plant and equipment is measured at cost less accumulated depreciation, depletion and amortization. Bonavista’s oil and natural gas properties are depleted using the unit-of-production method over proved and probable reserves for each cash-generating unit (CGU). The unit-of-production method takes into account capital expenditures incurred to date along with future development capital required to develop both proved and probable reserves. 19 c) Impairment - Bonavista assesses its property, plant and equipment for impairment when events or circumstances indicate that the carrying value of its assets may not be recoverable. If any indication of impairment exists, Bonavista performs an impairment test on the CGU which is the lowest level at which there are identifiable cash flows. The determination of fair value at the CGU level again requires the use of judgements and estimates that include quantities of reserves and future production, future commodity pricing, development costs, operating costs and royalty obligations. Any changes in these items may have an impact on the fair value of the assets. d) Decommissioning liabilities - Bonavista estimates its decommissioning liabilities based upon existing laws, contracts or other policies. The estimated present value of our decommissioning obligations are recognized as a liability in the period in which they occur. The provision is calculated by discounting the expected future cash flows to settle the obligations at the risk-free interest rate. The liability is adjusted each reporting period to reflect the passage of time, with accretion charged to net income, any other changes whether it be changes in interest rates or changes in estimated future cash flows are capitalized to property, plant and equipment. 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. 20 Management’s Report The Consolidated Financial Statements of Bonavista Energy Corporation and related financial information were prepared by, and are the responsibility of Management. The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards. The Consolidated Financial Statements and related financial information reflect amounts which must of necessity be based upon informed estimates and judgments of Management with appropriate consideration to materiality. The Corporation has developed and maintains systems of controls, policies and procedures in order to provide reasonable assurance that assets are properly safeguarded, and that the financial records and systems are appropriately designed and maintained, and provide relevant, timely and reliable financial information to Management. KPMG LLP are the external auditors appointed by the shareholders, and they have conducted an independent examination of the corporate and accounting records in order to express an Auditors’ Opinion on these Consolidated Financial Statements. The Board of Directors has established an Audit Committee. The Audit Committee reviews with Management and the external auditors any significant financial reporting issues, the Consolidated Financial Statements, and any other matters of relevance to the parties. The Audit Committee meets quarterly to review and approve the condensed consolidated interim financial statements prior to their release, as well as annually to review the Corporation’s annual Consolidated Financial Statements and Management’s Discussion and Analysis and to recommend their approval to the Board of Directors. The external auditors have unrestricted access to the Corporation, the Audit Committee and the Board of Directors. Jason E. Skehar President and Chief Executive Officer Glenn A. Hamilton Senior Vice President and Chief Financial Officer March 20, 2013 Calgary, Alberta 21 INDEPENDENT AUDITORS’ REPORT To the Shareholders of Bonavista Energy Corporation: We have audited the accompanying consolidated financial statements of Bonavista Energy Corporation, which comprise the consolidated statements of financial position as at December 31, 2012 and December 31, 2011, the consolidated statements of income and comprehensive income, changes in equity 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 International Financial Reporting Standards, 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 Bonavista Energy Corporation as at December 31, 2012 and December 31, 2011, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards. Chartered Accountants Calgary, Canada March 20, 2013 22 BONAVISTA ENERGY CORPORATION Consolidated Statements of Financial Position (thousands) Assets: Current assets: Accounts receivable Prepaid expenses Marketable securities Other assets Financial instrument commodity contracts Financial instrument commodity contracts Financial instrument contracts Property, plant and equipment Exploration and evaluation assets Goodwill Liabilities and Shareholders’ Equity: Current liabilities: Accounts payable and accrued liabilities Dividends payable Financial instrument commodity contracts Financial instrument commodity contracts Long-term debt Other liabilities Decommissioning liabilities Deferred income taxes Shareholders’ equity: Shareholders’ capital Exchangeable shares Contributed surplus Deficit Commitments December 31, December 31, Notes 2012 2011 $ 102,500 $ 133,324 11,089 2,768 12,191 8,608 137,156 1,224 4,293 9,660 - 8,655 5,203 156,842 - 3,604 3,691,572 3,518,847 217,382 11,225 233,642 11,225 $ 4,062,852 $ 3,924,160 $ 181,674 $ 176,743 21,303 8,786 211,763 1,550 889,071 13,650 447,753 213,176 17,292 13,917 207,952 - 1,080,605 - 444,132 189,669 2,059,305 1,446,804 585,754 405,183 32,092 44,848 (62,848) (223,447) 585,754 32,092 (62,848) 2,001,802 2,285,889 2,001,802 $ 4,062,852 $ 3,924,160 (4) (4) (8) (9) (9) (4) (4) (12) (13) (14) (11) (15) See accompanying notes to the consolidated financial statements. Approved on behalf of the Board of Directors of Bonavista Energy Corporation: Ian S. Brown, Director Michael M. Kanovsky, Director 23 BONAVISTA ENERGY CORPORATION Consolidated Statements of Income and Comprehensive Income Years ended December 31, (thousands, except per share amounts) Revenues: Production Royalties Realized gains on financial instrument commodity contracts Unrealized gains (losses) on financial instrument commodity contracts Expenses: Operating Transportation General and administrative Transaction costs Goodwill impairment Share-based compensation Gain on disposition of property, plant and equipment Loss on disposition of exploration and evaluation assets Notes 2012 2011 $ 832,491 $ 1,044,414 (124,300) (161,742) (4) (4) (9) 708,191 882,672 8,581 8,210 7,766 (2,935) 16,791 4,831 724,982 887,503 229,847 229,072 38,367 26,967 960 - 19,450 (59,675) 5,938 40,581 24,146 - 20,096 17,282 (11,901) - Depletion, depreciation, amortization and impairment (8) 331,023 313,475 Income from operating activities Finance costs Finance income Net finance costs Income before taxes Deferred income taxes Net income and comprehensive income Net income per share – basic Net income per share – diluted See accompanying notes to the consolidated financial statements. 592,877 632,751 132,105 53,350 254,752 86,171 (11,739) (25,752) 41,611 60,419 90,494 26,292 194,333 57,149 $ 64,202 $ 137,184 $ $ 0.37 $ 0.85 0.36 $ 0.85 (6) (6) (14) (11) (11) 24 BONAVISTA ENERGY CORPORATION Consolidated Statements of Changes in Equity For the years ended December 31 (thousands) Shareholders’ capital Exchangeable shares Contributed surplus Total shareholders’ equity Deficit Balance as at December 31, 2011 $ 1,446,804 $ 585,754 $ 32,092 $ (62,848) $ 2,001,802 Net income Issuance of equity, net of issue costs Issued for cash on exercise of common share incentive rights Exercise of common share incentive rights Conversion of restricted share awards Share-based compensation expense Share-based compensation capitalized Issued pursuant to the dividend reinvestment and stock dividend plans Exchangeable shares exchanged for common shares Dividends declared - 334,736 4,510 4,609 5,183 - - 82,892 - - - - - - - - 180,571 (180,571) - - - - - (4,609) (5,183) 20,070 2,478 - - - 64,202 64,202 - - - - - - - - 334,736 4,510 - - 20,070 2,478 82,892 - (224,801) (224,801) Balance as at December 31, 2012 $ 2,059,305 $ 405,183 $ 44,848 $ (223,447) $ 2,285,889 (thousands) Shareholders’ capital Exchangeable shares Contributed surplus Total shareholders’ equity Deficit Balance as at December 31, 2010 $ 1,162,680 $ 650,668 $ 28,074 $ - $ 1,841,422 Net income Issuance of equity, net of issue costs Issued on business acquisition Issued for cash on exercise of common share incentive rights Exercise of common share incentive rights Conversion of restricted share awards Share-based compensation expense Share-based compensation capitalized Exchangeable shares exchanged for common shares Dividends declared - 193,597 939 12,521 7,794 4,359 - - - - - - - - - - 64,914 - (64,914) - - - - - (7,794) (4,359) 13,411 2,760 - - 137,184 137,184 - - - - - - - - 193,597 939 12,521 - - 13,411 2,760 - (200,032) (200,032) Balance as at December 31, 2011 $ 1,446,804 $ 585,754 $ 32,092 $ (62,848) $ 2,001,802 See accompanying notes to the consolidated financial statements. 25 BONAVISTA ENERGY CORPORATION Consolidated Statements of Cash Flows Years ended December 31, (thousands) Cash provided by (used in): Operating Activities: Net income Adjustments for: Notes 2012 2011 $ 64,202 $ 137,184 Depletion, depreciation, amortization and impairment (8) Share-based compensation Unrealized gains(losses) on financial instrument commodity contracts Gain on disposition of property, plant and equipment Loss on disposition of exploration and evaluation assets Goodwill impairment Net finance costs Deferred income taxes Decommissioning expenditures Changes in non-cash working capital items Financing Activities: Issuance of equity, net of issue costs Issuance of senior notes Proceeds on exercise of common share incentive rights Dividends paid Interest paid Proceeds from long-term debt Repayment of long-term debt Investing Activities: Business acquisition Exploration and development Property acquisitions Property dispositions Office equipment and leasehold improvements Changes in non-cash working capital items Change in cash Cash, beginning of year Cash, end of year See accompanying notes to the consolidated financial statements. (9) (7) 331,023 18,364 313,475 15,868 (8,210) 2,935 (59,675) (11,901) 5,938 - 41,611 26,292 (25,530) 13,466 - 20,096 60,419 57,149 (21,136) (6,923) 407,481 567,166 331,188 - 4,510 191,506 152,214 12,521 (137,898) (204,176) (40,907) - (41,182) 88,579 (182,329) (116,605) (25,436) 82,857 (10) (155,266) (172,944) (402,090) (453,550) (14,626) 180,848 (3,307) 12,396 (19,806) 30,357 (10,361) (23,719) (382,045) (650,023) (7) - - - $ $ - - - 26 BONAVISTA ENERGY CORPORATION Notes to the Consolidated Financial Statements For the year ended December 31, 2012 and 2011 Structure of the Corporation and Basis of Presentation: The principal undertakings of Bonavista Energy Corporation 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. Bonavista's principal place of business is located at 1500, 525 - 8th Avenue SW, Calgary, Alberta, Canada T2P 1G1. 1. Basis of presentation: a) Statement of compliance: The consolidated financial statements (the "financial statements") have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (IASB). A summary of Bonavista's significant accounting policies under IFRS are presented in note 2. The consolidated financial statements were authorized for issue by the Board of the Corporation on March 20, 2013. b) Basis of measurement: The consolidated financial statements have been prepared on the historical cost basis except for the following: i) derivative financial instruments are measured at fair value; and ii) liabilities for cash-settled share-based compensation are measured at fair market value. c) Functional and presentation currency: These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s functional currency. d) Use of estimates and management judgements: The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the period. Estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the consolidated financial statements. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as the Corporation’s operating environment changes. Estimates and underlying assumptions are reviewed on an ongoing basis by management. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. The key sources of estimation uncertainty to the carrying amounts of assets and liabilities are discussed below: i) Depletion, depreciation, amortization and impairment: Depletion, depreciation, amortization and impairment testing are based on an estimate of the Corporation’s total proved and probable reserves, production rates, oil and gas prices, future costs and future prices. Assumptions used to value proved and probable reserves may change significantly as new information becomes available to the Corporation’s independent reserve evaluator. Changes to forward price estimates, production costs or recovery rates may change the economic status of the reserves. Fluctuations in commodity prices may result in changes to forward prices estimates and impact the Corporation’s impairment testing. Impairment testing is also impacted by changes in the general economic environment which influence the discount rate used to present value the Corporation’s future cash flow estimates. Impairment is assessed at a cash-generating unit ("CGU") level, comparing the carrying amount of the asset to the recoverable amount. The determination of what constitutes the Corporation's assessed CGU's is subject to management judgement. ii) Decommissioning liability: The provision for decommissioning liabilities is based on estimates of costs and planned remediation projects. Actual costs may differ from those estimated due to changes in governing environment laws and regulations, technological changes, and market conditions. iii) Financial Instrument contracts: The estimated fair value of financial instrument commodity contracts are subject to changes in forward looking commodity prices, interest rate curves, volatility curves and counterparty non-performance risk. The estimated fair values of the Corporation’s financial instrument contracts are subject to changes in foreign exchange rates. 27 iv) Share-based compensation: Share-based compensation expense is based on an estimate of option and restricted share awards that will eventually vest. This performance multiplier is based on historical information of the Corporation’s plans. Share- based compensation recorded for the Corporation's stock option plans is based on an estimate of the fair value of options granted. The Corporation uses a Black-Scholes option pricing model to estimate the fair value of options. The Black-Scholes option model requires inputs, including, the risk-free rate, dividend yield and expected life which are subject to management judgment. 2. Significant accounting policies: The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements, and have been applied consistently by the Corporation and its subsidiaries. a) Basis of consolidation: The consolidated financial statements comprise the financial statements of the Corporation and its subsidiaries as at December 31, 2012. Subsidiaries are consolidated from the date of acquisition, being the date on which Corporation obtains control and continue to be consolidated until the date that control ceases. Control exists when the Corporation has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. All intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions are eliminated in full. Many of the Corporation's oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Corporation's share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. b) Foreign currency: Monetary assets and liabilities denominated in foreign currencies are translated to Canadian dollars at the period end exchange rate. Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are translated to the functional currency at the exchange rate at the date that the fair value was determined. Foreign currency differences arising on translation are recognized in profit or loss. c) Financial instruments: i) Non-derivative financial assets: The Corporation initially recognizes loans, receivables and deposits on the date that they are originated. All other financial assets (including assets designated at fair value through profit or loss) are recognized initially on the trade date at which the Corporation becomes a party to the contractual provisions of the instrument. The Corporation derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Corporation is recognized as a separate asset or liability. Financial assets and liabilities are offset and the net amount presented in the statement of consolidated financial position when, and only when, the Corporation has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously. The Corporation classifies non-derivative financial assets into the following categories: financial assets at fair value through profit or loss, held-to-maturity financial assets, loans and receivables and available-for-sale financial assets. Financial assets at fair value through profit or loss A financial asset is classified at fair value through profit or loss if it is classified as held for trading or is designated as such upon initial recognition. Financial assets are designated at fair value through profit or loss if the Corporation manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Corporation’s documented risk management or investment strategy. Attributable transaction costs are recognized in profit or loss as incurred. Financial assets at fair value through profit or loss are measured at fair value, and changes therein are recognized in the consolidated statement of income. Loans and receivables Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, loans and receivables are measured at amortized cost using the effective interest method, less any impairment losses. Loans and receivables comprise of cash and cash equivalents, and trade and other receivables. Cash and cash equivalents Cash and cash equivalents comprise cash balances and call deposits with original maturities of three months or less. 28 ii) Non-derivative financial liabilities: The Corporation initially recognizes debt securities issued and subordinated liabilities on the date that they are originated. All other financial liabilities (including liabilities designated at fair value through profit or loss) are recognized initially on the trade date at which the Corporation becomes a party to the contractual provisions of the instrument. The Corporation derecognizes a financial liability when its contractual obligations are discharged or cancelled or expired. Financial assets and liabilities are offset and the net amount presented in the consolidated statement of financial position when, and only when, the Corporation has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously. The Corporation classifies non-derivative financial liabilities into the other financial liabilities category. Such financial liabilities are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, these financial liabilities are measured at amortized cost using the effective interest method. Other financial liabilities comprise loans and borrowings, bank overdrafts, and trade and other payables. Bank overdrafts that are repayable on demand and form an integral part of the Corporation’s cash management are included as a component of cash and cash equivalents for the purpose of the statement of cash flows. iii) Derivative financial instruments: The Corporation has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices and foreign exchange rates. These instruments are not used for trading or speculative purposes. The Corporation has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Corporation considers all commodity contracts and foreign exchange contracts to be economic hedges. Derivatives are recognized initially at fair value and any attributable transaction costs are recognized in profit or loss when incurred. Subsequent to initial recognition, derivatives are measured at fair value, and changes therein are recognized immediately in profit or loss. The Corporation has accounted for its forward 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. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the balance sheet. Settlements on these physical sales contracts are recognized in oil and natural gas revenues. Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are recognized immediately in the consolidated statement of income. Financial assets designated at fair value through profit or loss are comprised of interest rate swaps and forward exchange contracts. iv) Shareholders’ capital and Exchangeable shares: Common shares and exchangeable shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects. d) Exploration and evaluation assets and property, plant and equipment: i) Recognition and measurement: Pre-licence costs are recognized in the consolidated statement of income as incurred. Exploration and evaluation expenditures: Exploration and evaluation (“E&E”) costs, including the costs of acquiring licences and directly attributable general and administrative costs, initially are capitalized as either tangible or intangible E&E assets according to the nature of the assets acquired. The costs are accumulated in cost centres by well, field or exploration area pending determination of technical feasibility and commercial viability. E&E assets are assessed for impairment if: (a) sufficient data exists to determine technical feasibility and commercial viability; and (b) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when total proved plus probable reserves are determined to exist. A review of each exploration licence or field is carried out, at least annually, to ascertain whether proved plus probable reserves have been discovered. Upon determination of total proved plus probable reserves, intangible E&E assets attributable to those reserves are transferred from E&E assets to a separate category within tangible assets referred to as oil and natural gas properties. 29 Development and production costs: Items of property, plant and equipment, which include oil and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into cash generating units for impairment testing. Gains and losses on dispositions of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized net within “gains (losses) on disposition of property, plant and equipment” in the consolidated statement of income. ii) Subsequent costs: Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved or proved plus probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in the consolidated statement of income as incurred. iii) Depletion, depreciation and amortization: The net carrying amount of development or production assets is depleted using the unit-of-production method by reference to the ratio of production in the year to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of oil, natural gas and natural gas liquids, which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50% statistical probability that it will be less. The equivalent statistical probabilities for the proven component of proved and probable reserves are 90% and 10%, respectively. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon: a reasonable assessment of the future economics of such production; a reasonable expectation that there is a market for all or substantially all the expected oil and natural gas production; and evidence that the necessary production, transmission and transportation facilities are available or can be made available. Reserves may only be considered total proved plus probable if producibility is supported by either actual production or conclusive formation test. The area of reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of oil and natural gas controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are only included in the proved and probable classification when successful testing by a pilot project, the operation of an installed program in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or program was based. 30 The estimated useful lives for certain production assets for the current and comparative years are as follows: Facilities Oil and natural gas properties 15 years Based on CGU Reserve Life For other assets, depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of each part of an item of property, plant and equipment. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Corporation will obtain ownership by the end of the lease term. The estimated useful lives for other assets for the current and comparative years are as follows: Office equipment Fixtures and fittings Leaseholds 5 years 5 years 9.5 years Depreciation methods, useful lives and residual values are reviewed at each reporting date. e) Goodwill and Exploration and evaluation assets: i) Goodwill: Goodwill arises on the acquisition of businesses, subsidiaries, associates and joint ventures. Goodwill is measured at cost less accumulated impairment losses. Goodwill is evaluated for impairment on an annual basis, or more frequently if potential indicators of impairment exist. ii) Exploration and evaluation assets: Other intangible assets that are acquired by the Corporation, which have finite useful lives, are measured at cost less accumulated amortization and accumulated impairment losses. Subsequent expenditure is capitalized only when it increases the future economic benefits embodied in the specific asset to which it relates. Amortization is recognized in profit or loss on a straight-line basis over the estimated useful lives of other intangible assets, other than goodwill, from the date they were available for use. f) Impairment: i) Non-derivative financial assets: A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in the consolidated statement of income. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in the consolidated statement of income. ii) Non-financial assets: The carrying amounts of the Corporation’s non-financial assets, other than E&E assets and deferred income tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives or that are not yet available for use an impairment test is completed each year. E&E assets are assessed for impairment when they are reclassified to property, plant and equipment, as oil and natural gas interests, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets, the CGU. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. 31 In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. The goodwill acquired in a business combination, for the purpose of impairment testing, is allocated to the CGUs that are expected to benefit from the synergies of the combination. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit (group of units) on a pro rata basis. An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized. g) Employee benefits: i) Share-based compensation: Long-term incentives are granted to officers, directors, employees and certain consultants in accordance with the Corporation’s stock option and restricted share award plans. The fair value of stock options is assessed on the grant date using the Black-Scholes option pricing model. The fair value is subsequently recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus. Upon exercise of the options, consideration paid by the stock option holders and the value in contributed surplus pertaining to the exercised options are recorded as shareholders’ capital. The fair value of restricted share awards is assessed on the grant date factoring in the weighted average trading price of the five days preceding the grant date and forecasted dividends. This fair value is recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus. Upon the forced vest of the restricted share awards into common shares on the predetermined dates, the value in contributed surplus pertaining to the share awards is recorded as shareholders’ capital. Under both incentive plans, forfeiture rates are assigned in the determination of fair value. Upon vesting, the difference between estimated and actual forfeitures is adjusted through share-based compensation. ii) Short-term employee benefits: Short-term employee benefit obligations are expensed as the related service is provided. A liability is recognized for the amount expected to be paid under short-term cash bonus or profit-sharing plans if the Corporation has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the obligation can be estimated reliably. h) Lease payments: Payments made under operating leases are recognized in profit and loss on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease. i) Provisions: A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses. j) Decommissioning liabilities: The Corporation’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category. Decommissioning liabilities are measured at the present value of management’s best estimate of expenditure required to settle the present obligation at the balance sheet date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established. 32 k) Revenues: Revenues from the sale of oil and natural gas are recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. This is generally at the time product enters the pipeline. Revenues are measured net of discounts, customs, duties and royalties. With respect to the latter, the entity is acting as a collection agent on behalf of others. Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements. l) Finance income and costs: Finance costs comprise of interest expense on borrowings, unwinding of the discount on provisions and impairment losses recognized on financial assets, fair value losses on financial assets at fair value through profit and loss. Interest income is recognized as it accrues in profit or loss, using the effective interest method. Foreign currency gains and losses, are reported under finance income or expenses. m) Income taxes: Income tax expense comprises current and deferred income taxes. Current and deferred income taxes are recognized in the consolidated statement of income except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income. Current tax is the expected tax payable or receivable on the taxable income or loss for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred income taxes are recognized in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred income taxes are not recognized for: temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss; and temporary differences related to investments in subsidiaries to the extent that it is probable that they will not reverse in the foreseeable future; and taxable temporary differences arising on the initial recognition of goodwill. Deferred income taxes are measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously. A deferred income tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred income tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. n) Net income per share: Basic net income per share is calculated by dividing the profit or loss attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees. 3. New accounting standards: Bonavista has reviewed the new and revised accounting standards issued by the International Accounting Standard Board (“IASB”) as at December 31, 2012, but not yet effective for financial statements for annual periods beginning on or after January 1, 2013. The first standard, IFRS 9 "Financial Instruments" is to be adopted for fiscal years beginning January 1, 2015 with the remaining standards to be adopted for fiscal years beginning January 1, 2013 with earlier adoption permitted. IFRS 9 “Financial Instruments” - replaces the guidance in IAS 39 “Financial Instruments: Recognition and Measurement.” This standard eliminates the existing IAS 39 categories of held to maturity, available-for-sale and loans and receivables. IFRS 9 will require financial assets to be classified into two categories: amortized cost and fair value. The extent of the impact of the adoption of this standard has not yet been determined. IFRS 10 “Consolidated Financial Statements” supersedes IAS 27 “Consolidation and Separate Financial Statements” and SIC-12 “Consolidation - Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities. The adoption of IFRS 10 is not expected to impact Bonavista's financial statements. 33 IFRS 11 “Joint Arrangements” are classified into two types, either joint operations or joint ventures, each with their own accounting treatment. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting. The adoption of IFRS 11 is not expected to have a material impact on Bonavista's financial statements. IFRS 12 “Disclosure of Interest in Other Entities” combines the disclosure requirements for entities that have interest in subsidiaries, joint arrangements, associates as well as unconsolidated structured entities. The adoption of IFRS 12 is not expected to have a material impact on Bonavista's financial statements. IFRS 13 “Fair Value Measurement” establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The adoption of IFRS 13 is not expected to have a material impact on Bonavista's financial statements. 4. Financial risk management: 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 Corporation’s 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 purchasers 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, 2012 Bonavista’s receivables consisted of $63.6 million of receivables from oil and natural gas marketers which has substantially been collected subsequent to December 31, 2012 and $29.3 million from joint venture partners of which $12.4 million has been subsequently collected. As at December 31, 2012 Bonavista has $12.3 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, 2012 and did not provide for any doubtful accounts during the year ended December 31, 2012. 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, dividends payable, financial instruments contracts, bank debt, and senior unsecured notes. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities, and capital expenditures. Bonavista processes invoices within a normal payment period. Accounts payable and accrued liabilities have contractual maturities of less than one year. Dividends payable are declared on a monthly basis and are dependent upon a number of factors including current and future commodity prices, foreign exchange rates, our commodity hedging program, current operations and future investment opportunities. Financial instrument contracts have contractual maturities of less than three years on all commodity contracts and range from four to ten years on foreign exchange hedge contracts. Bonavista’s four year revolving credit facility, as outlined in note 12, may at the request of the Corporation with the consent of the lenders, be extended on an annual basis beyond the existing term. The Corporation also has a series of senior unsecured notes outstanding, as outlined in note 12, 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. 34 Bonavista mitigates a portion of the commodity price risk through the use of various financial instrument commodity 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 the current year's total budgeted revenue, net of royalties, provided that no more than 80% of forecasted revenues from any one product may be hedged, or in the case of electricity, 60% of Bonavista's net consumption. The term of any commodity hedge executed will be limited to no more than three calendar years subsequent to the current calendar year in which an executed hedge is made. Financial instrument commodity contracts: As at December 31, 2012, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume Average Price Term 35,000 gjs/d 40,000 gjs/d 45,000 gjs/d 5,000 gjs/d 10,000 gjs/d 10,000 gjs/d 500 bbls/d 7,500 bbls/d 1,500 bbls/d CDN $2.87 - CDN $3.44 - AECO CDN $2.93 - CDN $3.73 - AECO CDN $2.75 - CDN $3.27 - AECO CDN $3.50 - CDN $4.00 - AECO CDN $3.25 - CDN $4.14 - AECO CDN $2.85 - CDN $3.50 - AECO CDN $95.00 - CDN $115.00 - WTI CDN $87.00 - CDN $102.35 - WTI CDN $83.33 - CDN $99.25 - WTI January 1, 2013 - December 31, 2013 January 1, 2013 - December 31, 2014 April 1, 2013 - October 31, 2013 November 1, 2013 - March 31, 2014 January 1, 2014 - December 31, 2014 April 1, 2014 - October 31, 2014 January 1, 2013 - June 30, 2013 January 1, 2013 - December 31, 2013 January 1, 2014 - December 31, 2014 Subsequent to December 31, 2012, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume Average Price Term 10,000 1,500 1,500 500 gjs/d bbls/d bbls/d bbls/d CDN $3.38 - CDN $3.92 - AECO CDN $88.17 - CDN $100.05 - WTI CDN $85.83 - CDN $99.57 - WTI CDN $87.50 - CDN $97.50 - WTI January 1, 2014 - December 31, 2015 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 January 1, 2015 - December 31, 2015 As at December 31, 2012, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume Price Contract Term 10,000 35,000 1,000 gjs/d CDN $2.51 gjs/d CDN $2.84 bbls/d CDN $87.35 Swap - AECO Swap - AECO Swap - WTI January 1, 2013 - June 30, 2013 January 1, 2013 - December 31, 2013 January 1, 2013 - December 31, 2013 Subsequent to December 31, 2012, Bonavista entered into the following contract to manage its overall commodity exposure: Volume Price Contract Term 15,000 5,000 gjs/d CDN $3.43 gjs/d CDN $3.55 Swap - AECO Swap - AECO January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 Financial instrument commodity contracts are recorded on the consolidated statement of financial position 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 income and comprehensive income. A $0.10 change in the price per thousand cubic feet of natural gas – AECO would have an impact of approximately $3.5 million on net in place as at December 31, 2012 (2011 - $2.5 million). A $1.00 change in the price per barrel of oil – WTI would have an impact of approximately $1.6 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2012 (2011 - $1.8 million). instrument commodity contracts that were financial income those for 35 d) Foreign exchange risk: Commodity prices are largely denominated in US dollars and as a result the prices that Canadian producers receive is determined by the relationship between the US and Canadian dollar. In addition, Bonavista also has US denominated debt and interest obligations of which future cash payments are directly impacted by the exchange rate in effect on the due date. On July 21, 2011, Bonavista entered into an agreement with three financial intermediaries to purchase the following US dollars that coincide with Bonavista’s note repayment commitments: Forward date November 2, 2017 November 2, 2020 November 2, 2022 Contract US$ purchased forward US$ purchased forward US$ purchased forward Notional US$ $30,000,000 $53,300,000 $16,500,000 CDN$/US$ 0.995 0.995 0.995 A $0.01 change in CDN$/US$ exchange rate would have an impact of approximately $655,000 on net income for those foreign exchange forward contracts in place as at December 31, 2012 (2011 - $619,000). 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 1% it is estimated that Bonavista’s net income for the year ended December 31, 2012 would decrease by $3.6 million (2011 - $4.6 million). Fair value of financial instruments: The fair value of the financial instruments carried on Bonavista’s consolidated statement of financial position is classified according to the following hierarchy based on the amount of observable inputs used to value the financial 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 have been classified as Level 1, financial instrument contracts, bank debt and senior unsecured notes are classified as Level 2. The fair market value recorded on the consolidated statements of financial position for these financial instrument contracts were as follows: (thousands) Current asset: Marketable securities(1) Financial instrument commodity contract(2) Long-term asset: Financial instrument commodity contract(2) Financial instrument contract(2) Current liabilities: Financial instrument commodity contract(2) Long-term liability: Financial instrument commodity contract(2) Net asset/(liability) (1) (2) Level 1 Level 2 December 31, December 31, 2012 2011 $ 2,768 8,608 $ - 5,203 1,224 4,293 - 3,604 (8,786) (13,917) (1,550) - $ 6,557 $ (5,110) 36 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, 2012 is approximately $579.8 million (2011 - $573.9 million), compared to a carrying amount of $547.5 million (2011 - $558.5 million). 5. 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 assets and liabilities from financial instrument contracts), 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, senior unsecured notes and 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, 2012, Bonavista’s ratio of net debt to fourth quarter annualized funds from operations was 2.2 to 1 (2011 - 1.9 to 1), which is slightly above the range established by the Corporation. The following table reconciles funds from operations to its nearest measured prescribed by IFRS, cash flow from operating activities. Calculation of Funds From Operations: (thousands) Cash flow from operating activities Interest expense Decommissioning expenditures Changes in non-cash working capital Funds from operations Fourth quarter annualized Three months ended December 31, 2012 2011 $ 102,886 (9,487) 11,410 5,206 $ 145,150 (8,454) 5,973 8,174 $ 110,015 $ 150,843 $ 440,060 $ 603,372 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 differentials, 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 shareholders' 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 12 of the consolidated financial statements. 37 6. Finance costs and income: a) Finance costs: Finance costs: Interest on bank debt Interest on notes payable Accretion of decommissioning liabilities Unrealized loss on marketable securities Foreign exchange loss Unrealized loss on financial instrument contracts Finance costs b) Finance income: Finance income: Unrealized gain on financial instrument contracts Foreign exchange gain Finance income Years ended December 31, 2011 2012 $ 19,278 $ 23,445 9,895 26,629 18,098 12,206 732 - - - 26,110 3,128 $ 53,350 $ 86,171 Years ended December 31, 2011 2012 $ (689) $ (6,732) (11,050) (19,020) $ (11,739) $ (25,752) The Corporation’s effective interest rate for the period ending December 31, 2012 was approximately 4.1% (2011 - 3.0%). 7. Supplemented cash flow information: Changes in non-cash working capital is comprised of: Source/(use) of cash Accounts receivable Prepaid expenses Marketable securities Other assets Accounts payable and accrued liabilities, net of interest accrual Related to: Operating activities Investing activities Years ended December 31, 2011 2012 $ 30,824 $ (5,714) (1,429) (3,500) (3,536) 500 - 1,413 3,503 (26,841) $ 25,862 $ (30,642) $ 13,466 $ (6,923) 12,396 (23,719) $ 25,862 $ (30,642) 38 8. Property, plant and equipment: Cost: Oil and natural gas properties Facilities Other assets Total Balance as at December 31, 2010 $ 2,880,897 $ 425,931 $ 4,707 $ 3,311,535 Additions Acquisitions Transfers from exploration and evaluation Changes in decommissioning liabilities Disposals 392,153 188,714 25,843 131,184 (30,344) 29,258 47,700 - - (8,757) 10,361 - - - - 431,772 236,414 25,843 131,184 (39,101) Balance as at December 31, 2011 $ 3,588,447 $ 494,132 $ 15,068 $ 4,097,647 Additions Acquisitions Transfer from exploration and evaluation Changes in decommissioning liabilities 380,105 148,574 25,076 19,256 9,943 32,767 - - Dispositions (129,831) (24,561) 3,307 - - - - 393,355 181,341 25,076 19,256 (154,392) Balance as at December 31, 2012 $ 4,031,627 $ 512,281 $ 18,375 $ 4,562,283 Depletion, depreciation and amortization: Balance as at December 31, 2010 Depletion, depreciation, amortization and impairment Disposals Balance as at December 31, 2011 Depletion, depreciation, amortization and impairment Dispositions $ (246,426) $ (20,945) $ (941) $ (268,312) (288,489) 2,488 (22,741) 499 (2,245) (313,475) - 2,987 $ (532,427) $ (43,187) $ (3,186) $ (578,800) (304,746) 35,301 amortization (23,703) (2,574) 3,811 - (331,023) 39,112 Balance as at December 31, 2012 $ (801,872) $ (63,079) $ (5,760) $ (870,711) Net book value as at December 31, 2012 $ 3,229,755 $ 449,202 $ 12,615 $ 3,691,572 Net book value as at December 31, 2011 $ 3,056,020 $ 450,945 $ 11,882 $ 3,518,847 For the year ended December 31, 2012, Bonavista capitalized $7.3 million (2011 - $7.9 million) of direct general and administrative expenses. For the year ended December 31, 2012, Bonavista recorded an impairment charge of nil (2011 - $16.0 million). The impairment charge in 2011 was recorded in two natural gas weighted CGU's. The benchmark reference pricing as prepared by GLJ Petroleum Consultants and adjusted for commodity differentials specific to Bonavista are as follows: Year 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Remainder (1) (1) WTI Oil (US$/bbl) 90.00 92.50 95.00 97.50 97.50 97.50 98.54 100.51 102.52 104.57 2.0% AECO Gas (Cdn$/mmbtu) 3.38 3.83 4.28 4.72 4.95 5.22 5.32 5.43 5.54 5.64 2.0% Cdn$/US$ Exchange Rates 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 39 Percentage change represents the change in each year after 2022 to the end of the reserve life. The recoverable amount was estimated based on discounted cash flows using proved plus probable reserves and discounted using a pre-tax discount rate of 10% (2011 - 10%). If an 8% pre-tax discount rate was used in estimating discounted cash flows, Bonavista would have recorded an impairment charge of nil (2011 - nil). If a 12% pre-tax discount rate was used in estimated discounted cash flows, Bonavista would have recorded an impairment charge of approximately $25.0 million (2011 - $18.1 million). 9. Goodwill and Exploration and evaluation assets : Exploration and evaluation assets Goodwill (thousands) Balance as at December 31, 2010 $ 31,321 $ 219,590 Additions Acquisitions Dispositions Transfers to property, plant and equipment Impairment - - - - (20,096) 34,900 7,499 (2,504) (25,843) - Balance as at December 31, 2011 $ 11,225 $ 233,642 Additions Acquisitions Dispositions Transfers to property, plant and equipment - - - - 14,520 6,127 (11,831) (25,076) Balance as at December 31, 2012 $ 11,225 $ 217,382 Exploration and evaluation assets consist of the Corporation’s exploration projects which are pending the determination of proved or probable reserves. Additions represent the Corporation’s share of costs incurred on E&E assets during the year. For the year ended December 31, 2012, Bonavista recorded a goodwill impairment charge of nil (2011 - $20.1 million). The goodwill impairment charge in 2011 was recorded in two natural gas weighted CGU's. The recoverable amount was estimated based on discounted cash flows using proved plus probable reserves and discounted using a pre-tax discount rate of 10% (2011 - 10%). If an 8% pre-tax discount rate was used in estimating discounted cash flows, Bonavista would have recorded a goodwill impairment charge of nil (2011 - $14.0 million). If a 12% pre-tax discount rate was used in estimating discounted cash flows, Bonavista would have recorded a goodwill impairment charge of nil (2011 - $20.1 million). 10. Acquisitions: a) On October 1, 2012, Bonavista completed the acquisition of certain natural gas weighted properties located within its deep basin core area in west central Alberta. The assets were acquired for a cash consideration of $155.3 million. The amounts recognized on the date of acquisition to identifiable net assets were as follows: (thousands) Net assets acquired: Exploration and evaluation assets Facilities Oil and natural gas properties Other deferred liabilities Decommissioning liabilities Net assets acquired (thousands) Purchase consideration: Cash Total purchase consideration $ Amount 6,091 30,173 151,151 (16,813) (15,336) $ 155,266 $ $ 155,266 155,266 40 In the period from October 1, 2012 to December 31, 2012 the acquisition contributed revenues of $13.0 million and net income of $6.4 million which are the year ended December 31, 2012. If the acquisition had occurred on January 1, 2012, management estimates that the acquisition would have contributed $50.3 million to revenues and $24.0 million to net income for the year ended December 31, 2012. In conjunction with the transaction, Bonavista has expensed $231,000 of applicable transaction costs. the consolidated statement of included income for in b) On August 10, 2011, Bonavista acquired all of the issued and outstanding shares of a private oil and natural gas company in consideration for cash and common shares. In connection with the acquisition, Bonavista also received approximately $54.0 million of income tax attributes. The amounts recognized on the date of acquisition to identifiable net assets were as follows: (thousands) Net assets acquired: Oil and natural gas properties Working capital Decommissioning liabilities Deferred income taxes Net assets acquired (thousands) Purchase consideration: Cash Common shares Total purchase consideration Amount $ 111,562 9,398 (2,125) (13,865) $ 104,970 $ 104,031 939 $ 104,970 In the period from August 10, 2011 to December 31, 2011 the acquisition contributed revenues of $14.9 million and net income of $8.0 million which are the year ended December 31, 2011. If the acquisition had occurred on January 1, 2011, management estimates that the acquisition would have contributed $39.3 million to revenues and $21.0 million to net income for the year ended December 31, 2011. the consolidated statement of included income for in c) On October 3, 2011, Bonavista acquired all the issued and outstanding shares of a private oil and natural gas company in consideration for cash. In connection with the acquisition, Bonavista also received approximately $38.9 million of income tax attributes. The amounts recognized on the date of acquisition to identifiable net assets were as follows: (thousands) Net assets acquired: Oil and natural gas properties Working capital Decommissioning liabilities Deferred income taxes Net assets acquired (thousands) Purchase consideration: Cash Total purchase consideration Amount $ 92,384 (9,587) (657) (13,227) $ 68,913 $ $ 68,913 68,913 In the period from October 3, 2011 to December 31, 2011 the acquisition contributed revenues of $3.7 million and net income of $2.1 million which are the year ended December 31, 2011. If the acquisition had occurred on January 1, 2011, management estimates that the acquisition would have contributed $18.0 million to revenues and $10.3 million to net income for the year ended December 31, 2011. the consolidated statement of included income for in d) On January 9, 2013, Bonavista completed the acquisition of 2,450 boe per day of low decline production situated on a highly synergistic land base within its deep basin core area in west central Alberta for a cash purchase price of approximately $72.5 million. 41 11. Shareholders' capital: The Corporation is authorized to issue an unlimited number of common shares without nominal or par value, an unlimited number of exchangeable shares without nominal or par value and 10,000,000 preferred shares, issuable in series. The holders of common shares are entitled to receive dividends as declared by the Corporation and are entitled to one vote per share. Dividends declared for the year ended December 31, 2012 were $1.44 per share (2011 - $1.44 per share). Bonavista announced that it had adopted a dividend reinvestment plan ("DRIP") and stock dividend plan (“SDP”) on December 31, 2011 and May 3, 2012 respectively. The DRIP and SDP provide eligible holders of common shares the option to reinvest cash dividends into common shares issued either from treasury at a five per cent discount to the prevailing average market price or acquired through the facilities of the Toronto Stock Exchange at prevailing market rates with no discount. Under the DRIP, a cash dividend is paid to the common shareholder and then immediately reinvested in new common shares. Under the SDP program, dividends are paid directly in common shares to electing participants. The implementation of the DRIP began in January 2012 and the implementation of the SDP began in June 2012. 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. The holders of exchangeable shares are entitled to one vote times the exchange ratio for each exchangeable share. a) Issued and outstanding: i) Common shares: (thousands) Balance as at December 31, 2010 Issued for cash Issued on business acquisition Issued on conversion of exchangeable shares Issued upon exercise of common shares incentive rights Share-based compensation Issue costs, net of future tax benefit Conversion of restricted share awards Balance as at December 31, 2011 Issued for cash Issued on conversion of exchangeable shares Issued pursuant to the dividend reinvestment and stock dividend plans Issued upon exercise of common shares incentive rights Share-based compensation Issue costs, net of future tax benefit Conversion of restricted share awards Number of Shares 133,975 7,000 32 2,288 725 - - 78 144,098 20,930 6,953 5,034 372 - - 135 Amount $ 1,162,680 199,850 939 64,914 12,521 12,153 (6,253) - $ 1,446,804 345,345 180,571 82,892 4,510 9,792 (10,609) - Balance as at December 31, 2012 177,522 $ 2,059,305 ii) Exchangeable shares: (thousands) Balance, beginning of year Exchanged for common shares Balance, end of year Exchange ratio, end of year Years ended December 31, 2012 2011 Number Amount Number Amount 20,339 (6,270) $ 585,754 (180,571) 22,593 (2,254) $ 650,668 (64,914) 14,069 $ 405,183 20,339 $ 585,754 1.13313 - 1.04906 - Common shares issuable on exchange 15,942 $ 405,183 21,337 $ 585,754 42 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. b) Share-based compensation: Bonavista has option and restricted share award programs that entitle officers, directors, employees and certain consultants to purchase and receive shares in the Corporation. The number of common shares awarded under all long- term incentive plans shall be limited to 8% of the aggregate number of issued and outstanding equivalent shares of the Corporation. i) Stock option and common share incentive rights plans: Upon conversion to a corporation, 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. The exercise price per common share is calculated by deducting from the grant price the aggregate of all dividends on a per common share basis made by the Corporation after the grant date. All new rights granted after December 31, 2010 are granted under the stock option plan. The incentive rights granted under the stock option plan vest evenly 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. Bonavista estimates the fair value of granted options using a Black-Scholes option pricing model. The following assumptions were used to arrive at the estimated fair value during each respective period: Weighted average for the period Dividend yield Volatility Risk-free interest rate Forfeiture rate (1) Expected life December 31, 2012 December 31, 2011 7.90% 39.82% 1.28% 8.14% 5.0 7.92% 36.94% 1.64% 7.92% 5.0 (1) The estimated forfeiture rate is adjusted for actual forfeitures throughout the vesting period. The following table summarizes the stock option and common share incentive rights outstanding and exercisable under the plans at December 31, 2012: Balance as at December 31, 2010 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2011 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2012 Exercisable as at December 31, 2012 Number of Stock Options/Common Share Incentive Rights 3,956,728 2,456,616 (725,197) (392,669) - 5,295,478 2,762,385 (371,678) (1,280,949) - 6,405,236 1,882,647 Weighted Average Exercise Price $ 20.28 27.53 (17.25) (25.81) (1.02) $ 22.65 18.62 (12.13) (23.45) (0.66) 20.75 20.97 $ $ 43 As at December 31, 2012 there are 4.4 million stock options outstanding (2011 - 2.3 million) of which 654,376 are exercisable (2011 - nil) and 2.0 million common share incentive rights outstanding (2011 - 3.0 million) with 1.2 million exercisable (2011 - 1.2 million). The range of exercise prices of the outstanding stock option and common share incentive rights plans is as follows: Stock Options/Common Share Incentive Rights Outstanding Weighted average remaining contractual life (years) Weighted average exercise price Number outstanding Stock Options/Common Share Incentive Rights Exercisable Number exercisable Weighted average exercise price Range of exercise prices $ 9.43 – 16.13 16.14 – 25.80 25.81 – 35.99 2,133,881 2,253,715 2,017,640 $ 9.43 – 35.99 6,405,236 3.6 2.9 3.2 3.2 $ 13.84 21.09 27.70 $ 20.75 440,955 810,937 630,755 $ 10.11 21.16 28.31 1,882,647 $ 20.97 ii) Restricted share award incentive plan and restricted common share incentive plan: Upon the Trust’s conversion to a corporation, the Restricted Share Award Incentive Plan was established and the restricted common share incentive plan (formerly the restricted 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 vested or been cancelled. All new rights granted after December 31, 2010 are granted under the Restricted Share Award Incentive Plan. Vesting arrangements are within the discretion of Bonavista’s Board of Directors, but all awards vest evenly over a period of 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 the statutory withholding tax. The fair value of restricted share awards is assessed on the grant date factoring in the weighted average trading price of the five days preceding the grant date and forecasted dividends. This fair value is recognized as share- based compensation expense over the vesting period with a corresponding increase to contributed surplus. Upon the forced vest of these awards, the fair value is moved from contributed surplus into shareholders’ capital. The following table summarizes the restricted share award incentive and restricted common share incentive plans outstanding at December 31, 2012: Balance as at December 31, 2010 Granted Exercised Forfeited Balance as at December 31, 2011 Granted Exercised Forfeited Balance as at December 31, 2012 248,552 414,714 (135,578) (40,204) 487,484 1,480,706 (178,432) (151,538) 1,638,220 As at December 31, 2012, there were 1.6 million restricted share awards (2011 - 388,532) and 41,593 restricted common share rights (2011 - 98,952) outstanding. As at December 31, 2012, the balance of contributed surplus attributable to the share-based compensation awards was $44.8 million (2011 - $32.1 million). Share-based compensation expense recognized the year ended December 31, 2012 was $19.5 million (2011 - $17.3 million). in 44 c) Per share amounts: The following table summarizes the weighted average common shares and exchangeable shares used in calculating net income per equivalent share: (thousands) Common shares Exchangeable shares converted at the exchange ratio Basic equivalent shares Stock option and common share incentive rights Restricted share awards and restricted common share rights Diluted equivalent shares 12. Long-term debt: (thousands) Bank credit facility Senior unsecured notes Balance, end of year a) Bank credit facility: Years ended December 31, 2011 2012 154,551 138,476 21,030 22,236 175,581 160,712 223 943 716 359 176,747 161,787 December 31, 2012 December 31, 2011 $ 344,195 544,876 $ 889,071 $ 524,963 555,642 $ 1,080,605 Bonavista has a $1 billion unsecured, covenant-based bank credit facility provided by a syndicate of 11 domestic and international banks. During the third quarter of 2012 Bonavista amended and renewed its facility for a four year term, maturing September 10, 2016. Bonavista also has in place a $50 million demand working capital facility, which is subject to the same covenants as the credit facility. The credit 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. The credit facility is a four year revolving credit and may, at the request of Corporation with the consent of the lenders, be extended on an annual basis beyond the existing term. There is an accordion feature providing that at any time during the term, on participation of any existing or additional lenders, the Corporation can increase the facility by $250 million. Under the terms of the amended and renewed bank credit facility, Bonavista has provided the covenants that its: (i) consolidated senior debt borrowing will not exceed three and one half times net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion, amortization and impairment for the four fiscal quarters from and including the fiscal quarter ending December 31, 2012 through to and including the fiscal quarter ending September 30, 2013; (ii) consolidated total debt will not exceed three and one half times of consolidated net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion, amortization and impairment; 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. The weighted average interest rate under the bank credit facility was 3.1% for the year ended December 31, 2012 (2011 - 3.4%). 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. 45 c) Senior unsecured notes not subject to the master shelf agreement: On November 2, 2010 and October 25, 2011, 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 October 25, 2011 Principal CDN $50.0 million US $90.0 million US $160.0 million US $50.0 million US $150.0 million Coupon Rate 3.79% 3.66% 4.37% 4.47% 4.25% Maturity Date November 2, 2015 November 2, 2017 November 2, 2020 November 2, 2022 October 25, 2021 As at December 31, 2012, Bonavista is in compliance with all the covenants under its credit facilities. 13. Decommissioning liabilities: Bonavista’s decommissioning liabilities results from net ownership interests in oil and natural gas assets including well sites, gathering systems and processing facilities. Bonavista estimates the net present value of its total decommissioning liabilities to be $447.8 million as at December 31, 2012 (2011 - $444.1 million), based on an estimated total future undiscounted liability of approximately $899.4 million (2011 - $772.2 million). At December 31, 2012 management estimates expenditures required to settle the liability will be made over the next 50 years. A risk-free rate of approximately 2.4% (2011 - 2.5%) and an inflation rate of 2% (2011 – 2%) were used to calculate the present value of the decommissioning liability. The impact of the change in the risk free rate is reflected in the table below in the category change in estimate. A reconciliation of the decommissioning liabilities is provided below: (thousands) Balance, beginning of year Accretion expense Liabilities incurred Liabilities acquired Liabilities disposed Liabilities settled Change in estimate Years ended December 31, 2011 2012 $ 444,132 $ 319,096 9,895 5,173 15,805 (35,635) (25,530) 33,913 12,206 16,202 3,717 (4,544) (21,136) 118,591 Balance, end of year $ 447,753 $ 444,132 14. Deferred 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. The difference results from the following items: (thousands) Income before taxes Current statutory income tax rate Income tax expense at current statutory rate Goodwill impairment Effect of tax rate changes and rate variance Other Deferred income taxes Years ended December 31, 2011 2012 $ 90,494 $ 194,333 25.1% 22,714 - (64) 3,642 26.6% 51,693 5,337 (3,942) 4,061 $ 26,292 $ 57,149 The decrease in the statutory rate from 2011 to 2012 is a result of the federal enacted rate decreasing by 1.5%. 46 The net deferred income tax liability is comprised of the following: Deferred income tax liabilities: Capital assets in excess of tax value Partnership deferral Foreign exchange on long-term debt Debt issue costs Deferred income tax assets: Decommissioning liabilities Non-capital losses Deferred liability Share issue costs Financial instruments contracts Marketable securities Share-based compensation Deferred income tax liability December 31, 2012 December 31, 2011 $ 348,848 $ 271,029 92,306 2,694 1,656 137,069 772 32 (112,207) (107,704) (111,300) (99,720) (4,046) (8,153) (126) (92) - - (5,865) (1,732) - (616) $ 213,176 $ 189,669 A continuity of the net deferred income tax liability is detailed in the following tables: Balance December 31, 2011 (Asset)/ Liability Recognized in profit and loss (Asset)/ Liability Recognized in equity (Asset)/ Liability Acquired in business combinations (Asset)/ Liability Recognized in property, plant and equipment (Asset)/ Liability Balance December 31, 2012 (Asset)/ Liability (thousands) Property, plant and equipment $ 271,029 $ 68,980 $ Decommissioning liabilities (111,300) Non-capital losses Partnership deferral Share issue costs Deferred liability Foreign exchange Debt issue costs Financial instruments contracts Marketable securities Share-based compensation (99,720) 137,069 (5,865) - 772 32 (1,732) - (616) 2,956 (7,984) (44,763) 1,260 167 1,922 1,624 1,606 (92) 616 - - - - (3,548) - - - - - - $ 8,839 $ (3,863) - - - (4,213) - - - - - - - - - - - - - - - - $ 348,848 (112,207) (107,704) 92,306 (8,153) (4,046) 2,694 1,656 (126) (92) - $ 189,669 $ 26,292 $ (3,548) $ 763 $ - $ 213,176 47 Balance December 31, 2010 (Asset)/ Liability Recognized in profit and loss (Asset)/ Liability Recognized in equity (Asset)/ Liability Acquired in business combinations (Asset)/ Liability Recognized in property, plant and equipment (Asset)/ Liability Balance December 31, 2011 (Asset)/ Liability $ 185,092 $ 53,618 $ (79,966) (83,580) 91,998 (1,448) 1,660 (11) (6,226) - (30,637) (11,680) 45,071 (284) (888) 43 2,522 (616) - - - - - - - (2,091) - $ 32,319 $ (697) (4,460) - - - - (70) - $ 107,519 $ 57,149 $ (2,091) $ 27,092 $ - - - - - - - - - - $ 271,029 (111,300) (99,720) 137,069 (1,732) 772 32 (5,865) (616) $ 189,669 (thousands) Property, plant and equipment Decommissioning liabilities Non-capital losses Partnership deferral Financial instruments contracts Foreign exchange Debt issue costs Share issue costs Share-based compensation The following is a summary of the estimated tax pools: Canadian oil and gas property expense Canadian development expense Canadian exploration expense Undepreciated capital cost Non-capital losses Other Total December 31, 2012 December 31, 2011 $ 1,032,539 $ 1,170,107 645,918 73,223 428,513 391,041 32,535 549,441 - 478,889 318,112 26,140 $ 2,603,769 $ 2,542,689 Non-capital losses carry forward of $391.0 million (2011 - $318.1 million) expire in years 2025 through 2032. Bonavista has capital losses of $67.8 million available for carry forward against future capital gains indefinitely that is not included in the deferred income tax asset. For the year ended December 31, 2012 and 2011 Bonavista paid no tax installments. 15. Commitments: The following details contractual cash obligations for long-term debt, lease obligations, and other purchase commitments as at December 31, 2012: Total 2013 2014 2015 2016 2017 and thereafter Payments Due by Year (thousands) Long-term debt repayments (1)(3) Interest payments (2)(3) Office lease (4) Drilling service contract (5) Transportation expenses $ 894,195 163,840 47,020 47,000 41,361 $ - 23,221 5,829 23,500 17,369 $ - 23,221 5,929 23,500 11,131 $ - 22,910 6,068 - 6,081 $ 344,195 20,719 6,068 - 3,382 $ 550,000 73,769 23,126 - 3,398 Total contractual obligations $ 1,193,416 $ 69,919 $ 63,781 $ 35,059 $ 374,364 $ 650,293 (1) 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 2016. Fixed interest payments on senior unsecured notes. US dollars payments are converted using the exchange rate of $1.00 US/Canadian dollar. (2) (3) (4) Office lease expires July 31, 2020. (5) The drilling service contract is with one provider for a term of two years. 48 16. Supplemental disclosure: a) Income Statement Presentation Bonavista's statement of income is prepared primarily by nature of expense, with the exception of employee compensation costs which are included in both the operating and general and administrative expense line items. The following table details the amount of total employee compensation costs included in the operating and general and administrative expense line items in the statement of income. (thousands) Operating General and administrative Total employee compensation costs b) Compensation of key management personnel: Years ended December 31, 2011 2012 $ 6,409 26,684 $ 5,563 24,955 $ 33,093 $ 30,518 The remuneration of key management personnel of the Corporation during the year ended December 31 is as follows: (thousands) Short-term employee benefits Share-based payments Years ended December 31, 2011 2012 $ 2,823 6,523 $ 9,346 $ 2,442 2,821 $ 5,263 49 CORPORATE INFORMATION DIRECTORS Keith A. MacPhail, Executive Chairman Ronald J. Poelzer, Executive Vice Chairman Michael M. Kanovsky, Lead Director Sky Energy Corporation Ian S. Brown, Independent Businessman Harry L. Knutson, Nova Bancorp Inc. Margaret A. McKenzie, Range Royalty Management Ltd. Jason E. Skehar President and CEO Christopher P. Slubicki, Independent Businessman Walter C. Yeates, Independent Businessman OFFICERS Keith A. MacPhail, Executive Chairman Ronald J. Poelzer, Executive Vice Chairman Jason E. Skehar, President and CEO Glenn A. Hamilton, Senior Vice President and CFO Scott H. Hanson, Vice President, Production Bruce W. Jensen, Vice President, Engineering Dean M. Kobelka, Vice President, Finance Magni Lake, Vice President, Marketing Wayne E. Merkel, Vice President, Exploration Lynda J. Robinson, Vice President, Human Resources and Administration Hank R. Spence, Vice President, Operations Cory J. Stewart, Vice President, Land Grant A. Zawalsky, Corporate Secretary FOR FURTHER INFORMATION CONTACT: Keith A. MacPhail Executive Chairman or Jason E. Skehar President and CEO 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 Citibank, N.A. (Canadian Branch) HSBC Bank Canada Sumitomo Mitsui Banking Corporation of Canada Union Bank of California, N.A. (Canada Branch) Calgary, Alberta ENGINEERING CONSULTANTS GLJ Petroleum Consultants Ltd. 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: or Glenn A. Hamilton Senior Vice President and CFO 50 

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