BNP Paribas Bank Polska
Annual Report 2014

Plain-text annual report

ANNUAL REPORT 2014 February 26, 2015 Highlights Three months ended December 31 Years ended December 31 2014 2013 % Change 2014 2013 % Change 244,612 135,845 0.63 42,754 0.21 (60,978) (0.28) (199,730) (0.93) 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 (loss) (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 Weighted average outstanding equivalent shares: (thousands)(4) Basic Diluted 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) 3.87 37.56 83.76 7.38 1.02 10.99 19.63 359 18,256 7,688 85,810 162,155 (87,868) 215,855 218,571 245,466 124,354 0.62 38,904 0.21 6,667 0.03 23,702 0.12 — % 9 % 2 % 10 % — % (1,015)% (1,033)% (943)% (875)% 1,106,852 561,105 2.69 164,750 0.84 4,847 0.02 (136,643) (0.65) 4,429,402 1,032,029 1,155,422 2,357,706 964,312 477,578 2.42 152,968 0.84 49,505 0.25 75,297 0.38 4,235,626 1,165,077 1,124,198 2,270,015 111,596 4,815 45 % (1,925)% 639,560 (106,777) 443,829 20,530 199,254 201,756 8 % 8 % 208,719 210,957 197,296 199,340 287 15,103 12,208 75,072 3.54 49.35 72.73 8.77 1.21 12.91 20.82 25 % 21 % (37)% 14 % 9 % (24)% 15 % (16)% (16)% (15)% (6)% 314 15,991 8,873 77,211 4.27 49.78 80.72 8.25 1.14 12.20 22.60 278 15,093 12,039 73,406 3.35 47.61 79.32 8.93 1.15 13.00 20.54 15 % 17 % 11 % 8 % — % (90)% (92)% (281)% (271)% 5 % (11)% 3 % 4 % 44 % (620)% 6 % 6 % 13 % 6 % (26)% 5 % 27 % 5 % 2 % (8)% (1)% (6)% 10 % (2) (3) NOTES: (1) Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations as presented do 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 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. 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. Basic funds from operations per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. Dividends declared include both cash dividends and common shares issued pursuant to Bonavista's dividend reinvestment plan ("DRIP") and Bonavista's stock dividend program ("SDP"). There were no common shares issued under the DRIP and SDP for the three months ended December 31, 2014 (December 31, 2013 - 1.2 million). For the year ended December 31, 2014, approximately 1.7 million (December 31, 2013 - 4.6 million) common shares were issued under the DRIP and SDP with an approximate value of $26.1 million (December 31, 2013 - $59.2 million). Basic net income per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. Amounts have been adjusted to exclude unrealized gains and losses on financial instrument commodity contracts, net of tax. Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts and decommissioning liabilities. (4) (5) (6) (7) Oil includes light, medium and heavy oil. (8) (9) (10) Operating netback equals production revenues including realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses, calculated Product prices include realized gains and losses on financial instrument commodity contracts. Cash costs equal the total of operating, transportation, general and administrative, and financing expenses. on a boe basis. Highlights (cont'd) Year ended December 31 Drilling: Gross Net Land (net acres): Undeveloped Total Reserves:(11) Proved producing: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) Total proved: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) Proved plus probable: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) % Proved producing % Proved % Probable 2014 2013 % Change 134 111.6 128 104.5 816,085 2,218,776 1,281,191 2,891,947 5 % 7 % (36)% (23)% 15 % — % 9 % 15 % (5)% 8 % 15 % (5)% 7 % 1 % 1 % (1)% (9)% (14)% (19)% (23)% 3 % (1)% — % (1)% (9)% (10)% 21 % 662.0 59,129 169,456 1,094.4 93,329 275,729 1,689.9 145,119 426,768 40% 65% 35% 575.9 58,853 154,833 950.4 97,822 256,216 1,472.0 153,195 398,529 39% 64% 36% 9,726 6,310 4,608 3,608 9.1 13.2 1,282 1,994 11.95 11.03 1.9 Net present value of future cash flow before income taxes ($ millions, proved plus probable): 0% discount rate 5% discount rate 10% discount rate 15% discount rate Reserve life index (years):(12) Total proved Proved plus probable Reserves (boe per thousand shares - basic): Total proved Proved plus probable Finding and development costs - proved plus probable ($/boe)(13) Finding, development and acquisition costs - proved plus probable ($/boe)(13) Recycle ratio - proved plus probable(14) 8,845 5,402 3,733 2,783 9.4 13.1 1,277 1,977 10.85 9.94 2.3 NOTES: (11) Working interest reserves are gross reserves prior to deduction of royalties and without including any of Bonavista's royalty interests. (12) Calculated based on the amount for the relevant reserve category divided by the 2015 production forecast prepared by the independent reserve evaluator (GLJ). (13) Includes changes in future development costs. (14) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition costs per boe. Share Trading Statistics December 31, 2014 September 30, 2014 June 30, 2014 March 31, 2014 Three months ended ($ per share, except volume) High Low Close 12.99 6.66 7.30 16.36 12.61 12.88 17.85 15.79 16.37 16.22 13.46 16.17 Average Daily Volume - Shares 999,646 728,707 545,585 566,650 MESSAGE TO SHAREHOLDERS Our pursuit to become one of the most efficient operators in western Canada has resulted in 2014 being an outstanding year for Bonavista. Throughout, we remained focused on enhancing capital and operating efficiencies, while further concentrating our asset portfolio in the West Central and Deep Basin Core Areas. This unwavering commitment to operational excellence and targeted development within our core areas has resulted in annual production of 77,211 boe per day, representing five percent growth over 2013, despite divesting of approximately 6,000 boe per day of non-core assets. Significant infrastructure investment in the first half of 2014 created incremental processing capacity resulting in profitable production growth in our key plays during the second half of the year. We exited 2014 with average production for December of 88,083 boe per day, representing 17% (eight percent per share) growth, relative to the same period in 2013. Overall, we added production at a cost of approximately $17,000 per boe per day on a trailing twelve month full cycle basis. This represents a 50% reduction in our cost of adding production over the past two years, reflecting our relentless focus on efficiency. Similarly, we have grown our proved plus probable reserves by seven percent to 427 mmboe as at December 31, 2014. With profitable growth being paramount, we have reduced our 2014 finding, development and acquisition (“FD&A”) costs by 10% to $9.94 per boe, on a proved plus probable basis, including changes in future development costs (“FDC”), resulting in a recycle ratio of 2.3:1. Our business plan remains focused on maximizing shareholder value through a balance of growth and income. In 2014, we delivered production growth of five percent and delivered an annualized yield of six percent, collectively exceeding our total return goal of 10%. For 2015, we remain focused on prudent and sustainable spending levels in light of the current commodity price environment. Our goal is to spend within the limits of our forecasted funds from operations for 2015. Hence, we have revised our capital budget to reflect an "all-in" payout ratio (inclusive of dividends) of 100%. Our 2015 capital budget has been revised to between $300 and $320 million, drilling between 70 (60.4 net) and 80 (69.1 net) wells. Notwithstanding a curtailment of approximately 3,500 boe per day in our annual guidance due to planned facility turnaround activity, our annual production is expected to grow approximately five percent year-over-year to between 80,000 and 82,000 boe per day. This growth, combined with our current dividend yield of approximately five percent, should result in attaining our goal of a 10% total shareholder return again in 2015. Operational and financial accomplishments for 2014 include: • Grew fourth quarter production by 14% over last year to 85,810 boe per day, resulting in annual production growth of 5% to 77,211 boe per day, despite turnaround activities and net dispositions reducing production by 4,500 boe per day annually; • Reduced fourth quarter operating costs by 16% over last year to $7.38 per boe, resulting in an annual reduction in operating costs of 8% to $8.25 per boe and cash costs by 6% to $12.20 per boe. This has generated an annual operating netback of $22.60 per boe, a 10% improvement from 2013; • Invested $639.6 million in exploration and development ("E&D") activities, drilling 134 (111.6 net) wells, adding on average 545 boe per day of production per well using the first 30 days of production. Consistent with our asset concentration strategy, 130 of the 134 wells were drilled within our core areas. Productivity peaked in the fourth quarter where $162.2 million was spent on E&D development, drilling 27 (24.2 net) wells averaging 710 boe per day per well in their first 30 days of production; BONAVISTA ENERGY CORPORATION Page 3 • Reduced FD&A costs by 10% to $9.94 per boe on a proved plus probable basis, including changes in FDC, resulting in a recycle ratio of 2.3:1. Similarly, our E&D program delivered a reduction in finding and development costs (“F&D”) by 9% to $10.85 per boe on a proved plus probable basis, including changes in FDC, resulting in a recycle ratio of 2.1:1; • Replaced 2014 production by 200%, adding 56 mmboe of reserves on a proved plus probable basis, bringing year- end 2014 reserves to 427 mmboe, a 7% increase over year-end 2013; • Generated production revenues of $1.1 billion, a 15% increase compared to 2013; • Realized funds from operations of $561.1 million ($2.69 per share), a 17% increase from 2013; • Hedged 248,000 gj per day of our natural gas at an average floor price of $3.54 per gj at AECO for 2015 and approximately 150,000 gj per day at an average floor price of $3.40 per gj for 2016. Additionally, we hedged 8,000 bbls per day of our oil and liquids at an average floor price of CDN$91.59 per bbl WTI for 2015. Overall for 2015, Bonavista has hedged approximately 70% of our forecasted revenues (net of royalties); • Completed a bought deal financing for net proceeds of approximately $192 million, issuing 12.1 million common shares to fund our Ansell area acquisition and future development; • Extended the term of our bank facility of $600 million to September 10, 2018 at reduced borrowing costs, with $442.8 million undrawn at December 31, 2014; and • Delivered cumulative dividends of over $2.6 billion or $27.87 per common share since 2003, when Bonavista introduced an income component to our total shareholder return. Acquisition and divestiture highlights: • Completed 38 property transactions in 2014, resulting in net proceeds of $106.8 million; • Completed acquisitions of $186.6 million adding production of 2,800 boe per day at closing and 1,300 boe per day on average for the year and 82 net future drilling locations in our core areas. The largest acquisition was at Ansell in our Deep Basin Core Area focusing on the Wilrich play, for $141.1 million. Since acquiring these assets, we have organically grown production at Ansell by 3.5 times to 8,850 boe per day in December; and • Divested of $293.4 million representing 6,000 boe per day of non-core assets, reducing annual production by 3,500 boe per day. The disposed assets had operating costs in excess of $22.00 per boe. 2014 FOURTH QUARTER AND ANNUAL CORE AREA HIGHLIGHTS WEST CENTRAL CORE AREA Our West Central Core Area is characterized by liquids-rich natural gas and light oil resources in multiple prospective horizons, with year round access. It includes extensive infrastructure of over 2,800 kilometers of pipelines and 38 facilities, the majority of which are operated by Bonavista. In this core area, we have access to approximately 1.3 million acres, containing approximately 800 of our future drilling locations. Given our current development pace of drilling 50 to 60 locations per year, this represents a drilling inventory in excess of 14 years. In 2014, we spent $380 million on E&D activities, drilling 98 (82.2 net) horizontal wells. In 2015, we plan to reduce E&D spending to $167 million, due to current commodity price weakness, drilling 54 (43.8 net) horizontal wells. Production in this area averaged 46,796 boe per day in 2014 representing a 13% increase over 2013, despite significant third party turnaround activity in the second and third quarters. Our Hoadley Glauconite play continues to be our engine of growth representing 71% of the total expenditures forecasted in this core area for 2015. Meanwhile, the emerging growth and profitability of our Falher play, even in this commodity price environment, has become a focal point of our planning given our recent drilling successes. Glauconite Natural Gas Bonavista conducted its most active year, drilling 69 (59.5 net) horizontal wells, representing a 78% increase in net wells from 2013, including 10 wells (9.4 net) in the fourth quarter. This increased activity has resulted in fourth quarter production of approximately 27,000 boe per day, equating to over 50% growth since the beginning of the year. BONAVISTA ENERGY CORPORATION Page 4 Well economics remain strong in spite of the decrease in natural gas and natural gas liquids pricing. With the addition of deep cut processing at the Rimbey facility during the second quarter of 2015, we expect a 40% improvement in the natural gas liquids recoveries, to approximately 100 bbls per mmcf. Using these improved recoveries, single well economics are slightly improved to a 30% internal rate of return (“IRR”), using a price of $3.00 per gj @ AECO for natural gas and a WTI price of US$60.00 per bbl for oil and condensate. This is a testament to the quality of this play and its ability to generate competitive returns in the current commodity price environment. We remain encouraged with the results of our extended reach horizontal program. We have drilled 12 extended reach horizontal wells to date, averaging 1.9 times the length of a typical “one-mile” well. Using this horizontal length multiplier, these wells have demonstrated cost reductions averaging 19% and production capital efficiency improvements of six percent. Slick water completions for these wells have resulted in additional cost savings of 25% versus a standard completion technique. We plan to drill an additional eight extended reach wells in 2015. Being the most active operator, with inventory of approximately 400 locations and strong economics, the Glauconite will continue to serve as the foundation of our development program. As such, we plan to drill 44 (33.8 net) wells in 2015. Spirit River Falher Natural Gas In 2014, our Falher E&D program at Morningside has yielded exciting results, drilling six horizontal wells, including one during the fourth quarter. First month production rates have averaged 1,070 boe per day, inclusive of natural gas liquids yield of approximately 50 bbls per mmcf. This year, our production has grown seven-fold to 4,070 boe per day during December 2014 from 500 boe per day in January 2014. To support this rapid growth, we expanded our compression and gathering infrastructure in the second half of the year and have since reached capacity with results exceeding our expectations. We have 25 Falher drilling locations in our inventory at Morningside and development economics continue to compete with our flagship Glauconite play. Well costs are $3 million to drill, complete and equip, generating an internal rate of return of 36%, using prices of $3.00 per gj AECO for natural gas and a WTI price of US$60.00 per bbl. The low cost and high deliverability of the Falher enables this play to achieve competitive rates of return at current commodity prices. Consequently, we plan to drill eight (8.0 net) Falher wells in 2015, seven of which will be at Morningside. Additional Highlights Cardium activity in 2014 consisted of 16 (11.4 net) wells which performed above our expectations, averaging 295 boe per day in their first 30 days of production. This drilling program was supported by the installation of a multi-well oil battery with a capacity of 5,000 bbls per day at Lochend. In light of the current outlook on oil prices, we have scaled back our development program whereby only two Cardium wells will be drilled in 2015. We drilled four Ellerslie wells in 2014, all of them during the first half of the year. During the second half, our capital allocation shifted away from the Ellerslie and over to our Deep Basin Wilrich play as a result of the Ansell acquisition. At current commodity prices, the Ellerslie does not compete with our Glauconite and Spirit River plays, as such we do not have any wells planned for 2015. DEEP BASIN CORE AREA Our Deep Basin Core Area contains multiple vertically stacked oil and natural gas reservoirs in a concentrated area, proximate to infrastructure and associated services. Over the past three years, we have been aggressively building our position in this core area. We have assembled approximately 300,000 net acres, identified 300 horizontal drilling locations, and we have achieved compounded annual growth in our reserve base of 62% to 111 mmboe proved plus probable reserves at December 31, 2014 during this period. In 2014, we spent approximately $175 million on E&D activities, drilling 32 (25.3 net) horizontal wells and built $31 million of infrastructure. This resulted in average annual production growth of approximately 30% to 17,276 boe per day. Bonavista had an active fourth quarter drilling program in the Deep Basin, drilling 11 (9.8 net) horizontal wells, seven of which were Wilrich wells at Ansell. Our Wilrich results continue to exceed expectations, as such, we plan to install additional processing infrastructure in 2015 and have secured incremental egress for our production. Our 2015 plans involve spending $106 million on E&D activities, drilling 19 (18.9 net) horizontal wells. BONAVISTA ENERGY CORPORATION Page 5 With compelling production performance, the Wilrich play provides solid economics in the current natural gas pricing environment, resulting in an attractive internal rate of return of 36%, using prices of $3.00 per gj AECO for natural gas and a WTI price of US$60.00 per bbl. Lastly, as we develop the extensive Notikewin and Falher channel systems deposited above the Wilrich reservoir, we anticipate significant inventory additions to our asset portfolio in this play. Spirit River Natural Gas Within the Wilrich zone at Ansell we drilled 15 (13.9 net) horizontal wells in 2014, including seven (7.0 net) in the fourth quarter. In 2014, our development plan at Ansell consisted of infrastructure investment with a goal to develop an unrestricted egress for our Ansell Wilrich development. During the first half of the year, we commissioned two 30 kilometer pipelines with 120 mmcf per day of capacity and constructed a 30 mmcf per day compressor station. In July, we acquired our non-operated partner, increasing our ownership from 51% to 100%, and during the fourth quarter, we expanded our compression capacity to 60 mmcf per day. With our 2014 Ansell Wilrich drilling program, we continued to improve our understanding of the play as well as enhance our completion techniques. As a result, we have improved the initial 30 day production rate from 674 boe per day for our first quarter 2014 wells to 964 boe per day for our fourth quarter 2014 wells. Continuous improvement in the economic performance at Ansell has earned the allocation of 71% ($75 million) of our 2015 Deep Basin capital expenditures, consisting of 16 (16.0 net) wells. In the Marlboro area, we drilled five horizontal wells (3.1 net) in 2014, including two (1.6 net) in the fourth quarter. We are pleased with our Marlboro program as the wells have achieved an average 30 day rate of 975 boe per day. With existing facility utilization near capacity at Marlboro, we do not plan to drill any wells in 2015. The successful 2014 Wilrich programs at Ansell and Marlboro has resulted in our Wilrich production growing by over 170% in 2014 to approximately 13,000 boe per day in December. In 2014, we identified numerous Notikewin and Falher opportunities using three dimensional seismic. Subsequent to the fourth quarter, we drilled our first Notikewin well at Ansell which recorded an initial 30 day rate of 710 boe per day. We are pleased with this initial result and remain optimistic about future development. The economics of the Notikewin and Falher will benefit from our existing infrastructure constructed for our Wilrich and Bluesky programs. Additional Highlights In 2014, we drilled five horizontal Bluesky wells on our Pine Creek acreage. In the fourth quarter we drilled two wells with an average 30 day rate of 810 boe per day per well. We also participated in an additional five non-operated wells with an average 30 day rate of 520 boe per day per well. Our operated Bluesky wells have exceeded our expectations, however given facility capacity constraints and the current commodity price environment, we will only drill one Bluesky well in 2015. MONTNEY Bonavista drilled two horizontal Montney wells in our Blueberry field in northeast British Columbia targeting the upper Montney. These wells had an average 30 day rate of 450 boe per day per well despite being restricted through non- operated facilities. The improved performance of our 2014 wells reflects our understanding of the reservoir characteristics and the use of enhanced completion techniques to maximize stimulated area and conductivity. Our Montney play remains an important component of our future growth. We plan to drill two wells in 2015 for the purposes of delineating the resource, exploring enhanced completion techniques and honoring our land retention program. STRENGTHS OF BONAVISTA ENERGY CORPORATION Throughout our eighteen year history, from an initial restructuring in 1997 to create a high growth junior exploration company, through the energy trust phase between July 2003 and December 2010, and since January 2011 as a dividend paying corporation, Bonavista has remained committed to the same operating philosophies despite the endless commodity price volatility and uncertainty inherent in the energy sector. We have consistently maintained a high level of investment activity on our asset base resulting in an increase in corporate production by approximately 125% since converting to an energy trust in July 2003. These results stem from the expertise of our people and their entrepreneurial approach to consistently generating profitable development projects in an unpredictable commodity price environment. Our experienced technical teams have a thorough understanding of our assets and the reservoirs within the Western Canadian Sedimentary Basin as they exercise the discipline and commitment required to deliver long-term value to our shareholders. The core operating and financial principles that guide our people have been with our organization from the beginning and remain solidly intact today. BONAVISTA ENERGY CORPORATION Page 6 Our production is approximately 70% weighted towards natural gas and is geographically focused in multi-zone regions, primarily in Alberta. We actively participate in undeveloped land purchases, property acquisitions and farm-in opportunities, which have all enhanced the quantity and quality of our extensive drilling inventory. Specifically over the past five years, technology coupled with North American natural gas supply/demand fundamentals has led to numerous opportunities to reposition the asset portfolio and drastically improve the quality of our development projects. These activities have led to low cost reserve additions and a reliable production base that continues to grow at a steady pace. Today, the predictable production performance and cost structure of our asset base ensures operating netbacks that compete favorably in most operating environments. Furthermore, our assets are predominantly operated by Bonavista, providing control over the pace of operations and a direct influence over our operating and capital cost efficiencies. Our team brings a successful track record of executing low to medium risk scalable development programs with consistency and with precision. We continually strive for balance sheet flexibility and remain focused on prudent 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 underpinned with a set of consistent and reliable operating and financial principles. Directors, management and employees also own approximately 11% of the equity of Bonavista, aligning our interests with those of external shareholders. OUTLOOK North American natural gas markets remain oversupplied creating increased pricing uncertainty and volatility. Increasing US natural gas production has mitigated storage withdrawals normally anticipated during the winter season. The environment continues to be challenging at current prices given the global supply/demand imbalance, and to be successful we remain focused on efficiencies and cost controls. We remain committed to be the most efficient operator in western Canada. In 2014, our asset concentration strategy, coupled with our execution efficiency has resulted in 17% growth in our exit production over the same period in 2013. This resulted by adding production at a competitive cost of $17,000 per boe per day on a trailing twelve month full cycle basis. For 2015, we will remain on strategy with virtually all of our E&D spending allocated to our core areas. The economic resilience of both our Glauconite play and our prolific Spirit River plays will attract the majority of this E&D budget given our expectations of 30 to 40% returns in this commodity price environment. We have approximately 700 locations in these two plays, which economically rank among the best natural gas plays in western Canada. Furthermore, the anticipated reduction in service provider utilization this year will improve the cost and efficiency of these services and enhance our economics in 2015 and beyond. We have witnessed many commodity price cycles in our eighteen year history. In these environments, efficient companies with high quality assets and a low cost structure will succeed. We are confident that our asset portfolio and our proven ability to execute efficiently will enable us to deliver profitable returns through this cycle while maintaining or even improving financial flexibility. We would like to thank our employees for their dedication and commitment to our strategy throughout the year and our shareholders for their continued support in these uncertain times. We are very pleased with our achievements in 2014 and remain confident in our strategy for 2015 and beyond. On behalf of the Board of Directors Keith A. MacPhail Jason E. Skehar Executive Chairman President and Chief Executive Officer February 26, 2015 Calgary, Alberta BONAVISTA ENERGY CORPORATION Page 7 BONAVISTA ENERGY CORPORATION 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” or "our") audited consolidated financial statements for the year ended December 31, 2014, together with the notes thereto. The following MD&A of the financial condition and results of operations was prepared at, and is dated February 26, 2015. Basis of Presentation - The financial data presented below has been prepared in accordance with International Accounting 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. Operations - Bonavista's exploration and development program for the year ended December 31, 2014 led to the drilling of 134 (111.6 net) wells. Consistent with Bonavista's asset concentration strategy, 130 of the 134 wells were drilled within the Deep Basin and West Central Core Areas. In line with Bonavista's expectations, our exploration and development programs delivered solid rates of return and reinforced management's confidence in the quality of Bonavista's asset portfolio. The recent collapse in world oil prices and muted outlook for North American natural gas and natural gas liquids prices has caused Bonavista to re-evaluate its exploration and development program for 2015. As a result, Bonavista is planning to drill approximately 70 (60.4 net) to 80 (69.1 net) wells in its core areas during 2015 with a revised capital budget of between $300 and $320 million. Profitability continues to guide our exploration and development program and our priority is to maintain flexibility to accommodate continued changes in commodity prices, development risk and well performance. Reserves - Reserves estimates have been calculated in compliance with National Instrument 51-101 Standards of Disclosure ("NI 51-101"). Of the net present value of the Corporation's reserves, 89% were evaluated by independent third-party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") in their report dated February 3, 2015. The balance of approximately 11% of proved plus 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, 2014 and are defined under NI 51-101, as the Corporation's interest before deduction of royalties and without including any of the Corporation's royalty interests. BONAVISTA ENERGY CORPORATION Page 8 Reserves(1)(4) Proved Proved producing Proved non-producing Proved undeveloped Total proved Probable 661,960 13,999 418,441 1,094,400 595,491 Proved plus probable Proved reserve life index (years)(3) Proved plus probable reserve life index (years)(3) 1,689,891 Natural Gas Light, Medium and Heavy Oil Natural Gas Liquids Total Reserves (2) (mboe) (mbbls) (mbbls) (mmcf) 17,520 321 3,527 21,369 9,075 30,444 41,609 795 29,556 71,960 42,715 114,675 169,456 3,449 102,823 275,729 151,038 426,768 9.4 13.1 (1) (2) (3) (4) Bonavista's gross reserves are based on the GLJ reserve report dated February 3, 2015, GLJ reserve estimates based on forecast prices and costs as of January 1, 2015. 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 value equivalency at the wellhead. Calculated based on the amount for the relevant reserve category divided by the 2015 production forecast prepared by GLJ. Amounts may not add due to rounding. Reserve Reconciliation(1) Balance, December 31, 2013 Extensions and improved recovery Technical revisions Acquisitions Dispositions Economic Factors Production Balance, December 31, 2014 (1) Amounts may not add due to rounding. Proved (mboe) 256,216 44,426 9,682 9,025 (10,837) (4,653) (28,131) 275,729 Probable Proved plus Probable (mboe) 142,313 17,673 (9,326) 6,321 (5,265) (678) — 151,039 (mboe) 398,529 62,100 356 15,347 (16,102) (5,331) (28,131) 426,768 Bonavista's 2014 year end proved reserves totaled 275.7 mmboe, a 8% increase compared to the 256.2 mmboe at the year end 2013. Proved plus probable reserves increased by 7% to 426.8 mmboe when compared to 398.5 mmboe at the year end 2013. Bonavista's proved plus probable reserve life index was relatively unchanged at 13.1 years at the year end 2014 compared to 13.2 years at the year end 2013. The stability of the proved plus probable reserve life index demonstrates the sustainable balance that exists between Bonavista's capital program, reserve additions and production levels. The following tables highlight Bonavista's proved plus probable reserves, proved plus probable finding and development ("F&D") expenditures, proved plus probable finding, development and acquisition ("FD&A") expenditures and the associated recycle ratios: Year ended December 31 Reserves (mboe): Proved producing Total proved Proved plus probable Capital expenditures ($ millions): Exploration and development Acquisitions, net of dispositions Total capital expenditures Operating Netback ($/boe):(1) Current year Three-year weighted average 2014 2013 % Change 169,456 275,729 426,768 639.6 (106.8) 532.8 22.60 20.37 154,833 256,216 398,529 443.8 20.5 464.3 20.54 20.92 9 % 8 % 7 % 44 % (620)% 15 % 10 % (3)% (1) Operating netback is calculated using production revenues including realized gains and losses on financial instruments commodity contracts less royalties, transportation and operating costs calculated on a per boe equivalent basis. BONAVISTA ENERGY CORPORATION Page 9 Year ended December 31 Finding and Development Expenditures: Proved Producing: Change in FDC ($ thousands) Reserves additions (mboe) F&D costs ($/boe)(3) F&D recycle ratio(3) F&D three-year weighted costs ($/boe)(2) F&D recycle ratio three-year weighted average(3) Total Proved: Change in FDC ($ thousands) Reserves additions (mboe) F&D costs ($/boe)(3) F&D recycle ratio(3) F&D three-year weighted costs ($/boe)(2) F&D recycle ratio three-year weighted average(3) Proved plus Probable: Change in FDC ($ thousands) Reserves additions (mboe) F&D costs ($/boe)(3) F&D recycle ratio(3) F&D three-year weighted costs ($/boe)(2) F&D recycle ratio three-year weighted average(3) Finding, Development and Acquisition Expenditures: Proved Producing: Change in FDC ($ thousands) Reserves additions (mboe) FD&A costs ($/boe)(3) FD&A recycle ratio(3) FD&A three-year weighted costs ($/boe)(2) FD&A recycle ratio three-year weighted average(3) Total Proved: Change in FDC ($ thousands) Reserves additions (mboe) FD&A costs ($/boe)(3) FD&A recycle ratio(3) FD&A three-year weighted costs ($/boe)(2) FD&A recycle ratio three-year weighted average(3) Proved plus Probable: Change in FDC ($ thousands) Reserves additions (mboe) FD&A costs ($/boe)(3) FD&A recycle ratio(3) FD&A three-year weighted costs ($/boe)(2) FD&A recycle ratio three-year weighted average(3) 2014 2013 % Change (4,005) 49,547 12.83 1.8 14.89 1.4 1,312 49,488 12.95 1.7 14.70 1.4 (19,091) 57,209 10.85 2.1 12.21 1.7 1,120 42,754 12.49 1.8 13.43 1.5 45,038 47,573 12.15 1.9 13.05 1.6 28,160 56,454 9.94 2.3 10.70 1.9 7,232 27,410 16.46 1.2 16.68 1.3 (40,992) 25,877 15.57 1.3 17.10 1.2 15,007 38,409 11.95 1.7 13.62 1.5 10,195 32,833 14.45 1.4 15.65 1.3 40,114 34,564 14.60 1.4 15.31 1.4 120,685 53,065 11.03 1.9 12.07 1.7 (155)% 81 % (22)% 50 % (11)% 8 % (103)% 91 % (17)% 31 % (14)% 17 % (227)% 49 % (9)% 24 % (10)% 13 % (89)% 30 % (14)% 29 % (14)% 15 % 12 % 38 % (17)% 36 % (15)% 14 % (77)% 6 % (10)% 21 % (11)% 12 % (2) Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis (6:1). (3) Recycle ratio is defined as operating netback per boe divided by either F&D or FD&A costs on a per boe basis. (4) The aggregate of the E&D costs incurred in the financial year and change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Bonavista demonstrated significant improvements in its recycle ratio in 2014 delivering a ratio of 2.3:1 for proved plus probable reserves and 2.1:1 for proved reserves including revisions and changes in future development expenditures. Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista’s Annual Information Form that will be filed on SEDAR. BONAVISTA ENERGY CORPORATION Page 10 Financial and operating highlights - The following is a summary of key financial and operating results for the respective periods: ($ thousands, expect per boe and share amounts where noted) Three months ended December 31 Years ended December 31 2014 2013 % Change 2014 2013 % Change 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 Share-based compensation per boe Depreciation, depletion, amortization and impairment per boe Net finance costs per boe Deferred income taxes (recovery) per boe Net income (loss) per boe per share - basic Dividends declared per share Funds from operations per boe per share - basic 3.87 37.56 83.76 359 18,256 7,688 85,810 3.54 49.35 72.73 287 15,103 12,208 75,072 244,612 245,466 30.99 27,328 35.54 30,099 3.46 11.2% 4.36 12.3% 58,239 60,601 7.38 9,556 1.21 8,074 1.02 2,608 0.33 404,949 51.29 39,473 5.00 (6,067) (0.77) (60,978) (7.72) (0.28) 8.77 9,206 1.33 8,361 1.21 5,777 0.84 90,844 13.15 36,964 5.35 1,215 0.18 6,667 0.97 0.03 42,754 38,904 0.21 0.21 135,845 124,354 17.21 0.63 18.00 0.62 9 % (24)% 15 % 25 % 21 % (37)% 14 % — % (13)% (9)% (21)% (1)% (4)% (16)% 4 % (9)% (3)% (16)% (55)% (61)% 346 % 290 % 7 % (7)% (599)% (528)% (1,015)% (896)% (1,033)% 10 % — % 9 % (4)% 2 % 4.27 49.78 80.72 314 15,991 8,873 77,211 3.35 47.61 79.32 278 15,093 12,039 73,406 1,106,852 964,312 39.28 35.99 136,095 124,489 4.83 12.3% 4.65 12.9% 232,474 239,196 8.25 8.93 36,013 36,595 1.28 1.37 32,012 30,802 1.14 1.15 20,449 23,868 0.73 0.89 670,510 349,285 23.79 119,577 4.24 13.04 94,709 3.53 34,323 24,043 1.22 4,847 0.17 0.02 0.90 49,505 1.85 0.25 164,750 152,968 0.84 0.84 561,105 477,578 19.91 2.69 17.82 2.42 27 % 5 % 2 % 13 % 6 % (26)% 5 % 15 % 9 % 9 % 4 % (1)% (3)% (8)% (2)% (7)% 4 % (1)% (14)% (18)% 92 % 82 % 26 % 20 % 43 % 36 % (90)% (91)% (92)% 8 % — % 17 % 12 % 11 % BONAVISTA ENERGY CORPORATION Page 11 Production - For the year ended December 31, 2014, production volumes averaged 77,211 boe per day, a 5% increase compared to an average of 73,406 boe per day for year ended December 31, 2013. Natural gas production increased 13% to 314 mmcf per day for the year ended December 31, 2014 from 278 mmcf per day for the same period in 2013. Natural gas liquids production increased 6% to 15,991 bbls per day for the year ended December 31, 2014 from 15,093 bbls per day in 2013. Natural gas liquids production grew at a lesser pace than natural gas production as a result of temporary liquid recovery inefficiencies and significant turnaround activity, which led to the diversion of natural gas to less efficient processing plants. Oil production decreased 26% to 8,873 bbls per day for the year ended December 31, 2014 from 12,039 bbls per day for the same period in 2013 as a result of several non-core dispositions completed in 2014. Production volumes for the fourth quarter of 2014 grew 14% to average 85,810 boe per day, compared to 75,072 boe per day for the same period in 2013. Fourth quarter exploration and development was focused in the Deep Basin and West Central core areas where continued improvements in capital and operating efficiencies have led to significant production growth. Natural gas production increased 25% to 359 mmcf per day in the fourth quarter of 2014 from 287 mmcf per day in the fourth quarter of 2013. In addition, natural gas liquids production increased 21% to 18,256 bbls per day in the fourth quarter of 2014 from 15,103 bbls per day for the same period in 2013. Oil production decreased 37% to 7,688 bbls per day in the fourth quarter of 2014 from 12,208 bbls per day in the fourth quarter of 2013 as a result of non-core dispositions completed in the past year. 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 2014 359 18,256 7,688 85,810 2013 287 15,103 12,208 75,072 2014 314 15,991 8,873 77,211 2013 278 15,093 12,039 73,406 The following table summarizes Bonavista's production by core area for the three months and years ended December 31: Deep Basin (boe/day) West Central (boe/day) Other (boe/day) Total oil equivalent (boe/day) Three months ended December 31 Years ended December 31 2014 20,429 53,965 11,416 85,810 2013 14,298 42,468 18,306 75,072 2014 17,276 46,796 13,139 77,211 2013 13,449 41,437 18,520 73,406 Our current production is approximately 83,300 boe per day, consisting of 72% natural gas, 20% natural gas liquids and 8% oil. Production revenues - Production revenues for the year ended December 31, 2014 increased 15% to $1.1 billion, compared to $964.3 million for the same period in 2013, resulting from a 5% increase in production volumes and a 9% increase in production revenue per boe. For the year ended December 31, 2014, natural gas prices, including the impact of realized gains and losses on financial instrument commodity contracts, increased 27% to $4.27 per mcf, compared to $3.35 per mcf realized in the same period in 2013. Natural gas liquids prices, including the impact of realized gains and losses on financial instrument commodity contracts, increased 5% to $49.78 per bbl for the year ended December 31, 2014 from $47.61 per bbl for the same period in 2013. In addition, oil prices, including the impact of realized gains and losses on financial instrument commodity contracts, were $80.72 per bbl, an increase of 2% from $79.32 per bbl for the same prior year period. Production revenues for the fourth quarter of 2014 were $244.6 million which is relatively unchanged as compared to $245.5 million for the same period in 2013 as a decline in oil and natural gas liquid prices was offset by a 14% increase in production volumes. Production revenues per boe fell 13% in the fourth quarter of 2014 to $30.99 per boe from $35.54 per boe for the same period in 2013. This decrease was partially mitigated by the realized gains recognized on financial instrument commodity contracts in the fourth quarter of 2014, resulting in revenues per boe of $31.69, a 10% decrease compared to $35.28 per boe in the fourth quarter of 2013. Natural gas prices, excluding realized gains and losses on financial instrument commodity contracts, for the fourth quarter of 2014 increased 14% to $3.99 per mcf as compared to $3.50 per mcf for the same period last year. For the three months ended December 31, 2014 natural gas prices, including realized gains and losses on financial instrument commodity contracts, increased 9% to $3.87 per mcf compared to $3.54 per mcf in the same period in 2013. Natural gas liquids prices, excluding realized gains on financial instrument commodity contracts, decreased 25% to $37.08 per boe in the fourth quarter of 2014 as compared to $49.31 per boe for the same period in 2013. Natural gas liquids prices, including realized gains on financial instrument commodity contracts, decreased by 24% to $37.56 per boe in the fourth quarter of 2014 when compared to $49.35 per boe for the same period in 2013. The decline in pricing for natural gas liquids, excluding realized gains on financial instrument commodity contracts, was the result of a demand-supply imbalance, most notably in propane, as inventory levels remained high in the fourth quarter of 2014 resulting from milder winter temperatures across much of North America which limited demand. BONAVISTA ENERGY CORPORATION Page 12 Oil prices, excluding realized gains and losses on financial instrument commodity contracts, decreased by 5% for the three months ended December 31, 2014 to $71.71 per boe as compared to $75.21 per boe for the same period in 2013. Oil prices, including realized gains and losses on financial instrument commodity contracts, for the fourth quarter of 2014 were $83.76 per bbl, a 15% increase when compared to $72.73 per boe for the same period in 2013. The quarter over quarter decline in oil prices, excluding realized gains and losses on financial instrument contracts, was also related to a supply-demand imbalance as overall production continued to grow in non-opec countries while OPEC continued to maintain production levels. The impact of declining oil prices, which are benchmarked in US dollars, was partially offset by a strengthening of the US dollar relative to the Canadian dollar which increases the Canadian price received on our oil and natural gas liquids. The following table highlights Bonavista's production revenue per boe, including realized gains and losses on financial instrument commodity contracts, for the three months and years ended December 31: Three months ended December 31 Years ended December 31 Natural gas ($/mcf): Production revenues Realized gains (losses) on financial instrument 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 (losses) on financial instrument commodity contracts 2014 3.99 (0.12) 3.87 37.08 0.48 37.56 71.71 12.05 83.76 30.99 0.70 31.69 2013 3.50 0.04 3.54 49.35 — 49.35 75.21 (2.48) 72.73 35.54 (0.26) 35.28 2014 4.65 (0.38) 4.27 49.31 0.47 49.78 88.28 (7.56) 80.72 39.28 (2.31) 36.97 2013 3.35 — 3.35 47.61 — 47.61 82.51 (3.19) 79.32 35.99 (0.51) 35.48 Risk management activities - As part of our financial management strategy, Bonavista has adopted a disciplined commodity price risk management program. Bonavista's risk management program aims to reduce the impact of commodity price volatility and protect funds from operations, protect acquisition and development economics and fund dividend commitments. Bonavista’s Board of Directors has approved a commodity price risk management limit of 70% of the current year's budgeted revenues, net of royalties and 60% thereafter, provided that no more than 80% of forecasted revenues, net of royalties, from any one product may be hedged, or in the case of electricity, 60% of Bonavista's forecasted consumption. The term of any commodity hedge will be limited to no more than three calendar years subsequent to the current calendar year in which a hedge is executed. 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 currency. Swaps and costless collars are primarily entered into, which limits Bonavista's exposure to volatility in commodity prices while in the case of costless collars allows for the participation in some of the commodity price increases. For the year ended December 31, 2014, Bonavista's risk management program on financial instrument commodity contracts resulted in a gain of $123.6 million, consisting of a realized loss of $65.2 million and an unrealized gain of $188.8 million. The realized loss of $65.2 million consisted of a $43.5 million loss on natural gas commodity derivative contracts, a $24.5 million loss on oil commodity derivative contracts, offset by a $2.8 million gain on natural gas liquids commodity derivative contracts. For the same period in 2013, our risk management program on financial instrument commodity contracts resulted in a loss of $48.1 million, consisting of a realized loss of $13.7 million and an unrealized loss of $34.4 million. The realized loss of $13.7 million consisted of a $350,000 gain on natural gas commodity derivative contracts and a $14.0 million loss on oil commodity derivative contracts. For the fourth quarter of 2014, our risk management program on financial instrument commodity contracts resulted in a gain of $190.6 million, consisting of a realized gain of $5.5 million and an unrealized gain of $185.1 million. The realized gain of $5.5 million was comprised of a gain of $8.5 million on oil commodity derivative contracts and an $815,000 gain on natural gas liquids commodity derivative contracts, offset by a loss of $3.8 million on natural gas commodity derivative contracts. For the same period in 2013, our risk management program on financial instrument commodity contracts resulted in a loss of $24.5 million, consisting of a realized loss BONAVISTA ENERGY CORPORATION Page 13 of $1.8 million and an unrealized loss of $22.7 million. The realized loss of $1.8 million consisted of a loss of $2.8 million on oil commodity contracts, offset by a gain of $1.0 million on natural gas commodity contracts. As at December 31, 2014, Bonavista entered into the following costless collars to sell oil and natural gas: Volume Average Price Term 5,000 gjs/d CDN $3.50 - CDN $4.00 - AECO January 1, 2015 - March 31, 2015 5,000 gjs/d CDN $3.75 - CDN $4.29 - AECO January 1, 2015 - September 30, 2015 65,000 gjs/d CDN $3.50 - CDN $3.95 - AECO January 1, 2015 - December 31, 2015 10,000 gjs/d CDN $3.75 - CDN $4.26 - AECO January 1, 2016 - March 31, 2016 20,000 gjs/d CDN $3.69 - CDN $4.04 - AECO January 1, 2016 - December 31, 2016 10,000 gjs/d CDN $3.75 - CDN $4.20 - AECO January 1, 2017 - December 31, 2017 5,000 bbls/d CDN $89.60 - CDN $98.47 - WTI January 1, 2015 - December 31, 2015 500 bbls/d US $90.00 - US $100.40 - WTI January 1, 2015 - December 31, 2015 10,550 gjs/d US $3.90 - US $4.43 - NYMEX January 1, 2016 - March 31, 2016 Subsequent to December 31, 2014, Bonavista entered into the following costless collars to sell natural gas: Volume Average Price Term 15,000 gjs/d CDN $3.00 - CDN $3.29 - AECO January 1, 2016 - December 31, 2017 As at December 31, 2014, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume Price 10,000 gjs/d CDN $3.60 120,000 gjs/d CDN $3.70 20,000 gjs/d CDN $3.32 5,000 gjs/d CDN $3.81 15,000 gjs/d CDN $3.75 Contract Swap - AECO Swap - AECO Swap - AECO Swap - AECO Swap - AECO Term January 1, 2015 - March 31, 2015 January 1, 2015 - December 31, 2015 April 1, 2015 - December 31, 2016 November 1, 2015 - March 31, 2016 January 1, 2016 - December 31, 2016 10,550 gjs/d US $4.00 Swap - NYMEX January 1, 2015 - December 31, 2015 26,375 gjs/d US $(0.42) 2,500 bbls/d US 49.3% 2,500 bbls/d US 46.2% 1,000 bbls/d US $8.38 (1) Conway propane price as a percentage of WTI. Swap - AECO Basis Swap - CNWY PN/WTI(1) Swap - CNWY PN/WTI(1) Swap - WTI-MSW January 1, 2015 - December 31, 2015 January 1, 2015 - March 31, 2015 April 1, 2015 - March 31, 2016 January 1, 2015 - March 31, 2015 Subsequent to December 31, 2014, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume Price 20,000 gjs/d CDN $2.70 40,000 gjs/d CDN $3.14 5,000 gjs/d CDN $2.90 1,000 bbls/d US 40% (1) Conway propane price as a percentage of WTI. Contract Swap - AECO Swap - AECO Term April 1, 2015 to October 31, 2015 January 1, 2016 - December 31, 2017 Swap - AECO Swap - CNWY PN/WTI(1) April 1, 2016 - October 31, 2016 April 1, 2016 - March 31, 2017 As at December 31, 2014, Bonavista entered into the following contracts to purchase electricity: Volume 6 5 1 mwh mwh mwh Price CDN $50.88 CDN $51.60 CDN $52.50 Contract Swap - AESO Swap - AESO Swap - AESO Term January 1, 2015 - December 31, 2015 January 1, 2016 - December 31, 2016 January 1, 2017 - December 31, 2017 BONAVISTA ENERGY CORPORATION Page 14 Financial instrument commodity contracts are recorded in 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, 2014, the fair market value recorded on the consolidated statement of financial position for these financial instrument commodity contracts was a net asset of $153.9 million (December 31, 2013 - net liability $34.9 million). These financial instrument commodity contracts had the following gains and losses reflected in the consolidated statements of income and comprehensive income: ($ thousands) Realized gains (losses) on financial instrument commodity contracts Unrealized gains (losses) on financial instrument commodity contracts Three months ended December 31 Years ended December 31 2014 2013 2014 2013 5,490 (1,769) (65,232) (13,652) 185,148 190,638 (22,742) (24,511) 188,803 123,571 (34,426) (48,078) for income A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $10.4 million on net (December 31, 2013 - $6.8 million). A $1.00 change in the price per barrel of oil - WTI would have an impact of approximately $2.1 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2014 (December 31, 2013 - $3.5 million). instrument commodity contracts that were financial those in place as at December 31, 2014 In addition to those financial instrument commodity contracts in place, Bonavista also entered into the following physical contracts to sell natural gas as at December 31, 2014: Volume Price 30,000 gjs/d CDN $3.61 Contract AECO Term January 1, 2016 - December 31, 2016 Subsequent to December 31, 2014, Bonavista entered into the following physical contracts to sell natural gas: Volume Price 30,000 gjs/d CDN $2.87 Contract AECO Term April 1, 2015 - October 31, 2015 Bonavista has also entered into financial instrument contracts to mitigate foreign exchange exposure to fluctuations between the Canadian and United States dollar. To fix the foreign exchange rate on a portion of the US dollar denominated senior unsecured notes, Bonavista entered into an agreement on July 21, 2011, to purchase US dollars at predetermined rates on settlement dates that coincide with Bonavista's US dollar debt repayment commitments. Forward date November 2, 2017 November 2, 2020 November 2, 2022 Contract US$ 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 As at December 31, 2014, the fair value recorded on the consolidated statement of financial position for these financial instrument contracts was a long-term asset of $16.0 million, compared to a long-term asset of $8.0 million as at December 31, 2013. For the year ended December 31, 2014, an unrealized gain of $8.0 million was recorded on the consolidated statements of income and comprehensive income (December 31, 2013 - $3.7 million gain). Holding all other variables constant, a $0.01 change in CDN$/US$ exchange rate would have an impact of approximately $861,000 on net income for those foreign exchange forward contracts in place as at December 31, 2014 (December 31, 2013 - $709,000). BONAVISTA ENERGY CORPORATION Page 15 The US dollar has strengthened significantly over the past year relative to the Canadian dollar. The increase in interest expense on Bonavista's US dollar senior unsecured notes resulting from the devaluation of the Canadian dollar is mitigated by higher revenues earned from US dollar denominated commodities. However, to further manage exposure to foreign currency exchange fluctuations, Bonavista entered into a number of financial agreements subsequent to December 31, 2014. Each agreement requires Bonavista to purchase US dollars at a predetermined rate and date which coincide directly with Bonavista's US dollar debt repayment commitments. Settlement date June 6, 2016 June 5, 2017 November 2, 2017 November 2, 2020 October 25, 2021 Contract US$ purchased forward US$ purchased forward US$ purchased forward US$ purchased forward US$ purchased forward Notional US$ $12,500,000 $12,500,000 $30,000,000 $106,700,000 $150,000,000 CDN$/US$ 1.2220 1.2234 1.2228 1.2265 1.2297 Royalties - For the year ended December 31, 2014, royalties increased 9% to $136.1 million from $124.5 million in 2013, largely attributable to the 15% increase in production revenues. Royalties as a percentage of production revenues for the year ended December 31, 2014 decreased to 12.3% from 12.9%. The decrease in royalties as a percentage of production revenues is due to the increase in natural gas revenues which attract a lower royalty rate, comprising a larger percentage of the total production revenues. In addition, oil revenues attracting a higher royalty rate, have decreased as a percentage of total production revenues as result of disposition activity in 2014. Natural gas liquids royalties were lower as a percentage of natural gas liquids revenues in the fourth quarter of 2014 due to changes to the Alberta natural gas liquids reference price structure effective July 1, 2014, in addition to the impact of Bonavista's renegotiation of the applicable freehold royalty rate on lands in the West Central core area in the second quarter of 2014. Royalties for the three months ended December 31, 2014 were $27.3 million, a 9% decrease from $30.1 million for the same period in 2013, despite relatively unchanged production revenue over the same period. For the three months ended December 31, 2014 royalties as a percentage of production revenues decreased to 11.2% when compared to 12.3% for the same period in 2013. The decrease in royalties on an absolute basis and as a percentage of production revenues are due to the same reasons as stated above. The following table highlights Bonavista's royalties by product for the three months and years ended December 31: Three months ended December 31 Years ended December 31 2014 2013 2014 2013 Natural gas ($/mcf): Royalties % of production revenues(1) Natural gas liquids ($/bbl): Royalties % of production revenues(1) Oil ($/bbl): Royalties % of production revenues(1) Total ($/boe): Royalties % of production revenues(1) 0.27 6.7% 6.52 17.6% 10.67 14.9% 3.46 11.2% 0.19 5.5% 9.51 19.3% 10.55 14.0% 4.36 12.3% 0.39 8.3% 8.64 17.5% 12.72 14.4% 4.83 12.3% 0.19 5.7% 9.78 20.5% 11.63 14.1% 4.65 12.9% (1) % of production revenues excludes gains and losses on financial instrument commodity contracts. Operating expenses - Operating expenses decreased 4% to $58.2 million in the fourth quarter of 2014 compared to $60.6 million in the fourth quarter of 2013. On a per boe basis operating costs decreased 16% to $7.38 per boe for the three months ended December 31, 2014 compared to $8.77 per boe in the same period in 2013. The decrease in operating costs on a per boe and absolute basis is largely due to Bonavista's strategic initiative of asset concentration, along with the cost savings realized through the divestiture of non-core higher cost assets. Cost efficiencies realized within Bonavista's core areas also contributed to the decrease in operating expenses both on an absolute and on a per boe basis in the fourth quarter of 2014 when compared to the same period in 2013. For the year ended December 31, 2014, operating expenses decreased 3% to $232.5 million compared to $239.2 million in the same period a year ago and on a per boe basis decreased 8% to $8.25 per boe, from $8.93 per boe in the same period in 2013. Factors contributing to the decrease in operating costs include a 5% increase in production volumes, disciplined cost control and improved operating efficiencies due to concentrated development within Bonavista's core areas and the disposition of higher cost non-core assets. BONAVISTA ENERGY CORPORATION Page 16 The following table highlights Bonavista's operating expenses by product for the three months and years ended December 31: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) Three months ended December 31 Years ended December 31 2014 1.05 9.31 11.39 7.38 2013 1.18 10.71 13.08 8.77 2014 1.16 10.16 12.27 8.25 2013 1.20 10.93 12.96 8.93 Transportation expenses - Transportation expenses for the year ended December 31, 2014 decreased 2% to $36.0 million compared to $36.6 million for the same period in 2013. For the year ended December 31, 2014, transportation costs on a per boe basis decreased 7% to $1.28 per boe from $1.37 per boe in the same period in 2013. The decrease was largely due to production growth with lower transportation expenses on a per boe basis in core areas and the disposition of higher cost, non-core properties throughout 2014. Transportation expenses for the three months ended December 31, 2014 increased 4% to $9.6 million compared to $9.2 million for the same period in 2013 primarily due to the 14% increase in production volumes. Transportation costs on a per boe basis decreased 9% to $1.21 per boe in the fourth quarter of 2014 compared to $1.33 per boe in the same period in 2013, for the same reasons noted above. The decrease was partially offset by increased natural gas liquids transportation as a result of changes made to contract terms effective for the contract year commencing April 1, 2014. The following table highlights Bonavista’s transportation costs by product for the three months and years ended December 31: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) Three months ended December 31 Years ended December 31 2014 0.22 0.67 1.53 1.21 2013 0.26 0.15 1.99 1.33 2014 0.24 0.59 1.71 1.28 2013 0.25 0.34 2.07 1.37 General and administrative expenses - General and administrative expenses, after overhead recoveries, increased 4% to $32.0 million for the year ended December 31, 2014 compared to $30.8 million for the year ended December 31, 2013. The increase in absolute general and administrative expenses for the year ended December 31, 2014, was largely the result of higher compensation costs. On a per boe basis, general and administrative expenses were relatively unchanged at $1.14 per boe and $1.15 per boe for the years ended December 31, 2014 and 2013 respectively. General and administrative expenses, after overhead recoveries, decreased 3% to $8.1 million for the three months ended December 31, 2014 from $8.4 million in the same period in 2013. On a per boe basis, general and administrative expenses decreased by 16% to $1.02 per boe for the three months ended December 31, 2014 compared to $1.21 per boe in the same prior year period. The decrease in general and administrative expenses on a per boe basis in the fourth quarter of 2014, when compared to the same 2013 period is largely the result of a 14% increase in production volumes. Share-based compensation expense, recognized in connection with Bonavista's option and incentive award programs, was $2.6 million and $20.4 million for the three months and year ended December 31, 2014 respectively, compared to $5.8 million and $23.9 million recognized in comparative 2013 periods. Depletion, depreciation, amortization and impairment - For the year ended December 31, 2014, depreciation, depletion, amortization and impairment expenses increased 92% to $670.5 million from $349.3 million for the same period in 2013, as a result of a $300 million impairment charge recorded for the year ended December 31, 2014 (December 31, 2013 - nil) and to a lesser extent the impact of a 5% increase in production volumes. For the year ended December 31, 2014, the average charge was $23.79 per boe compared to $13.04 per boe for the same period in 2013. The impairment recorded was a result of declining forward commodity prices for oil, natural gas, and natural gas liquids as at January 1, 2015 as compared to January 1, 2014, as prepared by Bonavista's independent reserve evaluator. As a result of the significant decline in the commodity price environment, Bonavista tested each of its CGUs for impairment at December 31, 2014. This test resulted in Bonavista recording impairments in its British Columbia, Southern Alberta, Central Alberta and Eastern Alberta CGUs. The impairment included Bonavista's goodwill of $11.2 million recorded in the Central Alberta CGU. BONAVISTA ENERGY CORPORATION Page 17 Depletion, depreciation, amortization, and impairment expenses increased 346% to $404.9 million for the three months ended December 31, 2014, compared to $90.8 million for the three months ended December 31, 2013, due to a 14% increase in production volumes as well as the impact of the impairment charge discussed above. On a per boe basis the average expense recognized for depletion, depreciation, amortization and impairment in the fourth quarter of 2014 was $51.29 per boe compared to $13.15 per boe recognized in the same period in 2013. Excluding the impact of the impairment charge recognized for the year ended December 31, 2014, Bonavista's depreciation, depletion and amortization expenses increased 6% to $370.5 million from $349.3 million for the same period in 2013, due to a 5% increase in production volumes. On a per boe basis the average expense recognized for depletion, depreciation and amortization for the year ended December 31, 2014, was $13.15 per boe compared to $13.04 per boe in the same period in 2013. For the three months ended December, 31, 2014, depreciation, depletion and amortization expenses, excluding the impact of the impairment charge, increased 16% to $104.9 million compared to $90.8 million for the three months ended December 31, 2013, due to a 14% increase of production volumes. On a per boe basis the average expense recognized for depletion, depreciation and amortization for the three months ended December 31, 2014, increased 3% to $13.29 per boe from $13.15 per boe in the same period in 2013. Net financing costs - Net financing costs increased 26% to $119.6 million for the year ended December 31, 2014, from $94.7 million for the same period in 2013. The increase can be largely attributable to an increase in unrealized foreign exchange losses associated with the revaluation of Bonavista's US dollar denominated senior unsecured notes. Similarly, for the year ended December 31, 2014, net financing costs on a per boe basis increased 20% to $4.24 per boe compared to $3.53 per boe for the same period in 2013, for the reason stated above. Net financing costs, excluding non-cash amounts, increased 5% to $43.9 million for the year ended December 31, 2014, compared to $42.0 million for the year ended December 31, 2013. The increase in net financing costs, excluding non-cash amounts, is the result of higher interest costs associated with the translation of US dollar interest on our US denominated senior unsecured notes as a result of a weaker Canadian dollar. However as a result of a 5% increase in production volumes, net financing costs, excluding non-cash amounts, on a per boe basis were relatively unchanged at $1.56 per boe for the year ended December 31, 2014 compared to $1.57 per boe in the same period in 2013. For the three months ended December 31, 2014 net financing costs of $39.5 million was recognized compared to net financing costs of $37.0 million recognized in the same period in 2013. The period over period change can be largely attributed to fluctuations in unrealized foreign exchange gains and losses associated with the revaluation of Bonavista's US dollar denominated senior unsecured notes. For the three months ended December 31, 2014, net financing costs on a per boe basis were 7% lower at $5.00 per boe compared to net financing costs of $5.35 per boe in the same period in 2013. Net financing costs, excluding non-cash amounts, remained consistent at $11.1 million for the three months ended December 31, 2014 compared to $11.1 million for the three months ended December 31, 2013. However as a result of a 14% increase in production volumes, net financing costs, excluding non-cash amounts, on a per boe basis were 13% lower at $1.40 per boe for the three months ended December 31, 2014 compared to $1.60 per boe in the same period in 2013. Deferred income taxes - The deferred income tax recovery for the three months ended December 31, 2014 was $6.1 million compared to a provision of $1.2 million recorded during the same period in 2013. For the year ended December 31, 2014, the provision for deferred income taxes was $34.3 million compared to $24.0 million recorded during the same period in 2013. The deferred income tax recovery for the three months and the deferred income tax provision for the year ended December 31, 2014 was higher than the provision calculated using the expected statutory rate primarily due to the income tax treatment of net foreign currency translation losses on Bonavista's US denominated senior unsecured notes and financial instrument contracts and the income tax treatment of non-deductible share-based compensation expense. Bonavista made no cash payments or tax installments for the three months and year ended December 31, 2014 or for the comparative periods in 2013. Funds from operations, net income (loss) and comprehensive income (loss) - For the year ended December 31, 2014, Bonavista experienced a 17% increase in funds from operations to $561.1 million ($2.69 per share, basic) from $477.6 million ($2.42 per share, basic) for the same period in 2013. Net income and comprehensive income for the year ended December 31, 2014, decreased 90% to $4.8 million ($0.02 per share, basic) compared to net income and comprehensive income of $49.5 million ($0.25 per share, basic) for the same period in 2013. Net income for the year ended December 31, 2014, decreased when compared to the same 2013 period as a result of increased unrealized foreign exchange losses, realized losses on financial instrument commodity contracts and the impact of the year end impairment charge recorded. Offsetting these expenses was a 15% increase in production revenues and a $123.6 million unrealized gain on the fair market valuation of financial instrument commodity contracts. For the three months ended December 31, 2014, funds from operations increased 9% to $135.8 million ($0.63 per share, basic) from $124.4 million ($0.62 per share, basic) for the same period in 2013. The increase reflects a 15% reduction in cash costs on a per boe basis resulting from Bonavista's asset concentration strategy and continued focus on finding operational efficiencies across our business. Net loss and comprehensive loss for the three months ended December 31, 2014, was $61.0 million ($(0.28) per share, basic) compared to net income and comprehensive income of $6.7 million ($0.03 per share, basic) for the same period in 2013. The decrease was largely due to a net gain of $190.6 million on financial instrument commodity contracts offset by the $300 million year end impairment charge. BONAVISTA ENERGY CORPORATION Page 18 The following table is a reconciliation of a non-IFRS measure, funds from operations, to its nearest measure prescribed by IFRS: Calculation of Funds From Operations: 2014 2013 2014 2013 Three months ended December 31 Years ended December 31 ($ thousands) Cash flow from operating activities Interest expense Decommissioning expenditures Changes in non-cash working capital Funds from operations 139,349 (11,060) 9,944 (2,388) 135,845 115,021 (11,076) 10,539 9,870 124,354 593,824 (43,921) 32,026 (20,824) 561,105 486,605 (42,000) 30,143 2,830 477,578 Capital expenditures - Capital expenditures for the year ended December 31, 2014 were predominately focused on the development of Bonavista's key plays in the Deep Basin and West Central core areas. Capital expenditures on exploration and development activities were 44% higher for the year ended December 31, 2014 at $639.6 million compared to a $443.8 million for the same period in 2013. Proceeds received on the disposition of non-core properties totaled $293.4 million and $98.0 million respectively, for the years ended December 31, 2014 and 2013. Business and other acquisitions for the years ended December 31, 2014 and 2013 were largely focused on the development of Bonavista' Deep Basin core area in west Central Alberta. For the year ended December 31, 2014, business and other acquisitions were $186.6 million compared to $118.6 million in the same 2013 period. Head office capital expenditures were 51% lower for the year ended December 31, 2014 at $3.0 million compared to $6.2 million in the same 2013 period. Capital expenditures for the three months ended December 31, 2014 were $74.7 million, consisting of $162.2 million on exploration and development activities, $11.6 million spent on business and other acquisitions, head office expenditures of $449,000, net of property dispositions of $99.4 million. For the same period in 2013, net capital expenditures were $118.5 million, consisting of $111.6 million spent on exploration and development activities, $45.1 million spent on business and other acquisitions, head office capital expenditures of $2.1 million, net of property dispositions of $40.3 million. The following table outlines capital expenditures by category for the three months and years ended December 31: ($ thousands) Land acquisitions Geological and geophysical Drilling completion Production equipment and facilities Exploration and development expenditures Cash used for business and other acquisitions Cash received from dispositions Head office expenditures Net capital expenditures Three months ended December 31 Years ended December 31 2014 2013 2014 2013 14,816 1,576 115,642 30,121 162,155 11,580 (99,448) 449 74,736 11,952 1,544 72,412 25,688 111,596 32,231 (27,416) 2,066 118,477 29,391 14,837 442,237 153,095 639,560 186,608 (293,385) 3,018 535,801 24,825 13,780 308,354 96,870 443,829 118,559 (98,029) 6,183 470,542 BONAVISTA ENERGY CORPORATION Page 19 Liquidity and capital resources - As at December 31, 2014, long-term debt, including working capital (excluding associated assets and liabilities from financial instrument commodity contracts and decommissioning liabilities) was $1.1 billion with a debt to fourth quarter 2014 annualized funds from operations ratio of 2.1:1. ($ thousands) Current portion of senior unsecured notes Long-term portion Bank credit facility Senior unsecured notes Total current and long-term debt December 31, 2014 December 31, 2013 50,000 — 154,368 835,303 1,039,671 229,323 816,854 1,046,177 As at December 31, 2014, Bonavista bank debt was $154.4 million bearing a weighted average interest rate of 3.2% (December 31, 2013 - 3.1%) and maturity date of September 10, 2018. As at December 31, 2014, Bonavista had approximately $442.8 million of unused borrowing capacity on its $600 million bank credit facility. Bonavista's senior unsecured notes totaled $885.3 million as at December 31, 2014 which consists of US$705.0 million (CDN$815.3 million) and CDN$70.0 million of which CDN$50.0 million becomes due on November 2, 2015. Bonavista's senior unsecured notes bear fixed interest rates, with the weighted average being 4.1% for the years ended December 31, 2014 and 2013. The senior unsecured notes have a six year weighted average life with the majority of the debt repayments due in 2019 and thereafter. On September 10, 2014, Bonavista amended and renewed its existing bank credit facility of $600 million provided by a syndicate of 11 domestic and international banks to a maturity date of September 10, 2018. Under the terms of the amended bank credit facility, Bonavista's consolidated senior debt borrowing is not to 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. On July 10, 2014, the Corporation completed a bought deal financing (the "Offering") for net proceeds of approximately $192 million. Pursuant to the Offering, the Corporation, through a syndicate of underwriters, issued 12.1 million common shares at a price of $16.60 per common share. The proceeds from the offering were used to repay the indebtedness incurred under the Corporation's bank credit facility and used to fund the $141 million purchase of the natural gas weighted assets in the Ansell area of our Deep Basin Core area on July 7, 2014. In spite of a year of continued operational success, the decline in world commodity prices has resulted in a challenging environment for the North American energy sector. Bonavista remains focused on creating value for its shareholders by consistently aligning the capital program and dividends with funds from operations. For 2015, Bonavista plans to invest between $300 and $320 million on its capital program within its core regions, representing a 42% decrease from 2014. On January 15, 2015, Bonavista reduced its monthly dividend from $0.07 per share to $0.035 per share. The revisions to the dividend and capital program align with the recently transformed commodity price environment and our goal to maintain a disciplined total payout ratio of between 100% and 110% in this environment. Bonavista remains committed to the fundamental principles associated with a sustainable business plan which includes maintaining financial flexibility and the prudent use of debt. Shareholders’ equity - As at December 31, 2014, Bonavista had 215.9 million equivalent common shares outstanding. This includes 9.5 million exchangeable shares, which are exchangeable into 12.2 million common shares. The exchange ratio in effect at December 31, 2014 for exchangeable shares was 1.28262:1. As at February 26, 2015, Bonavista had $216.5 million equivalent common shares outstanding. This includes 8.8 million exchangeable shares, which are exchangeable into 11.4 million common shares. The exchange ratio in effect at February 26, 2015 for exchangeable shares was 1.30251:1. In addition, Bonavista has 7.6 million stock option and common share incentive rights outstanding as at February 26, 2015, with an average exercise price of $17.80 per common share. Dividends - For the year ended December 31, 2014, Bonavista declared dividends of $164.8 million ($0.84 per share) compared to $153.0 million ($0.84 per share) in the same period in 2013. For the three months ended December 31, 2014, Bonavista declared dividends of $42.8 million ($0.21 per share) compared to $38.9 million ($0.21 per share) in the same period in 2013. Bonavista announces its dividend policy on a quarterly basis and confirms its dividend payment on a monthly basis. Dividends are approved by the Board of Directors and are dependent upon the commodity price environment, production levels and the amount of capital expenditures to be financed from funds from operations. On May 1, 2014, Bonavista’s Board of Directors approved the suspension of the dividend reinvestment and stock dividend plans beginning with the May dividend payable on June 16, 2014 and thereafter. Reinstatement of these plans in 2015 and thereafter will be dependent on future commodity pricing, operational performance and financial flexibility. The goal of Bonavista’s business model remains consistent with a commitment to generate an attractive return to shareholders through a sustainable balance between dividends and corporate growth. Targeting a dividend rate between 15% and 25% of funds from operations will allow the Corporation to withhold sufficient funds to finance capital expenditures required to modestly grow the production base over the long-term, assuming current strip pricing is realized. BONAVISTA ENERGY CORPORATION Page 20 Annual financial information - The following table highlights selected annual financial information for each of the three years ended December 31, 2014, 2013 and 2012: Years ended December 31 ($ thousands, except per share amounts) 2014 2013 2012 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(1) Long-term debt Shareholders' equity Dividends declared (1) Excluding decommissioning liabilities. 970,757 561,105 2.69 2.66 4,847 0.02 0.02 535,801 4,429,402 (27,173) 989,671 2,357,706 164,750 839,823 477,578 2.42 2.40 49,505 0.25 0.25 470,542 4,235,626 (109,587) 1,046,177 2,270,015 152,968 708,191 378,667 2.16 2.14 64,202 0.37 0.36 394,440 4,062,852 (74,607) 889,071 2,285,889 224,801 Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly periods ending on December 31, 2012 to December 31, 2014: December 31 September 30 2014 June 30 March 31 2013 December 31 September 30 June 30 March 31 ($ thousands, except per share amounts) Production revenues Net income (loss) Basic Diluted 244,612 (60,978) (0.28) (0.28) 259,678 24,186 0.11 0.11 287,529 86,576 0.43 0.42 315,033 (44,937) (0.22) (0.22) 245,466 6,667 0.03 0.03 246,413 22,950 0.12 0.11 244,940 23,107 0.12 0.12 227,493 (3,219) (0.02) (0.02) Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and changes in production volumes. Net income (loss) in the past eight quarters has fluctuated from a deficit of $61.0 million in the fourth quarter of 2014 to net income of $86.6 million in the second quarter of 2014. These fluctuations are primarily influenced by production volumes, commodity prices, realized and unrealized gains and losses on financial instrument commodity contracts, unrealized gains and losses on the revaluation of Bonavista's US dollar denominated senior unsecured notes and impairment charges. 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 designed, or caused to be designed under their supervision, disclosure controls and procedures, as defined by National Instrument 52-109 Certification, to provide reasonable assurance that (i) material information relating to the Corporation is made known to the Corporation’s Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are prepared; and (ii) information required to be disclosed by the Corporation in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. All control systems by their nature have inherent limitations and, therefore, the Corporation’s disclosure controls and procedures are believed to provide reasonable, but not absolute, assurance that the objectives of the control system are met. Internal control over financial reporting - The Corporation’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting, as defined by National Instrument 51-109. Internal controls 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. There were no changes made to Bonavista’s internal controls over financial reporting during the period beginning on January 1, 2014 and ending on December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Corporation’s internal controls over financial reporting. In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") issued an updated Internal Control-Integrated Framework (“2013 Framework”) replacing the Internal Control - Integrated Framework (1992). Bonavista adopted the 2013 Framework for the year ended December 31, 2014. BONAVISTA ENERGY CORPORATION Page 21 New accounting policies - On January 1, 2014, Bonavista adopted the following new standards and amendments in accordance with the transition provisions of each standard, which became effective for annual periods on or after January 1, 2014: • Amendments to IAS 36, "Impairment of Assets," the retrospective adoption of these amendments did not impact Bonavista's disclosures in the notes of the consolidated financial statements. There will be an impact to Bonavista's disclosures in the notes to its consolidated financial statements and condensed consolidated interim financial statements in periods when an impairment loss or impairment reversal is recognized. • Amendments to the recognition, presentation and disclosure to pension accounting under IAS 19, "Employee Benefits". The adoption of this amendment had no impact on Bonavista's consolidated financial statements. • IFRIC 21, "Levies," the adoption of this standard had no impact on the amounts recorded in Bonavista's consolidated financial statements. Future accounting policies - In May 2014, the IASB issued IFRS 15, "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. The new standard is effective for annual periods beginning on or after January 1, 2017 with earlier adoption permitted. Bonavista intends to adopt IFRS 15 in its financial statements for the annual period beginning on January 1, 2017. The extent of the impact of adoption of the standard has not yet been determined. On July 24, 2014, the IASB issued the complete IFRS 9, "Financial Instruments" to replace IAS 39, "Financial Instruments: Recognition and Measurement". IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. Bonavista is currently evaluating the impact of adopting IFRS 9 on the consolidated 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. The timely preparation of Bonavista’s financial statements requires management to make certain judgments, estimates and assumptions. These estimates and judgments are subject to changes and actual results could differ from those estimated. Significant judgments and estimates made by management in the preparation of the financial statements are outlined below. • Determination of a Cash Generating Unit (“CGU”) - The determination of Bonavista’s CGUs is subject to management’s judgment. In determining Bonavista’s CGUs management assessed what constituted independent cash flows and how to aggregate the respective assets. The asset composition of each CGU can directly impact the assessment of the recoverability of those assets included within each CGU. During the first quarter of 2014, Bonavista re-aligned certain CGUs with its asset base as a result of ongoing divestiture activity. • Impairment testing - Bonavista assesses its property, plant and equipment for impairment when events or circumstances indicate that the carrying amount 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 carrying amount of each CGU is compared to its recoverable amount which is defined as the greater of its fair value less cost to sell and value in use and is subject to management estimates. Key estimates used in the determination of these cash flows include: quantities of reserves and future production; future commodity pricing; development costs; operating costs; royalty obligations; and discount rates. Any changes in these estimates may have an impact on the recoverable amount of the CGU. Proved plus 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. • 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 plus probable reserves for each CGU. The unit-of-production method takes into account estimates of capital expenditures incurred to date along with future development capital required to develop both proved plus probable reserves. • Decommissioning liability - The provision for decommissioning liabilities is based on management's 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. • 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. BONAVISTA ENERGY CORPORATION Page 22 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. The Consolidated Financial Statements have been audited by KPMG LLP, the external auditors, in accordance with auditing standards generally accepted in Canada on behalf of the shareholders. 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 February 26, 2015 Calgary, Alberta BONAVISTA ENERGY CORPORATION Page 23 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, 2014 and December 31, 2013, 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, 2014 and December 31, 2013, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards. Chartered Accountants February 26, 2015 Calgary, Canada BONAVISTA ENERGY CORPORATION Page 24 Note 2014 2013 BONAVISTA ENERGY CORPORATION Consolidated Statements of Financial Position As at December 31 ($ 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 Total assets Liabilities and Shareholders’ Equity Current liabilities Accounts payable and accrued liabilities Current portion of long-term debt Decommissioning liabilities Dividends payable Financial instrument commodity contracts (4) (4) (4) (8) (9) (9) (12) (13) (4) Financial instrument commodity contracts (4) Long-term debt Other long-term liabilities Decommissioning liabilities Deferred income taxes Shareholders’ equity Shareholders’ capital Exchangeable shares Contributed surplus Deficit Commitments Total liabilities and shareholders' equity (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 102,840 9,525 814 19,358 140,271 272,808 17,680 16,025 3,933,396 189,493 — 4,429,402 234,025 50,000 15,185 14,263 1,693 315,166 2,385 989,671 12,412 482,797 269,265 124,431 7,322 2,645 13,786 419 148,603 346 8,023 3,845,344 222,085 11,225 4,235,626 213,118 — 9,313 13,087 31,985 267,503 3,710 1,046,177 13,853 397,174 237,194 2,071,696 1,965,611 2,514,006 272,900 57,613 (486,813) 2,357,706 2,228,210 307,468 61,247 (326,910 ) 2,270,015 4,429,402 4,235,626 Ian S. Brown, Director Michael M. Kanovsky, Director BONAVISTA ENERGY CORPORATION Page 25 BONAVISTA ENERGY CORPORATION Consolidated Statements of Income and Comprehensive Income For the years ended December 31 ($ thousands, except per share amounts) Revenues Production Royalties Realized losses on financial instrument commodity contracts Unrealized gains (losses) on financial instrument commodity contracts (4) (4) Expenses Operating Transportation General and administrative Share-based compensation Gain on disposition of property, plant and equipment Loss (gain) on disposition of exploration and evaluation assets Depletion, depreciation, amortization and impairment 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 Diluted See accompanying notes to the consolidated financial statements. (8) (6) (6) (14) Note 2014 2013 1,106,852 (136,095) 970,757 (65,232) 188,803 1,094,328 232,474 36,013 32,012 20,449 (61,780) 5,903 670,510 935,581 158,747 127,579 (8,002) 119,577 39,170 34,323 4,847 0.02 0.02 964,312 (124,489) 839,823 (13,652) (34,426) 791,745 239,196 36,595 30,802 23,868 (38,115) (18,143) 349,285 623,488 168,257 98,439 (3,730) 94,709 73,548 24,043 49,505 0.25 0.25 BONAVISTA ENERGY CORPORATION Page 26 BONAVISTA ENERGY CORPORATION Consolidated Statements of Changes in Equity For the years ended December 31 ($ thousands) Balance as at December 31, 2012 Net income Issue costs, net of future tax benefit Issued for cash on exercise of stock options and 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 Shareholders' Capital Exchangeable Shares Contributed Surplus Deficit Total Shareholders’ Equity 2,059,305 405,183 44,848 (223,447) 2,285,889 — (74) 1,984 2,708 7,410 — — 59,162 97,715 — — — — — — — — — (97,715) — — — — (2,708) (7,410) 23,868 2,649 — — 49,505 — — — — — — — — 49,505 (74) 1,984 — — 23,868 2,649 59,162 — — (152,968) (152,968) Balance as at December 31, 2013 2,228,210 307,468 61,247 (326,910) 2,270,015 Net income Issuance of equity Issue costs, net of future tax benefit Issued for cash on exercise of stock options and common share incentive rights Exercise of stock options and common share incentive rights Conversion of incentive and restricted share awards Tax effect on conversion of incentive 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 — 200,860 (6,280) 4,154 4,550 21,721 148 — — 26,075 34,568 — — — — — — — — — — — (34,568) — — — — — (4,550) (21,721) — 20,449 2,188 — — 4,847 — — — — — — — — — — 4,847 200,860 (6,280) 4,154 — — 148 20,449 2,188 26,075 — — (164,750) (164,750) Balance as at December 31, 2014 2,514,006 272,900 57,613 (486,813) 2,357,706 See accompanying notes to the consolidated financial statements. BONAVISTA ENERGY CORPORATION Page 27 BONAVISTA ENERGY CORPORATION Consolidated Statements of Cash Flows For the years ended December 31 ($ thousands) Cash provided by (used for) Operating Activities Net income Adjustments for: Depletion, depreciation, amortization and impairment Share-based compensation Unrealized (gains) losses on financial instrument commodity contracts Gain on disposition of property, plant and equipment Loss (gain) on disposition of exploration and evaluation assets Net finance costs Deferred income taxes Decommissioning expenditures Changes in non-cash working capital items Financing Activities Issuance of senior notes Issuance of equity, net of issue costs Proceeds on exercise of stock options and common share incentive rights Dividends paid Interest paid Repayment of long-term debt Investing Activities Business acquisition Exploration and development Other acquisitions Property dispositions Office equipment Changes in non-cash working capital items Change in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year See accompanying notes to the consolidated financial statements. Note 2014 2013 4,847 49,505 670,510 20,449 (188,803) (61,780) 5,903 119,577 34,323 (32,026) 20,824 593,824 349,285 23,868 34,426 (38,115) (18,143) 94,709 24,043 (30,143) (2,830) 486,605 — 229,226 192,476 4,154 (137,499) (43,550) (75,827) (60,246) (141,062) (639,560) (45,546) 289,385 (3,018) 6,223 (99) 1,984 (102,022) (40,793) (116,179) (27,883) (102,284) (443,829) (16,275) 98,029 (6,183) 11,820 (533,578) (458,722) — — — — — — (7) (10) (10) (7) BONAVISTA ENERGY CORPORATION Page 28 BONAVISTA ENERGY CORPORATION Notes to the Consolidated Financial Statements For the year ended December 31, 2014 and 2013 Structure of the Corporation and Basis of Presentation The principal undertakings of Bonavista Energy Corporation, (“Bonavista” or the “Corporation”) are to carry on the business of acquiring, developing and holding interests in oil and natural gas properties and assets in Western Canada. Bonavista's principal place of business is located at 1500, 525 - 8th Avenue SW, Calgary, Alberta, Canada T2P 1G1. The consolidated financial statements of the Corporation as at and for the year ended December 31, 2014, are available through our filings on SEDAR at www.sedar.com or can be obtained from Bonavista’s website at www.bonavistaenergy.com. 1. Basis of Presentation 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 February 26, 2015. Basis of measurement The consolidated financial statements have been prepared on the historical cost basis except for derivative financial instruments which are measured at fair value. Functional and presentation currency These consolidated financial statements are presented in Canadian dollars, which is the Corporation's functional currency. Use of management’s judgments and estimates 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 Bonavista'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. Determination of a Cash Generating Unit (“CGU”) The determination of Bonavista’s CGUs is subject to management’s judgment. In determining Bonavista’s CGUs, management assessed what constituted independent cash flows and how to aggregate the respective assets. The asset composition of each CGU can directly impact the assessment of the recoverability of those assets included within each CGU. During the first quarter of 2014, Bonavista re-aligned certain CGUs with its asset base as a result of ongoing divestiture activity. ii. Impairment testing Bonavista assesses its property, plant and equipment for impairment when events or circumstances indicate that the carrying amount 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 carrying amount of each CGU is compared to its recoverable amount which is defined as the greater of its fair value less cost to sell and value in use and is subject to management estimates. As at December 31, 2014, Bonavista evaluated each of its CGUs for indicators of impairment. In performing this evaluation, management used the net present values for each CGU. Key estimates used in the determination of these cash flows include: quantities of reserves and future production; future commodity pricing; development costs; operating costs; royalty obligations; and discount rates. Any changes in these estimates may have an impact on the recoverable amount of the CGU. BONAVISTA ENERGY CORPORATION Page 29 iii. Proved plus 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. iv. 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 plus probable reserves for each CGU. The unit-of-production method takes into account estimates of capital expenditures incurred to date along with future development capital required to develop both proved plus probable reserves. v. Decommissioning liability The provision for decommissioning liabilities is based on management's 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. vi. 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. 2. Significant accounting policies Basis of consolidation The consolidated financial statements comprise the financial statements of the Corporation and its subsidiaries as at December 31, 2014. Subsidiaries are consolidated from the date of acquisition, being the date on which Bonavista obtains control, and continues to be consolidated until the date that control ceases. Control exists when Bonavista 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 Bonavista's oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include Bonavista's share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. 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. Financial instruments i. Non-derivative financial assets Bonavista 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 date at which Bonavista 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 Bonavista is recognized as a separate asset or liability. Financial assets and liabilities are offset and the net amount is presented in the statement of consolidated financial position when, and only when, Bonavista 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. Bonavista 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 Bonavista manages such investments and makes purchase and sale decisions based on their fair value in accordance with Bonavista's documented risk management or investment strategy. Attributable transaction costs are recognized in profit or loss as incurred. BONAVISTA ENERGY CORPORATION Page 30 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. ii. Non-derivative financial liabilities Bonavista 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 Bonavista becomes a party to the contractual provisions of the instrument. Bonavista derecognizes a financial liability when its contractual obligations are discharged, cancelled or expired. Bonavista 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 Bonavista' 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 Bonavista 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. Bonavista 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. Bonavista 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. Exploration and evaluation assets and property, plant and equipment 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 are initially 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. BONAVISTA ENERGY CORPORATION Page 31 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. Annually, a review of each exploration licence or field is carried out, 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. 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 on a net basis within “gains (losses) on disposition of property, plant and equipment” in the consolidated statement of income. 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. 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 plus 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 plus 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 plus probable and a 50% statistical probability that it will be less. The equivalent statistical probabilities for the proven component of proved plus 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 plus 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. The estimated useful lives for certain production assets for the current and comparative years are as follows: Facilities 15 years Oil and natural gas properties 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 Bonavista will obtain ownership by the end of the lease term. BONAVISTA ENERGY CORPORATION Page 32 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. Goodwill and Exploration and evaluation assets 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. Exploration and evaluation assets Other intangible assets that are acquired by Bonavista, 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. Impairment 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. 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. Non-financial assets The carrying amounts of Bonavista'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. An impairment test is completed each year for goodwill and other intangible assets that have indefinite lives or that are not yet available for use. 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. 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 plus 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. BONAVISTA ENERGY CORPORATION Page 33 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. Employee benefits Share-based compensation Long-term incentives are granted to officers, directors, employees and certain consultants in accordance with Bonavista's stock option, incentive award 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 incentive awards and 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 conversion of the restricted share awards or the settlement of the incentive awards by common shares, on the predetermined vesting dates, the value in contributed surplus pertaining to the 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. 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 Bonavista 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. 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. Provisions A provision is recognized if, as a result of a past event, Bonavista 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. Decommissioning liabilities Bonavista'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. Revenues Revenues from the sale of oil, natural gas and natural gas liquids 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. 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. BONAVISTA ENERGY CORPORATION Page 34 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. Net income per share Basic net income per share is calculated by dividing the profit or loss attributable to common shareholders of Bonavista 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 policies Changes in accounting policies On January 1, 2014, Bonavista adopted the following new standards and amendments in accordance with the transition provisions of each standard, which became effective for annual periods on or after January 1, 2014: • • • Amendments to IAS 36, "Impairment of Assets," the retrospective adoption of these amendments did not impact Bonavista's disclosures in the notes of the consolidated financial statements. There will be an impact to Bonavista's disclosures in the notes to its consolidated financial statements and condensed consolidated interim financial statements in periods when an impairment loss or impairment reversal is recognized. Amendments to the recognition, presentation and disclosure to pension accounting under IAS 19, "Employee Benefits". The adoption of this amendment had no impact on Bonavista's consolidated financial statements. IFRIC 21, "Levies," the adoption of this standard had no impact on the amounts recorded in Bonavista's consolidated financial statements. Future accounting policies • In May 2014, the IASB issued IFRS 15, "Revenue from Contracts with Customers," which replaces IAS 18 "Revenue," IAS 11 "Construction Contracts," and related interpretations. The new standard is effective for annual periods beginning on or after January 1, 2017 with earlier adoption permitted. Bonavista intends to adopt IFRS 15 in its financial statements for the annual period beginning on January 1, 2017. The extent of the impact of adoption of the standard has not yet been determined. • On July 24, 2014, the IASB issued the complete IFRS 9, "Financial Instruments" to replace IAS 39, "Financial Instruments: Recognition and Measurement". IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. Bonavista is currently evaluating the impact of adopting IFRS 9 on its consolidated financial statements. BONAVISTA ENERGY CORPORATION Page 35 4. Financial risk management Bonavista is exposed to certain market risks that are part of its normal course of business. These market risks include commodity price risk, interest rate risk and foreign exchange risk. To manage its exposure to these market risks, Bonavista has a risk management program in place which includes financial instruments as disclosed in the commodity price risk and foreign exchange risk sections of this note. The objective of Bonavista's risk management program is to mitigate exposure to fluctuations in commodity prices, interest rates and foreign exchange rates to reduce volatility in the Corporation's funds from operations. Commodity price risk Bonavista is exposed to commodity price risk as prices received for its oil and natural gas production fluctuate. Commodity prices fluctuate as a result of a number of local and global factors including, supply and demand, inventory levels, weather patterns, pipeline transportation constraints, political stability and economic factors. Bonavista mitigates a portion of the commodity price risk through the use of various financial instrument commodity contracts and physical delivery sales contracts. Bonavista's policy is to enter into commodity price contracts when considered appropriate to a maximum of 70% of the current year's budgeted revenues, net of royalties and 60% thereafter, provided that no more than 80% of forecasted revenues, net of royalties, from any one product may be hedged, or in the case of electricity, 60% of Bonavista's forecasted 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. Bonavista's management regularly reviews this policy to reflect changes in market conditions. Financial instrument commodity contracts As at December 31, 2014, Bonavista entered into the following costless collars to sell oil and natural gas: Volume Average Price Term 5,000 gjs/d CDN $3.50 - CDN $4.00 - AECO January 1, 2015 - March 31, 2015 5,000 gjs/d CDN $3.75 - CDN $4.29 - AECO January 1, 2015 - September 30, 2015 65,000 gjs/d CDN $3.50 - CDN $3.95 - AECO January 1, 2015 - December 31, 2015 10,000 gjs/d CDN $3.75 - CDN $4.26 - AECO January 1, 2016 - March 31, 2016 20,000 gjs/d CDN $3.69 - CDN $4.04 - AECO January 1, 2016 - December 31, 2016 10,000 gjs/d CDN $3.75 - CDN $4.20 - AECO January 1, 2017 - December 31, 2017 5,000 bbls/d CDN $89.60 - CDN $98.47 - WTI January 1, 2015 - December 31, 2015 500 bbls/d US $90.00 - US $100.40 - WTI January 1, 2015 - December 31, 2015 10,550 gjs/d US $3.90 - US $4.43 - NYMEX January 1, 2016 - March 31, 2016 Subsequent to December 31, 2014, Bonavista entered into the following costless collars to sell natural gas: Volume Average Price Term 15,000 gjs/d CDN $3.00 - CDN $3.29 - AECO January 1, 2016 - December 31, 2017 As at December 31, 2014, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume Price 10,000 gjs/d CDN $3.60 120,000 gjs/d CDN $3.70 20,000 gjs/d CDN $3.32 5,000 gjs/d CDN $3.81 15,000 gjs/d CDN $3.75 Contract Swap - AECO Swap - AECO Swap - AECO Swap - AECO Swap - AECO Term January 1, 2015 - March 31, 2015 January 1, 2015 - December 31, 2015 April 1, 2015 - December 31, 2016 November 1, 2015 - March 31, 2016 January 1, 2016 - December 31, 2016 10,550 gjs/d US $4.00 Swap - NYMEX January 1, 2015 - December 31, 2015 26,375 gjs/d US $(0.42) 2,500 bbls/d US 49.3% 2,500 bbls/d US 46.2% 1,000 bbls/d US $8.38 (1) Conway propane price as a percentage of WTI. Swap - AECO Basis Swap - CNWY PN/WTI(1) Swap - CNWY PN/WTI(1) Swap - WTI-MSW January 1, 2015 - December 31, 2015 January 1, 2015 - March 31, 2015 April 1, 2015 - March 31, 2016 January 1, 2015 - March 31, 2015 BONAVISTA ENERGY CORPORATION Page 36 Subsequent to December 31, 2014, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume Price 20,000 gjs/d CDN $2.70 40,000 gjs/d CDN $3.14 5,000 gjs/d CDN $2.90 1,000 bbls/d US 40% (1) Conway propane price as a percentage of WTI. Contract Swap - AECO Swap - AECO Term April 1, 2015 to October 31, 2015 January 1, 2016 - December 31, 2017 Swap - AECO Swap - CNWY PN/WTI(1) April 1, 2016 - October 31, 2016 April 1, 2016 - March 31, 2017 As at December 31, 2014, Bonavista entered into the following contracts to purchase electricity: Volume 6 5 1 mwh mwh mwh Price CDN $50.88 CDN $51.60 CDN $52.50 Contract Swap - AESO Swap - AESO Swap - AESO Term January 1, 2015 - December 31, 2015 January 1, 2016 - December 31, 2016 January 1, 2017 - December 31, 2017 A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $10.4 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2014 (December 31, 2013 - $6.8 million). A $1.00 change in the price per barrel of oil - WTI would have an impact of approximately $2.1 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2014 (December 31, 2013 - $3.5 million). 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. As at December 31, 2014, the fair value recorded on the consolidated statement of financial position for these financial instrument commodity contracts was a net asset of $153.9 million (December 31, 2013 - net liability of $34.9 million). During the year ended December 31, 2014, a net gain of $123.6 million (December 31, 2013 - $48.1 million loss) was recorded in the consolidated statement of income and comprehensive income, consisting of a realized loss of $65.2 million (December 31, 2013 - $13.7 million loss) and an unrealized gain of $188.8 million (December 31, 2013 - $34.4 million loss). Physical purchase and sale contracts As at December 31, 2014, Bonavista entered into the following physical contracts to sell natural gas: Volume Price 30,000 gjs/d CDN $3.61 Contract AECO Term January 1, 2016 - December 31, 2016 Subsequent to December 31, 2014, Bonavista entered into the following physical contracts to sell natural gas: Volume Price 30,000 gjs/d CDN $2.87 Contract AECO Term April 1, 2015 - October 31, 2015 BONAVISTA ENERGY CORPORATION Page 37 Foreign exchange risk Bonavista is exposed to foreign currency fluctuations as oil and natural gas prices received are referenced to US dollar denominated prices. Bonavista has mitigated some of this foreign exchange risk by entering into fixed Canadian dollar oil and natural gas swaps as outlined in the commodity price risk section above. In addition, Bonavista has US dollar denominated senior unsecured notes and interest obligations of which future cash repayments are directly impacted by the Canadian dollar to the US dollar exchange rate. To fix the foreign exchange rate on a portion of the US dollar denominated senior unsecured notes, Bonavista entered into an agreement on July 21, 2011, to purchase US dollars at predetermined rates on settlement dates that coincide with Bonavista's US dollar debt repayment commitments. Settlement date November 2, 2017 November 2, 2020 November 2, 2022 Contract US$ 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 Holding all other variables constant, a $0.01 change in CDN$/US$ exchange rate would have an impact of approximately $861,000 on net income for those foreign exchange forward contracts in place as at December 31, 2014 (December 31, 2013 - $709,000). As at December 31, 2014, the fair value recorded on the consolidated statement of financial position for these financial instrument contracts was a long-term asset of $16.0 million, compared to a long-term asset of $8.0 million as at December 31, 2013. For the year ended December 31, 2014, an unrealized gain of $8.0 million was recorded on the consolidated statements of income and comprehensive income (December 31, 2013 - $3.7 million gain). Subsequent to December 31, 2014, Bonavista entered into agreements to further manage its exposure to foreign currency exchange fluctuations on its US dollar senior unsecured note repayments. Each agreement requires Bonavista to purchase US dollars at a predetermined rate and time which coincides directly with Bonavista's US dollar debt repayment commitments. Settlement date June 6, 2016 June 5, 2017 November 2, 2017 November 2, 2020 October 25, 2021 Interest rate risk Contract US$ purchased forward US$ purchased forward US$ purchased forward US$ purchased forward US$ purchased forward Notional US$ $12,500,000 $12,500,000 $30,000,000 $106,700,000 $150,000,000 CDN$/US$ 1.2220 1.2234 1.2228 1.2265 1.2297 Bonavista is exposed to interest rate risk on any amount outstanding on its Canadian bank credit facility. Bonavista manages interest rate risk by having both fixed interest rates on senior unsecured notes and floating interest rates on outstanding bank debt. Credit risk Credit risk is the risk of financial loss to Bonavista if a customer or counterparty to a financial instrument fails to meet its contractual obligation and arises, primarily from joint operations partners, marketers and financial intermediaries. Bonavista's accounts receivable are with customers and joint operations 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. Bonavista routinely assesses the financial strength of its customers. Bonavista may be exposed to certain losses in the event of non-performance by counterparties to financial instrument contracts. Bonavista 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, 2014 Bonavista’s receivables consisted of $72.2 million of receivables from oil and natural gas marketers of which substantially all has been collected subsequent to December 31, 2014 and $30.3 million from joint operations partners of which $15.1 million has been subsequently collected. As at December 31, 2014 Bonavista has $9.1 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 from joint operations partners, who are in default of amounts owing. Bonavista does not have an allowance for doubtful accounts as at December 31, 2014 and did not provide for any doubtful accounts during the year ended December 31, 2014. BONAVISTA ENERGY CORPORATION Page 38 Liquidity risk Liquidity risk is the risk that Bonavista will encounter difficulty in meeting obligations associated with the financial liabilities. Bonavista'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, Bonavista’s 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 two to seven 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. Bonavista also has a series of senior unsecured notes outstanding with fixed interest rates, as outlined in note 12, which range in maturities from November 2, 2015 to May 23, 2025. Bonavista also maintains and monitors a certain level of cash flow, which is used to partially finance all operating, investing and capital expenditures. Financial instrument classification and measurement Bonavista's financial instruments that are carried at fair value on the consolidated statements of financial position include marketable securities, financial instrument contracts and financial instrument commodity contracts. Bonavista classifies the fair value of these financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instrument. Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Level 3 – Valuation in this level are those with inputs for the asset or liabilities that are not based on observable market data. Bonavista's marketable securities have been classified as Level 1 measurements, and its financial instrument contracts, bank debt and senior unsecured notes are classified as Level 2 measurements. Bonavista does not have any fair value measurements classified as Level 3. The fair market value recorded on the consolidated statements of financial position for these financial instrument contracts were as follows: December 31, 2014 December 31, 2013 ($ thousands) Current assets Marketable securities(1) Financial instrument commodity contracts(2) Long-term assets Financial instrument commodity contracts(2) Financial instrument contracts(2) Current liabilities Financial instrument commodity contracts(2) Long-term liabilities Financial instrument commodity contracts(2) Net asset (liability) (1) (2) Level 1 Level 2 814 140,271 17,680 16,025 2,645 419 346 8,023 (1,693) (31,985) (2,385) 170,712 (3,710) (24,262) Bonavista's bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value. The fair market value of Bonavista's senior unsecured notes as at December 31, 2014 is approximately $924.5 million (December 31, 2013 - $789.2 million), compared to a carrying amount of $887.9 million (December 31, 2013 - $819.8 million). BONAVISTA ENERGY CORPORATION Page 39 5. Capital Management Bonavista's objective when managing capital is to maintain a flexible capital structure which allows it to provide a balance of growth and income to its shareholders, while ensuring financial strength and sustainability. Bonavista considers its capital structure to include working capital (excluding associated assets and liabilities from financial instrument contracts and decommissioning liabilities), bank debt, senior unsecured notes and shareholders' equity. Bonavista monitors capital based on the ratio of net debt to annualized funds from operations. The ratio represents the time period it would take to pay off the debt if no further capital expenditures were incurred and if funds from operations remained constant. This ratio is calculated as net debt, defined as outstanding bank debt, senior unsecured notes and working capital, divided by funds from operations for the most recent calendar quarter, annualized (multiplied by four). This ratio may increase at certain times as a result of acquisitions or low commodity prices. As at December 31, 2014, Bonavista’s ratio of net debt to fourth quarter annualized funds from operations was 2.1 to 1 (December 31, 2013 - 2.1 to 1). The following table reconciles funds from operations to its nearest measure prescribed by IFRS, cash flow from operating activities. Calculation of Funds from Operations ($ 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, 2014 Three months ended December 31, 2013 139,349 (11,060) 9,944 (2,388) 135,845 543,380 115,021 (11,076) 10,539 9,870 124,354 497,416 To facilitate the management of this ratio, Bonavista 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. 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. Bonavista 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. BONAVISTA ENERGY CORPORATION Page 40 6. Finance costs and income ($ thousands) Finance costs Accretion of decommissioning liabilities Accretion of other liabilities Interest on bank debt Interest on notes payable Unrealized loss on foreign exchange Unrealized loss on marketable securities Unrealized loss on financial instrument contracts Total finance costs Finance income Unrealized gain on financial instrument contracts Total finance income Net finance costs Year ended December 31, 2014 Year ended December 31, 2013 10,938 1,568 9,196 36,013 68,033 1,831 — 127,579 (8,002) (8,002) 119,577 10,566 1,691 13,347 30,339 42,373 123 — 98,439 (3,730) (3,730) 94,709 Bonavista's effective interest rate on its average bank debt outstanding for the year ending December 31, 2014 was approximately 3.2% compared to 3.1% for the year ending December 31, 2013. The average interest rate on Bonavista's senior unsecured notes for the year ending December 31, 2014 was 4.1% (December 31, 2013 - 4.1%). 7. Supplemented cash flow information ($ thousands) Cash provided by (used for): Accounts receivable Prepaid expenses Other assets Accounts payable and accrued liabilities, net of interest accrual Related to: Operating activities Investing activities Year ended December 31, 2014 Year ended December 31, 2013 18,954 (2,203) (7,231) 17,527 27,047 20,824 6,223 27,047 (21,931) 3,767 (1,595) 28,749 8,990 (2,830) 11,820 8,990 BONAVISTA ENERGY CORPORATION Page 41 8. Property, plant and equipment ($ thousands) Cost Oil and natural gas properties Facilities Other Assets Total Balance as at December 31, 2012 4,031,627 512,281 Additions Acquisitions Transfers from exploration and evaluation assets Changes in decommissioning liabilities Dispositions Balance as at December 31, 2013 Additions Acquisitions Transfers from exploration and evaluation assets Changes in decommissioning liabilities Dispositions Balance at December 31, 2014 Depletion, depreciation, amortization and impairment Balance as at December 31, 2012 Depletion, depreciation and amortization Dispositions Balance as at December 31, 2013 Depletion, depreciation, amortization and impairment Dispositions Balance at December 31, 2014 412,638 116,156 15,563 (26,607) (77,414) 4,471,963 581,261 136,138 64,558 179,000 15,409 25,797 — — (14,909) 538,578 38,683 31,988 — — (398,557) 5,034,363 (45,885) 563,364 (801,872) (320,117) 27,431 (1,094,558) (629,341) 145,302 (63,079) (25,740) 2,810 (86,009) (26,554) 11,831 18,375 6,183 — — — — 24,558 3,018 — — — — 4,562,283 434,230 141,953 15,563 (26,607) (92,323) 5,035,099 622,962 168,126 64,558 179,000 (444,442) 27,576 5,625,303 (5,760) (3,428) — (870,711) (349,285) 30,241 (9,188) (1,189,755) (3,390) (659,285) — 157,133 (1,578,597) (100,732) (12,578) (1,691,907) Net book value as at December 31, 2014 Net book value as at December 31, 2013 3,455,766 3,377,405 462,632 452,569 14,998 15,370 3,933,396 3,845,344 For the year ended December 31, 2014, Bonavista capitalized $8.5 million (December 31, 2013 - $8.7 million) of direct general and administrative expenses. Bonavista successfully closed on the disposition of non-core properties including, mature heavy oil properties in Northern Alberta and some other minor non-core properties for total proceeds of $289.4 million, resulting in a before tax gain on sale of property, plant and equipment of $61.8 million for the year ended December 31, 2014 (December 31, 2013 - $38.1 million). For the year ended December 31, 2014, Bonavista recorded impairments totaling $300 million (December 31, 2013 - nil) related to its British Columbia, Central Alberta, Southern Alberta and Eastern Alberta CGUs. The impairment included Bonavista's goodwill of $11.2 million recorded in the Central Alberta CGU. The impairments were recorded in depletion, depreciation, amortization and impairment in Bonavista's consolidated statement of income and other comprehensive income. The impairment charge was a result of declining forward commodity prices for oil, natural gas and natural gas liquids as at January 1, 2015 as compared to January 1, 2014, as prepared by Bonavista's independent reserve evaluator. The recoverable amounts determined for each impaired CGU were approximately $200 million for British Columbia, $1.7 billion for Central Alberta, $150 million for Southern Alberta and $90 million for Eastern Alberta. The recoverable amount of the CGUs, with recorded impairment, was estimated based on proved plus probable reserve values using before-tax discount rates specific to the underlying composition of assets residing in each CGU. The discount rates used ranged from 10 - 12 percent. The results of the December 31, 2014 impairment test are sensitive to lower commodity prices, which have been significantly eroded in the latter half of 2014, particularly oil and natural gas liquid prices. Further declines in the economic price environment for oil, natural gas and natural gas liquids could result in additional impairment charges. If a before-tax discount rate of 8 percent had been used to the determination of the recoverable amounts, a $115 million impairment would have been recorded in Bonavista's British Columbia, Southern Alberta, and Eastern Alberta CGUs. If a before-tax discount rate of 12 percent had been used in the determination of the recoverable amounts for Bonavista's non-impaired CGUs, Bonavista would have recorded an additional impairment charge of $40 million to its South Central CGU. The impairment recorded at December 31, 2014 may be reversed at such a time that the fair value of the impaired CGU increases. BONAVISTA ENERGY CORPORATION Page 42 Below are the commodity prices estimates used in Bonavista's December 31, 2014 impairment test: Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Thereafter Edmonton Light Crude Oil (1) (CDN$/bbl) 64.71 80.00 85.71 91.43 97.14 102.86 106.18 108.31 110.47 112.67 2.0%/year WTI Oil (1) (US$/bbl) 62.50 75.00 80.00 85.00 90.00 95.00 98.54 100.51 102.52 104.57 2.0%/year AECO Gas (1) (CDN$/MMBtu) 3.31 3.77 4.02 4.27 4.53 4.78 5.03 5.28 5.53 5.71 2%/year Foreign Exchange Rate (US$/CDN$) 0.850 0.875 0.875 0.875 0.875 0.875 0.875 0.875 0.875 0.875 0.875 (1) Prices represent forecasted amounts as at January 1, 2015 as prepared by Bonavista's independent reserves evaluator, GLJ Petroleum Consultants. 9. Goodwill and Exploration and evaluation assets ($ thousands) Balance as at December 31, 2012 Additions Acquisitions Dispositions Transfers to property, plant and equipment Balance as at December 31, 2013 Additions Acquisitions Dispositions Transfers to property, plant and equipment Impairment Balance as at December 31, 2014 Goodwill Exploration and evaluation assets 11,225 — — — — 11,225 — — — — (11,225) — 217,382 24,825 2,876 (7,435) (15,563) 222,085 29,391 20,887 (18,312) (64,558) — 189,493 Exploration and evaluation assets consist of Bonavista’s exploration projects which are pending the determination of proved or probable reserves and production. Additions represent Bonavista's share of costs incurred on E&E assets during the year. There were no incidents of impairment identified on Bonavista’s exploration and evaluation assets for the years ended December 31, 2014 and December 31, 2013. For the year ended December 31, 2014, Bonavista recorded a goodwill impairment charge of $11.2 million (December 31, 2013 - nil). The goodwill impairment was recorded in Bonavista's Central Alberta CGU. BONAVISTA ENERGY CORPORATION Page 43 10. Business acquisition On July 7, 2014, Bonavista completed the acquisition of certain natural gas weighted assets in the Ansell area within its Deep Basin Core Area. The acquired assets mainly comprise of the vendor's 49% working interest in Bonavista-operated Wilrich play as well as some minor lands in the immediate area. The assets were acquired for cash consideration of $141.1 million. The amounts recognized on the date of acquisition to identifiable net assets were as follows: ($ thousands) Net assets acquired: Exploration and evaluation assets Facilities Oil and natural gas properties Decommissioning liabilities Net assets acquired Purchase consideration: Cash Total purchase consideration Amount 20,448 23,577 97,699 (662) 141,062 141,062 141,062 In the period from July 7, 2014 to December 31, 2014, the acquisition contributed revenues of $5.4 million and net income of $3.0 million, which are included in the consolidated statements of income and comprehensive income for the period ending December 31, 2014. If the acquisition had occurred on January 1, 2014, management estimates that the acquisition would have contributed revenues of $13.1 million and net income of $6.1 million for the year ending December 31, 2014. During the year ended December 31, 2014, Bonavista also completed several natural gas weighted property acquisitions in the Deep Basin and West Central core areas totaling $45.5 million (December 31, 2013 - $16.3 million). 11. Shareholders' equity 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, 2014 were $0.84 per share (December 31, 2013 - $0.84 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. On May 1, 2014, the Board of Directors suspended the DRIP and SDP for the remainder of 2014. The reinstatement of the DRIP and SDP in 2015 and thereafter is at the discretion of the Corporation's Board of Directors. On February 17, 2015, the Board of Directors declared a dividend of $0.035 per common share, payable in cash to shareholders of record on February 27, 2015. The dividend payment date is March 15, 2015. The exchangeable shares of Bonavista are exchangeable into common shares based on the exchange ratio, which is adjusted monthly, to reflect dividends paid on common shares. As a result, cash dividends are not paid on exchangeable shares. The holders of exchangeable shares are entitled to one vote times the exchange ratio for each exchangeable share. BONAVISTA ENERGY CORPORATION Page 44 a. Issued and outstanding Common shares Balance at December 31, 2012 Issue costs, net of future tax benefit Issued on conversion of exchangeable shares Issued pursuant to the dividend reinvestment and stock dividend plans Issued upon exercise of stock options and common shares incentive rights Conversion of incentive and restricted share awards Share-based compensation Balance as at December 31, 2013 Issued for cash Issue costs, net of future tax benefit Issued on conversion of exchangeable shares Issued pursuant to the dividend reinvestment and stock dividend plans Issued upon exercise of stock options and common shares incentive rights Conversion of incentive and restricted share awards, net of future tax Share-based compensation Balance as at December 31, 2014 Exchangeable shares Common Shares (thousands) 177,522 — 4,023 4,562 208 647 — 186,962 12,100 — 1,499 1,748 387 1,064 — Amount ($ thousands) 2,059,305 (74) 97,715 59,162 1,984 — 10,118 2,228,210 200,860 (6,280) 34,568 26,075 4,154 148 26,271 203,760 2,514,006 Year ended December 31, 2014 Year ended December 31, 2013 Exchangeable Shares Amount Exchangeable Shares Amount (thousands) ($ thousands) (thousands) ($ thousands) Balance, beginning of year Exchanged for common shares Balance, end of year Exchange ratio, end of year Common shares issuable on exchange 10,676 (1,200) 9,476 1.28262 12,154 307,468 (34,568) 272,900 — 272,900 14,069 (3,393) 10,676 1.20836 12,900 405,183 (97,715) 307,468 — 307,468 The holders of Bonavista'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 Bonavista'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. BONAVISTA ENERGY CORPORATION Page 45 b. Share-based compensation Bonavista has option and incentive award programs (“long-term incentive plans”) 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. Share-based compensation expense recognized during (December 31, 2013 - $23.9 million). For the year ended December 31, 2014, $2.2 million of share-based compensation expense was capitalized to property, plant and equipment (December 31, 2013 - $2.6 million). As at December 31, 2014, the balance of contributed surplus attributable to share-based compensation awards was $57.6 million (December 31, 2013 - $61.2 million). the year ended December 31, 2014 was $20.4 million Stock option and common share incentive rights plans Upon conversion to a corporation, the stock option plan of Bonavista was established and the common share rights incentive plan (formerly the trust unit rights incentive plan of the Trust) was amended. The amended plan provided that all rights to acquire trust units became rights to acquire common shares. All new rights granted after December 31, 2010 are granted under the stock option plan. Directors, officers, employees and certain consultants of Bonavista are eligible to receive options under the stock option plan. Grants made under the stock option plan vest evenly over a three year period and expire three years after each vesting date, whereas grants made under the amended common share rights incentive plan vest over a four year period and expire two years after each vesting date. Bonavista estimates the fair value of share options granted using a Black-Scholes option pricing model. The following average assumptions were used to arrive at the estimated fair value during each respective period: Weighted average for the year ended December 31, 2014 December 31, 2013 Dividend yield Volatility Risk-free interest rate Forfeiture rate(1) Expected life 5.83% 28.30% 1.40% 9.55% 3.8 6.57% 38.97% 1.64% 8.78% 5.0 (1) The estimated forfeiture rate is adjusted for actual forfeitures throughout the vesting period. The following table summarizes the stock option and common share incentive rights outstanding and exercisable under the plans at December 31: Balance at December 31, 2012 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2013 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2014 Exercisable as at December 31, 2014 Stock Options/Common Share Incentive Rights Weighted Average Exercise Price 6,405,236 1,282,823 (211,140) (678,441) — 6,798,478 2,964,210 (387,010) (1,335,896) — 8,039,782 3,788,001 ($ per share) 20.75 13.84 (9.38) (21.17) (0.26) 19.52 14.74 (10.73) (19.36) (0.14) 18.08 21.30 As at December 31, 2014 there were 7.5 million stock options outstanding (December 31, 2013 - 5.5 million) of which 3.3 million were exercisable (December 31, 2013 - 2.1 million) and 0.5 million common share incentive rights outstanding (December 31, 2013 - 1.3 million) of which 0.5 million were exercisable (December 31, 2013 - 1.1 million). The range of exercise prices of the outstanding stock option and common share incentive rights plans is as follows: BONAVISTA ENERGY CORPORATION Page 46 Range of exercise prices Number outstanding ($ per share) 7.30 - 14.86 14.87 - 16.38 16.39 - 29.13 7.30 - 29.13 2,681,437 2,846,599 2,511,746 8,039,782 Outstanding Weighted average remaining contractual life (years) Exercisable Weighted average exercise price Number exercisable 3.8 3.2 1.5 2.9 ($ per share) 13.58 15.82 25.45 18.08 385,877 1,160,271 2,241,853 3,788,001 Weighted average exercise price ($ per share) 13.49 15.52 25.63 21.30 Incentive and restricted share award incentive plans Bonavista’s incentive and restricted share award incentive plans provide compensation in relation to a notional number of underlying common shares December 31, 2010 and May 2, 2013 were granted under the restricted share award incentive plan. On May 2, 2013 the restricted share award incentive plan was replaced by the incentive award plan. to directors, officers, employees and certain consultants. Awards granted between 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, in the case of incentive awards, cash or equivalent common shares for each incentive award and equivalent common shares for each restricted 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 incentive and 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 expected dividends. This fair value is recognized as share-based compensation expense over the vesting period with a corresponding increase to contributed surplus. Upon the conversion of the restricted share awards or the settlement of the incentive awards by common shares, on the predetermined vesting dates, the value in contributed surplus pertaining to the awards is recorded as shareholders’ capital. The following table summarizes the incentive and restricted share award incentive plans outstanding at December 31: Balance as at December 31, 2012 Granted Reinvestment(1) Exercised Forfeited Balance as at December 31, 2013 Granted Reinvestment(1) Exercised Forfeited Balance as at December 31, 2014 (1) Reinvestment of dividends earned during the period outstanding. Incentive and Restricted Share Awards 1,638,220 1,499,061 101,521 (646,544) (135,173) 2,457,085 1,541,632 164,402 (1,063,636) (337,312) 2,762,171 BONAVISTA ENERGY CORPORATION Page 47 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 Incentive and restricted share awards Diluted equivalent shares 12. Long-term debt ($ thousands) Bank credit facility Senior unsecured notes Long-term debt Long-term debt (current portion) Long-term debt (long-term portion) a. Bank credit facility Year ended December 31, 2014 Year ended December 31, 2013 195,686 13,033 208,719 12 2,226 210,957 181,685 15,611 197,296 125 1,919 199,340 December 31, 2014 December 31, 2013 154,368 885,303 1,039,671 50,000 989,671 229,323 816,854 1,046,177 — 1,046,177 Bonavista has a $600 million, covenant-based bank credit facility provided by a syndicate of 11 domestic and international banks. The current maturity date of the credit facility is September 10, 2018. 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 bank credit facility, Bonavista has provided the covenant 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; (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 shareholder’s equity of the Corporation, in all cases calculated based on a rolling prior four quarters. Bonavista’s consolidated senior debt and consolidated total debt were the same at December 31, 2014, including the Corporation's senior unsecured notes issued under the master shelf agreement, senior unsecured notes not subject to the master shelf agreement and the bank credit facility. Bonavista's consolidated senior debt may differ from total debt in instances when the Corporation issues senior subordinated debt or enters into a significant capital lease obligation or guarantee. b. Senior unsecured notes issued under a master shelf agreement Bonavista entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125 million in notes at a rate equal to the related US treasury rate corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. In 2010, Bonavista drew down US$50 million on the master shelf agreement with a coupon rate of 4.86% with US$25 million maturing on June 4, 2016 and the remaining US$25 million maturing on June 4, 2017. BONAVISTA ENERGY CORPORATION Page 48 Bonavista increased its existing master shelf agreement from US$125 million to US$150 million allowing the Corporation to draw an additional US$100 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 April 25, 2013, the Corporation drew down US$100 million on the master shelf agreement with a coupon rate of 3.80% and a maturity date of April 25, 2025. Under the terms of the master shelf agreement, Bonavista has provided similar significant covenants that exist under the bank credit facility. c. Senior unsecured notes not subject to the master shelf agreement On November 2, 2010, October 25, 2011 and May 23, 2013 Bonavista issued the following senior unsecured notes by way of a private placement. Under the terms of the senior unsecured notes, Bonavista has provided similar significant covenants that exist 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 May 23, 2013 May 23, 2013 May 23, 2013 Principal Coupon Rate CDN $50.0 million US US US US US $90.0 million $160.0 million $50.0 million $150.0 million $85.0 million CDN $20.0 million US $20.0 million 3.79% 3.66% 4.37% 4.47% 4.25% 3.68% 4.09% 3.78% Maturity Dates November 2, 2015 November 2, 2017 November 2, 2020 November 2, 2022 October 25, 2021 May 23, 2023 May 23, 2023 May 23, 2025 As at December 31, 2014, Bonavista was in compliance with all covenants under its credit facilities and senior unsecured notes. 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 $498.0 million as at December 31, 2014 (December 31, 2013 - $406.5 million), based on an estimated total future undiscounted liability of approximately $1.3 billion (December 31, 2013 - $1.4 billion). At December 31, 2014 management estimates expenditures required to settle the liability will be made over the next 54 years with the majority of payments being made in years 2040 to 2064. A risk-free rate of approximately 2.3% (December 31, 2013 - 3.2%) based on the Bank of Canada’s long-term risk- free bond rate and an inflation rate of 2% (December 31, 2013 - 2%) were used to calculate the present value of the decommissioning liability. December 31, 2014 December 31, 2013 ($ thousands) Balance, beginning of year Accretion expense Liabilities incurred Liabilities acquired Liabilities disposed Liabilities settled Change in estimate(1)(2) Balance, end of year Current portion of decommissioning liability Long-term portion of decommissioning liability (1) (2) Relates to changes in estimated costs, discount rates and anticipated settlement dates of decommissioning liabilities. The change in estimate, related to changes in the risk-free discount rate, totaled $145 million. 406,487 10,938 7,587 2,405 (76,409) (32,026) 179,000 497,982 15,185 482,797 447,753 10,566 6,394 13,423 (14,899) (30,143) (26,607) 406,487 9,313 397,174 BONAVISTA ENERGY CORPORATION Page 49 14. Deferred income taxes The provision for income tax differs from the result which would have been obtained by applying the combined Federal and Provincial income tax rates to net income before taxes. The difference results from the following items: ($ thousands) Income before taxes Current statutory income tax rate Income tax expense at current statutory rate Non-taxable portion of capital gain Change in unrealized tax benefits Non-deductible portion of unrealized foreign exchange Non-deductible share-based compensation Goodwill impairment Effect of tax rate changes and rate variance Other Deferred income taxes Year ended December 31, 2014 Year ended December 31, 2013 39,170 25.1% 9,832 — — 17,191 3,860 2,812 (283) 911 34,323 73,548 25.1% 18,461 (2,436) (2,436) 4,845 5,370 — 264 (25) 24,043 The tax rate consists of the combined federal and provincial statutory tax rates for Bonavista for the years ended December 31, 2014 and December 31, 2013. The general combined federal and provincial tax rate decreased slightly in 2014 due to reduced weighting in Saskatchewan as a result of the disposition of our mature non-core heavy oil weighted assets. ($ thousands) Deferred income tax liabilities: Capital assets in excess of tax value Foreign exchange on long-term debt Debt issue costs Financial instrument contracts Deferred income tax assets: Decommissioning liabilities Non-capital losses Other liability Issue costs Financial instrument contracts Share-based compensation Deferred income taxes Year ended December 31, 2014 Year ended December 31, 2013 446,249 — 1,342 38,561 (124,794) (83,295) (3,471) (4,094) — (1,233) 269,265 463,502 (2,151) 1,455 — (101,988) (105,993) (3,786) (4,465) (8,764) (616) 237,194 BONAVISTA ENERGY CORPORATION Page 50 A continuity of the net deferred income tax liability is detailed in the following tables: Balance December 31, 2012 (Asset)/Liability Recognized in profit and loss (Asset)/Liability Recognized in equity (Asset)/Liability Acquired in business combinations (Asset)/Liability Balance December 31, 2013 (Asset)/Liability ($ thousands) Property, plant and equipment Decommissioning liabilities Non-capital losses Partnership deferral Issue costs Other liability Foreign exchange Debt issue costs Financial instrument contracts Marketable securities Share-based compensation ($ thousands) Property, plant and equipment Decommissioning liabilities Non-capital losses Issue costs Other liability Foreign exchange Debt issue costs Financial instrument contracts Share-based compensation 348,848 (112,207) (107,704) 92,306 (8,153) (4,046) 2,694 1,656 (126) (92) — 213,176 113,960 10,913 1,711 (92,306) 3,713 260 (4,845) (201) (8,638) 92 (616) 24,043 — — — — (25) — — — — — — (25) 694 (694) — — — — — — — — — — 463,502 (101,988) (105,993) — (4,465) (3,786) (2,151) 1,455 (8,764) — (616) 237,194 Balance December 31, 2013 (Asset)/Liability Recognized in profit and loss (Asset)/Liability Recognized in equity (Asset)/Liability Acquired in business combinations (Asset)/Liability Balance December 31, 2014 (Asset)/Liability 463,502 (101,988) (105,993) (4,465) (3,786) (2,151) 1,455 (8,764) (616) 237,194 (17,419) (22,640) 22,698 2,475 315 2,151 (113) 47,325 (469) 34,323 — — — (2,104) — — — — (148) (2,252) 166 (166) — — — — — — — — 446,249 (124,794) (83,295) (4,094) (3,471) — 1,342 38,561 (1,233) 269,265 BONAVISTA ENERGY CORPORATION Page 51 The following is a summary of the estimated tax pools: ($ thousands) Canadian oil and gas property expense Canadian development expense Canadian exploration expense Undepreciated capital cost Non-capital losses Other Total December 31, 2014 December 31, 2013 817,360 802,495 295,302 417,556 332,384 16,337 937,202 723,968 149,719 431,025 391,788 17,796 2,681,434 2,651,498 Non-capital losses carry forward of $332.4 million (December 31, 2013 - $391.8 million) expire in the years 2028 through 2034. Bonavista has capital losses of $48.7 million (December 31, 2013 - $48.7 million) available for carry forward against future capital gains indefinitely that is not included in the deferred income tax asset. For the years ended December 31, 2014 and 2013 Bonavista paid no tax installments. 15. Commitments The following table details Bonavista's contractual obligations for long-term debt, lease obligations and other purchase and capital commitments as at December 31, 2014: ($ thousands) Long-term debt repayments(1)(3) Interest payments(2)(3) Office lease(4) Drilling and completions capital(5) Drilling service contracts(6) Transportation expenses Total 2015 2016 2017 2018 2019 and thereafter 1,039,671 227,687 35,263 49,027 30,437 84,206 50,000 35,940 6,068 — 18,623 22,716 29,003 33,709 6,068 49,027 5,907 23,049 133,412 154,368 672,888 31,731 6,068 — 5,907 17,027 27,832 6,356 — — 98,475 10,703 — — 10,083 11,331 Total contractual obligations 1,466,291 133,347 146,763 194,145 198,639 793,397 (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 2018. Fixed interest payments on senior unsecured notes. US dollars payments are converted using the exchange rate of $1.1601 CDN/US dollar. The drilling and completions capital commitment is on fee lands of a partner in Bonavista's West Central Core area, the remaining commitment is to be fulfilled by the end of 2016. The drilling service contracts are with two service providers extending over a three year term. (2) (3) (4) Office lease expires July 31, 2020. (5) (6) BONAVISTA ENERGY CORPORATION Page 52 16. Supplemental disclosure a. Income statement presentation Bonavista's statement of income is prepared primarily by nature of expense, with the exception of employee compensation costs which are included in both the operating and general and administrative expense line items. The following table details the amount of total employee compensation costs included in the operating and general and administrative expense line items in the consolidated statements of income and comprehensive income. ($ thousands) Operating General and administrative Total employee compensation costs b. Compensation of key management personnel Year ended December 31, 2014 Year ended December 31, 2013 12,832 34,221 47,053 7,337 31,125 38,462 Bonavista has determined that its key management personnel includes both officers and directors. Short-term benefits are comprised of salaries and directors fees, annual bonuses and other benefits. In addition, share-based compensation provided to key management personnel includes awards offered under Bonavista’s long-term incentive plans. The following table details remuneration to key management personnel included in general and administrative expenses on the consolidated statements of income and comprehensive income. ($ thousands) Short-term benefits Share-based payments Year ended December 31, 2014 Year ended December 31, 2013 3,756 6,830 10,586 3,513 4,133 7,646 BONAVISTA ENERGY CORPORATION Page 53 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 Caisse Centrale Desjardins Citibank, N.A. (Canadian Branch) 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 Facsimile: (403) 262-5184 Email: investor.relations@bonavistaenergy.com Website: www.bonavistaenergy.com CORPORATE INFORMATION DIRECTORS Keith A. MacPhail, (2)(5) Executive Chairman Jason E. Skehar, (5) President and CEO Ian S. Brown (1)(4) Michael M. Kanovsky (1)(2)(4)(5) Sue Lee (3)(4) Margaret A. McKenzie (1)(3) Robert G. Phillips(4) Ronald J. Poelzer (5) Christopher P. Slubicki (2)(3) (1) Member of the Audit Committee (2) Member of the Reserves Committee (3) Member of the Compensation Committee (4) Member of the Governance and Nominating Committee (5) Member of the Executive Committee OFFICERS Keith A. MacPhail, Executive Chairman Jason E. Skehar, President and CEO Glenn A. Hamilton, Senior Vice President and CFO Bruce W. Jensen, Chief Operating Officer Dean M. Kobelka, Vice President, Finance Magni Lake, Vice President, Marketing Wayne E. Merkel, Vice President, Exploration Colin Ranger, Vice President, Production 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 or Glenn A. Hamilton Senior Vice President and CFO 

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